IR 05000293/1987027
| ML20238E968 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 09/03/1987 |
| From: | Wiggins J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20238E936 | List: |
| References | |
| 50-293-87-27, IEIN-87-030, IEIN-87-30, NUDOCS 8709150314 | |
| Download: ML20238E968 (28) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No.: 50-293/87-27 Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: June 23 - August 3, 1987 Inspectors: M. McBride, Senior Resident Inspector J. Lyash, Resident Inspection 'm, Resident Inspector Approved By: 1)Reiv h9it6 7 J.Wipins,ChiefQReactorProjects Sec ion 18, [MP Areas Inspected: Routine resident inspection of plant operations, radiation protection, physical security, plant events, maintenance, surveillance, outage activities, and reports to the NR The inspection consisted of 414 hours0.00479 days <br />0.115 hours <br />6.845238e-4 weeks <br />1.57527e-4 months <br /> of direct inspectio !
Results: No violations were identifie The inspectors made the following I observations: I l
Concerns 1 A change to the core spray system injection valve stroke time implemented in accordance with 10 CFR 50.59 was not reported to the NRC as require In addition proper FSAR changes were not processed. (Unresolved Item
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87-27-01, Section 2.0) i The valve motor operator maintenance program appears weak in severci areas. Similar concerns were raised during NRC team inspection 50-293/ l 85-30, but have not been fully resolve (Unresolved Item 87-27-05, !
Section 3.a) I Two security events occurred during the period involving degradation of vital area barriers. An unrelated security weakness was identified in the site access program. Licensee response to the latter problem was slo (Section 3.c)
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inspection Summary (Continued) 2 A potential _ violation of employee radiation exposure reporting require-ments was identified' and will be evaluated by specialist inspectors at a later date. (Unresolved Item 87-27-07, Section 3.d) The inspectors questioned the wisdom of running the "B" diesel generator prior to the identification of a root cause for insulation fires on the
"A" diesel generator exhaust heade (Section 4.a)
Follow Items ; As-found pickup voltages for HFA relays being tested during this outage have been outside the allowable range. This may impact relay operabilit (Inspector Follow Item 87-27-03, Section 3.a) Cracks were identified in ECCS pump motor winding felt block The licensee's inspections in response to this, and IEN 87-30 will be reviewe (Inspector Follow Item 87-27-02, Section 2.0) Unexpected leakage from the scram discharge volume resulted from improper installation of two system flange (Inspector Follow Item 87-27-04, Section 2.0) The inspectors will review the licensee's evaluation of potential problems with emergency diesel generator room ventilation performance. (Inspector Follow Item 87-27-06, Section 3.b)
Strengths l' . Evaluation and corrective actions in res3onse to salt service water cor-rosion and control rod drive HCU bolting problems were thorough and ap-peared to have addressed root cause (Section 3.a) The licensee's radiation protection group provided effective assistance to an individual contaminated with promethiu (Section 4.e)
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TABLE OF CONTENTS
Page . ' S umma ry o f Fa c i l i ty Ac ti v i t i e s . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Followup on Previous Inspection Findings . . . . . . . . . . . . . . . . . 2
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Violations, Unresolved Items, Inspector Follow I Items, IE Information Notice 87-30 Routine Periodic Inspections ..... ....................... 5 ' Plant Maintenanc e and Outage Activities
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' Surveillance Testing : Physical Security l Radiation Protection l Review of Plant Events .................................... 17 l
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' Insulation Fire on the Emergency Diesel Generator Spurious Manual Initiation of the Emergency Diesel Generator Dry Chemical Fire Suppression System Spurious Reactor Protection System Actuations Contractor Employee Found Positive on Drug Screening Contractor Employee Contaminated with Promethium Review of Licensee Event Reports ( LERs) . . . . . . . . . . . . . . . . . . 22 Meetings ....... ......................................... 23
' Attachment I - Persons Contacted
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DETAILS 1.0- Summary of Facility Activities j The plant was shutdown on April 12, 1986 for unscheduled maintenance. On July 25,1986, Boston Edison announced that the outage would be extended to include refueling and completion of certain modification {
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Refueling activities were originally scheduled to begin on July 25, 1987 however this milestone was. subsequently postponed. A firm date had not l been established by the close of the inspection perio During the period the licensee replaced the Radiological Protection Section Hea On July 28 three senior managers from Northeast-Nuclear j Energy Company arrived onsite. This was the first in a series of planned j visits whose purpose is to provide an independent review of Pilgrim's .j readiness for restart to Boston Edison senior managemen .0 Followup on Previous Inspection Findings Violations
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(Closed) Violation (87-03-01), failure to take adequate corrective action and failure to submit a required report to the NRC. Between October 1986 and January 1987, portions of the required fire suppression water system equipment were inoperable and no report was submitted to the Commission as required by station Technical Specification 3.1 In addition, no plans or procedures to provide for loss of redundancy in the system had been implemented. The inspector reviewed the following licensee correc-tive actions; 1) a status board, maintained by the fire protection group, has been placed in the control room to enhance operations staff cognizance of fire protection equipment operational status, 2) procedure 1.5.3,
" Maintenance Requests", has been revised to explicitly require a review of the planned maintenance for applicable technical specification LC0's, 3) to improve the operations staff level of knowledge of fire protection system technical specifications, a memo on the subject was issued as required reading and 4) existing procedure 2.4.54 was revised to give specific directions to restore fire protection system redundancy in case one fire pump or water supply was inoperable. The inspector determined that these corrective actions are consistent with the licensee response to the violation as documented in a letter dated April 29, 1987. The inspec-tor had no further question !
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(Update) Violation (87-16-01), failure to properly implement fire protec-tion system surveillance procedure The inspector reviewed the licen-see's written response to the notice of violation. The response did not clearly indicate the licensee's evaluation of the violation's root caus Several of the items listed by the licensee as corrective actions had been performed prior to the date of the violation, and were therefore not cor-rective action The inspector also noted that the licensee had taken additional corrective action, which was observed by the inspector but had not been included in the response lette In general, the response ap-peared adequate, .however the above weaknesses were discussed with licensee management for consideration during preparation of future responses. This item remains open pending verification of the implementation of the licensee's corrective action Unresolved Items (Closed) Unresolved Item (85-30-02), review revised procedure 5.3.21, and the licensee method of validating procedures referenced by the E0Ps. Dur-ing team inspection 50-293/85-30 several errors were identified in licen-see procedure 5.3.21, Bypassing of Selected Interlocks and Isolation Signals, and Inhibit of Auto ADS. Procedure 5.3.21 is utilized in con-junction with the licensee's Emergency Operating Procedures (EOP). Based on the presence of the errors, the team questioned the adequacy of the E0P implementation process. In response the licensee reviewed proce6;re 5.3.21, correcting all identified errors. The inspector reviewed the revised procedure and verified that the discrepancies identified during ,
inspection 50-293/85-30 had been corrected. Additional portions of pro-
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cedure 5.3.21 and other procedures referenced by the E0Ps were reviewed for technical adequac No significant discrepancies were identifie The licensee is upgrading the existing E0Ps to revision 4 of the BWR Owners Group Emergency Procedures Guidelines. During the E0P upgrade pro-gram the licensee has committed to verify, validate and upgrade all cor-responding satellite procedure This commitment is documented in the licensee's written response to inspection 50-293/85-30, and has been stated during several management meeting The inspector reviewed draf t procedure 1.3.4-15, Verification and Validation Program for E0P Support Procedure This procedure includes a list of all satellite procedures referenced by the new E0Ps, and a checklist to be used during the verifi-cation / validation process. This draft procedure is scheduled for sub-mission to the Operations Review Committee in the near future and will be implemented prior to restar Based on correction of the previously identified discrepancies, and the established scope of the licensee's E0P l upgrade program, this item is closed.
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- (Closed); Unresolved Item -(85-30-06), review the ; implication' of, apparent-
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' failure .to ' provide' an adequate'. surveillance procedure for the core spray j pump start timer. This item was reviewed _by the inspector and documented 1 inHNRC inspection report 50-293/85-31, paragraph 4.B(4). At that _ time 1 appropriate procedural revisions had been made;to clarify testing require- ]
ments,L and this concern was considered resolved. . Based on the above,'and verification, by . the inspector that L this testing- remains- in place, this item is close '(Closed) Un_ resolved Item (86-01-06)',. review the licensee's evaluation sup-porting a new core spray valve c Ssure time and the licensee's response to
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the RHR system pressurization events. The licensee experienced continuing problems with leakage past the check valve and motor operated containment isolation valves in the _ Low Pressure Coolant. Injection (LPCI) line. ' This leakage resulted in~ recurring RHR system high pressure alarm The'-
reactor was shutdown due to this problem and 'its potential impact' on con-tainment integrity ' in April, 1986. -The RHR leakage and other equipment problems.' experiencedduring the. shutdown prompted the dispatch of. an NRC Augmented Inspection: Team (AIT). This AIT evaluated the RHR leakage
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- problem and established NRC open item 50-293/87-17-04.- . The implementation -
of e stat)1i shed licensee commitments _ in response. to the pressurization-events will be evaluated under that existing ite ;q The inspector also questioned the licensee's evaluation ' supporting a new core s' pray injection . valve stroke time. The opening stroke _ time of. core spray injection valve MO-1400-25 .was lengthened from 18. to 20 second Safety evaluation (SE).1914 documents the licensee's review and acceptance ;
of this change . as _ requ ad by 10 CFR _50.59. The SE and referenced l engineering ' calculations appear to support the licensee's conclusion that .
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the slightly longer stroke- time does not impact the time dependent. core spray flow rate assumptions made in the facility accident analysis. The inspector noted that section 7.4.3.4.4 of the Final Safety Analysis Report .i (FSAR) was not properly revised in that .it still reflected the 18 second stroke time. In addition the licensee's 1986' annual report of changes made to the facility under 10 CFR 50.59, which was submitted to the NRC on y July 20,.1987, did not include a description of the above chang The inspector brought these concerns to the. attention of licensee management .
and asked whether other safety evaluations could have the same proble This item is considered unresolved pending the licensee's response -
(87-27-01). .l Inspector Follow Items
_(Closed) Inspector Follow Item (87-18-01), review licensee's 10 CFR Part 21 report and the proposed corrective actions regarding loose and missing hold down bolts on the hydraulic control unit Details of the inspec-tor's review of this item is documented in the section 3.a of this report, i
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(Update) Inspector Follow Item (86-14-05), review the licensee's evalua-tion of the loss of 480 VAC load center B-10. Performance problems 'with the time delay trips for the bus B10 feeder breaker were identified. Dur-ing the current outage the licensee is overhauling all safety related-breakers of this typ As-found data accumulated during this process indicates that a significant percentage of the trip devices are out of specification. In excess of twenty Failure and Malfunction Reports have been initiated. The inspector discussed this observation with the licen-see Maintenance Section Head and was informed that an investigation was already being conducted and that a report discussing the conclusions would be issued. The inspector will evaluate the licensee's findings during a future inspectio (Update) Inspector Follow Item (86-34-01), review the licensee's correc-tive action in response to salt- service water piping corrosio The inspector's review of the licensee's investigation and corrective main-tenance on the salt service water pipe corrosion problem during this inspection period is documented in section 3.a of this repor IE Information Notice 87-30 On July 2, 1987, IE Information Notice 87-30, " Cracking of Surge Ring Brackets in large GE Motors", was issued. The purpose of the notice was to alert rec!pients of a potential for failure of surge ring brackets %nd cracking of felt blocks in large, vertical electric motors manufactured by General Electric C Following an investigation to determine the applicability of the subject notice to the Pilgrim Station, the licensee found that RHR, core spray, and recirculation pump motors were potentially affected. RHR and core spray pump motors were ove rhauled on site by GE under a contract with the licensee in 1986. The surge ring brackets were not inspected during the overhau However, small cracks were found on '
the ' A' RHR pump motor winding felt blocks. The inspector reviewed open Failure and Malfunction Report (F&MR)86-302, dated October 3, 1986, describing the small cracks on the felt block The licensee engineering department is still in the process of determining the root cause, signifi-cance, and corrective actions in response to this F&M The licensee has also brought in GE motor specialists to inspect the integrity of the surge ring brackets. These inspections are scheduled for early August, 1987. The completion of licensee engineering evaluation of felt block cracks and the results of surge ring bracket inspection will be reviewed during a future inspection (87-27-02).
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3.0 Routine periodic Inspections i The inspectors routinely toured the facility during normal and backshift j hours to assess general plant and equipment conditions, housekeeping, and I adherence to fire protection, security and radiological control measure .
Inspections were conducted between midnight and six a.m. on June 29, 1987 L for one hour'and July 17, 1987 for three hours and weekends on July 26, 1987 for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and August 1,1987 for two hours. Ongoing work activ-ities were monitored to verify that they were being conducted in accord-ance with -approved administrative and technical procedures, ' and that proper communications with the control room staff had been establishe The inspector observed valve, instrument and electrical equipment lineups in the field to ensure that they were consistent with system operability requirements and operating procedure During tours of the control room the' inspectors verified proper staffing, access control and operator attentiveness. Adherence to procedures and >
limiting conditions for operations were evaluate The inspectors examined equipment lineup and operability, instrument traces and status j of control room annunciators. Various control room logs and other avail- '
able licensee documentation were reviewe The inspector observed and reviewed outage, maintenance and problem inves-tigation activities to veri fy compliance with regulations, procedures, !
codes and standard Involvement of QA/AC, safety tag use, personnel l qualifications, fire protection precautions, retest requirements, and i deportability were assesse The inspector observed tests to verify performance in accordance with approved procedures and LCO's, collection of valid tess results, removal and restoration of equipment, and deficiency review and resolutio Radiological controls were observed on a routine basis.during the report-ing perio 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 sur-veys of nonradiological points throughout the facility were taken by the inspecto Checks were made to determine whechnr 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 .
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L Plant Maintenance and Outage Activities General Electric HFA Relay Repairs j An allegation was received by the resident office on June 27, 1987, regarding the control of ongoing HFA relay testing. The alleger was concerned primarily' with a pen and ink modification made to a flow chart being used during testing of General Electric (GE) HFA relay The alleger also expressed some concern that the flow chart could be
'used to alter existing procedures. In response to the allegation, a general review of ongoing GE HFA relay maintenance was performe The licensee, in conjunction with GE, is currently removing all-safety related HFA relays and replacing their potentially defective
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l armature plate The relays are removed from the field by- the licensee, tested to establish as-found data, and transferred to General Electric for armature plate . replacemen Subsequently the relays are transferred back to the licensee for receipt inspection testing, and reinstallation. Approval for isolation and removal of each relay is processed under a separate station maintenance request (MR). A copy of a flow chart is attached to each MR and summarizes the process to be followed by the licensee during portions of this
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projec It references an existing approved station procedure for routine HFA relay preventive and corrective maintenanc The flow chart instructs test and maintenance personnel to delete, limit the'
scope, and reorder certain steps in- implementing the procedure to facilitate and tailor its use during the current circumstance Typical tests performed under this guidance are contact configura-tion, contact gap and wipe, pickup voltage and impedance measurement, and general physical condition inspection. The procedure referenced
, by the flow chart contains guidance allowing steps to be performed in j part and in any order as directed by. the maintenance engineer. The flow chart is. intended to provide this directio It therefore ap-pears acceptable under the licensee's current program to use this approach provided the intent of steps is not altere A detailed review of the chart and procedure did not identify any technical concerns. Those steos deleted or limited in scope did not
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i appear to impact the validity of the testing. They were primarily included in the procedure to cellect data which was not needed in !
this ~ specialized cas The reordering of steps was prescribed for more efficient test conduct during this project. This reordering did not appear to affect test validity. The steps added in red pen at the bottom of the chart were included by the cognizant engineer and serve only to collect additional test data which might be useful but was not required. Test personnel utilizing the flow chart and pro-cedure to perform the relay testing were observed and appeared knowledgeable and comfortable with the available guidance. No prob-lems were identifie .,
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The practice of allowing maintenance procedure steps to be performed in any order or deleted at the discretion of the maintenance 'engi-n ee r ,- although acceptable here, would . not - be appropriate in all case It is possible that, unless careful consideration is given in each case, problems could result. At the same time this flexibility is necessary in some cases due to the difficulties inherent ' in developing prescriptive maintenance procedure In this instance it does not appear that any technical concern resulted, although a clearer temporary procedure could have been develope The inspec-tor discussed this concern with BECo. management during the exit interview. This practice will be monitored during future inspection In summary, the alleger accurately characterized the methods being -
used to control the testing of HFA relay However, based on a review of this matter, the inspectors concluded that the methods were adequate and were within the guidance of existing plant control procedure During testing of the HFA relays. the licensee identified ' that the as-found pickup voltages of some installed relays were outside the-voltage range recommended in GE Service Information Letter (SIL) 44, Supplement 4, Revision . 2. These relays were installed and. tested
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during 1984. In response GE evaluated the discrepancies On July 1,1987 the licensee received Supplement 5 to S1L.44 describing the GE findings. The supplement advised that the pickup voltage of DC HFA relays is temperature sensitiv The pickup voltage setpoint must be compensated if the relay coil temperature deviates from 25 degrees Centigrade. A formula for use. in applying this compensation was included. Supplement 5 also states that AC relay pickup voltage f is independent of coil temperature and therefore requires no compensatio SIL 44, Supplement 5 states that it is important to maintain relay pickup voltage within the recommended range so that relays will
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operate under adverse conditions. The purpose of the upper limit for '
pickup voltage is to assure that the relay will energize under low bus voltage conditions. Relay pickup voltage below the lower limit of the recommended range indicates low spring tension which may allow normally closed contacts to chatter in a de-energized relay during a seismic event. It also states that GE does not expect contact
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chatter to cause a safety problem for protection systems such as the Reactor Protection System and containment isolation because in both .
of these types of systems, the normally closed contacts do not per-form essential function i
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- .. 8 Data collected by the licensee indicates that a significant- percent-l age of HFA relays installed last outage exhibit as-found pickup volt- l l age values lower than the acceptable range even when the temperature compensation is applied. Contrary to the statements made in SIL 44, supplement . 5, Pilgrim does use normally closed contacts for some safety related applications. Low pickup voltage in these cases may result in unacceptable result It is not clear if the relays were improperly set up during 1984 or if they subsequently drifted out of tolerance. The licensee's maintenance staff initiated a Failure and Malfunction Report and an Engineering Service Request to evaluate j this proble The ' inspector will follow up on the results of this '
evaluation (87-27-03).
Salt Service Water Pipe Inspection and Repair Update In October 1986, salt service water (SSW) piping inspections conduc-ted by the licensee revealed delaminated and missing pipe lining, and below minimum wall corrosion wastage on portions of the SSW pipin The root cause analysis indicated that erosion and delamination of the pipe lining material occurred, followed by aggressive galvanic
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meeting report 50-293/86-41 dated December 31, 198 The licensee
. has established an inspection program to evaluate the scope of the problem and to develop a repair pla As reported in Inspection Report 50-293/87-26, the following is the list of piping inspections performed by the licensee and failures noted to date:
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UT examinations on the accessible portions of the above ground piping: J
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1) 1 spool piece on the A loop in the auxiliary bay failed due j to visual leakag The spool piece was patched, returned l to service and UT monitore j
2) 2 spool pieces on the 8 loop in the auxiliary bay were UT j
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rejected and replaced due to pipe wall thinnin ) 2 spool pieces on the crosstie in the screenhouse were UT rejected due to pipe wall thinning. A complete UT examina-tion has not been completed on these pipes, 4) The screenhouse wall penetration spool piece on the B loop l
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was UT rejected due to less than minimum pipe wall thick- !
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Hydrostatic pressure testing of the underground piping: -)
i 1 ) -- Undetermined leakage source of approximately 7 gallons per - 1 minute was detected on the B loop piping at the test pressure of 110 psi {
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2) .No leakage detected on the A . loop underground pipin Visual remote camera inspection of the underground piping:
1) A rust nodule with missing lining was noted on the elbow (B loop) between auxiliary bay and the screenhous ) A rust nodule with missing lining was noted on the screen-house wall penetration spoolpiece flange (B loop).
3) No indications were detected on the A loop underground pipin The licensee subsequently excavated 'B' loop underground piping and a portion of the ' A' loop underground piping near the screen house for a further inspectio ~UT, examinations on a portion of the ' A' loop underground pip;ng had no indication Visual . inspection of the excavated 'B' loop underground piping resulted in the following indications:
1) I spool piece penetrating the screenSouse wall ~ failed due
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to visual leakag The spool piece was replaced. A rust nodule with missing lining was noted on the piping upstream of the failed spool piec The piping was relined and returned to servic ) I spool piece just outside the auxiliary bay failed due to visual leakage. The affected portion of the spool piece was cut out, flanged and replace Subsequent hydrostatic pressure testing of the 'B' loop under ground piping at the test pressure of 110 psig had no detected leakage, l
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The licensee is currently'in the process of backfilling the excavated portions of underground piping. The licensee informed the inspector that the licensee engineering department is developing inspection criteria for further routine inspection of the SSW piping as one of the long term corrective action On July 30, 1987 the inspector discussed with the licensee representatives the deportability of the observed failures on the SSW system piping. The licensee indicated that the operability of the SSW system based on the observed failures and the possibility of catastrophic failure of the system will be evaluate Inspector followup of the root cause and operability determination will be conducted under existing open item 50-293/
86-34-0 Control Rod Drive Hydraulic Control Unit Seismic Qualification On October 22, 1986, the licensee received written notification from General Electric (GE) of improper hydraulic control unit (HCU)
installation at a BWR. The notification stated that the hold down bolts for many HCU frames were either missing or did not appear to be tightened sufficientl GE investigation identified that torgi e values specified for the bolts differed from the values used during seismic qualification testin .
Subsequent to this notification, the licensee initiated a plant specific evaluation of the HCU hold down bolt Deficiencies were identified involving both loose and missing bolts in the HCU support frames. It was determined that 31 of 145 HCUs were affected. Al so ,
the installation drawing (MID 11-3) specified thst the base bolts were to be installed with both flat washers and lock washers. How-ever, it was found that the base bolts were installed with lock washers only. The details of the identified discrepancies including location and as-found condition of each HCU are listed in LER 87-0 The licensee determined that these deficiencies could impair the ability of the support frames to withstand a safe shutdown earthquake (SSE). The HCUs were declared inoperable and the NRC was notified via ENS on May 8, 1987. Following completion of the 10 CFR Part 21 evaluation, the licensee notified the NRC Region I by telephone on May 29, 1987, and submitted a written report on May 30, 198 A licensee event report (LER 87-06) was also submitted to the NRC on June 4, 1987, providing the background information and proposed corrective action Sufficient data is not available to determine whether these defici-encies occurred during the initial installation, during maintenance and overhaul, or during plant operation. However, it was discovered that the left front hold down bolt for HCU frame 26-51 was installed without any concrete anchoring device. Further invest % tion by the licensee indicated that a piece of rebar was located apr.oximately 2-1/2 inches below the concrete pad surface in the hole. The bolt
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was. supposed to be attached to the unistrut below the surface of the )
concrete. This indicated that at least the deficiency involving the 1 left front hold down bolt for HCU frame 26-51 occurred during the -l initial installatio I Also, the most probable' cause for the missing flat washers appeared ,
to be improper installation during the original plant constructio I The hydraulic control units were installed by Reactor Controls Inc., I under contract to Bechtel Power Corp., to a specification written by I the General Electric Compan The licensee has generated Failure and Malfunction Reports87-182 and 87-407, and Potennial Condition Adverse to Quality (PCAQ) Report PCAQ 87-16 to address the root cause and corrective actions. Since the specific root cause could not be established, the licensee decided to l restore the HCus ta original design condition and inspect the hold ,
down bolts under a preventive maintenance program. To return all HCU frames to original design condition', the following activities were completed during this aspection period by the licensee in accordance with the directions prov ided in PCAQ 87-16 and Maintenance Request 87-3-46:
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New "unistrut" holdown bolts, flat washers, and lock washers were installed at each of the HCU hold down points (4 per uCU frame) in accordance with the G.E. specification (installation drawing MID 11-3). All hold down bolts were torqued to 50 ft-lb New bolts and flat washers were installed on the upper flanges of each HCU frames with missing bolts. All upper flange bolts were torqued to 19 ft-lb FRN 87-37-01 and FRN 87-37-04 were issued by the licensee engineering department to provide a method of anchoring the left front hold down bolt for HCU frame 26-51. The method provided i included cutting one rebar to allow installation of anchor bolt and using a 5/8 inch diameter HILTI KWIK BOLT with a 3-1/2 inch minimum embedmen The licensee's technical justification to anchor the left front HCU frame 26-51 using a 5/8 inch diameter d HILTI KWIK BOLT is based on an engineering calculation which indicated that the capacity of HILTI BOLT exceeds capacity required for anchorage of HCU fram The inspector reviewed the completed MR 87-3-46 package including the appropriate FRNs, QC inspector reports, and had no further question { 4
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L* 12 During the installation of new bolts on the upper flanges of HCU frames with missing bolts, it was found that existing bolt holes on some of the flanges do not align. This prevented installation of the 3/8 inch diameter bolts in the - tapped holes. The licensee engineer- -
ing department issued a Field Revision Notice (FRN 87-37-07) to pro-vide an equivalent bolting ar.angemen In accordance with FRN 87-37-07, new 7/16 inch diameter holes were drilled adjacent to the misa11gned holes, and 3/8 inch diameter bolts were fastened with nut This revised bolting arrangement applied to the following HCb frames: 1 HCU 18-51 bolted to HCU 18-47 (2 bolts)
HCU 22-51 bolted to HCU 22-47 (1 bolt)
HCU 18-31 bolted to HCU 22-31 (1 bolt)
HCU 46-43 bolted to HCU 38-51 (1 bolt)
HCU 38-39 bolted to HCU 46-31 (1 bolt)
The licensee's technical justification for the revised bolting arrangement stated that the same size and type of bolts are bei used and the new holes have been located in conformance with AISC requirements for center to center spacing and minimum edge distanc Thus, the revised bol ting arrangement has the same ' structural
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capacity as the original conditio ,
The inspector had'no further question Inadvertent Water Leakage from the Scram Discharge Voltge On July 24, 1987, a manual' reactor scram signal was initiated and the control rod drive scram air header was isolated to replace the air block valve (V-116) to the scram valves for HCU 38-07. Approximately five minutes after the scram signal was initiated, water leakage through the hydrolaze connection blind flanges on the west scram discharge volume headers was observed on elevation 23'. The scram discharge volume header was pressurized with a static head of water from the reactor vessel. Both CRD pumps were out of service for maintenance at the time. The control room operators reset the scram signal to prevent further leakage. It was estimated that about 150 gallons of water leaked onto the reactor building floor. The licen-see immediately restricted personnel access through the affected area and dried the area. The area survey conducted by the licensee indi-cated less than 1000 dpm/cm !
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The licensee initiated Failure and Malfunction Report (F&MR)87-343 to investigate and fix the leaking flanges. The licensee's initial root cause analysis indicated that the blank flanges were improperly installed following hydrolazing of the scram discharge volume header performed in 1986. The licensee plans to inspect the east scram discharge volume header flanges for similar problems. The inspector will review licensee corrective actions and disposition of the' F&MR 87-450 in a future inspection (87-27-04).
Motor Operated Valve Preventive and Corrective Maintenance The licensee is performing an extensive motor operated valve (MOV)
preventive maintenance and overhaul program during the current out-age. The inspector performed a sampling review of applicable pro-cedures, ongoing work and test activities, and completed work pack-age Many of the procedures controlling the program are newly developed and are being -implemented for the first time. Individuals observed and interviewed by the inspector appeared knowledgeable and well trained. During the inspector's review several areas of concern were identifie Control of MOV torque switen and limit switch settings appears
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to be wea Torque switch settings for use in the field are obtained from uncontrolled copies of the original valve operator bill of materials (BOM) kept in the maintenance shop. In some cases design changes and new torque switch settings were de-scribed on handwritten sheets included in the book. The inspec-tor questioned the reliability of this control matho Since the BOM is not a controlled document, design changes nay not result in updating of the appropriate settings. During review of eight completed work packages the inspector noted three valve operators (MOV 1001-47, 1301-60, 202-5A) with as-found torque J
switch settings outside the range specified on the 80 '
This may indicate that the values prescribed on the BOM are not con-sistently applied. The licensee stated that a set of controlled drawings, specifying torque switch settings were being develope )
l The inspector also noted that certain valves are not torque j seated but instead are deenergized in the closed direction by j a limit switc For example, the reactor recirculation pump discharge valves close on a low pressure coolant injection signal. The valve ceases to drive closed when the closed limit 1
switch trips, not when valve seating is sensed by the torque switc Although the ability of the valve to close is deter-mined by the closed limit switch no record of the required design setting was available. The licensee stated that the need to establish these settings had been identified, and an i
Engineering Service Request written to develop the .
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The licensee's method of setting the torque switch bypass switch requires further evaluatio For sealed-in gate and globe valves the licensee has elected to set the torque switch bypass switch at twanty parcent of the valve stroke in the open direc-tio The limit switch contacts which drive the control room position indicating lights and other position functions are located on the same limit switch rotor. Valves would therefore indicate full closed with the valve still twenty percent ope This will affect the validity of valve stroke timing which is performed using control room indication, knowledge of actual valve position, and may affect interlocks based on valve positio For valves which do not seal-in, such as throttle valves, the i licensee has elected to set the torque switch bypass switch at two to five percent. Certain throttle va'lves receive an auto-matic open signal during accident condition The inspector questioned the adequacy of this setting under accident condi-tions with a differential pressure acting across the valve.
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The inspector questioned the adequacy of certain portions of the MOV checkout and adjustment procedure, 3.M.3-24.5. This pro- ;
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cedure instructs personnel to set the open limit switch with the '
va3ve resting on the backsea In the field the inspesor observed that the open limit switch was actually being set with the valve one-and-one-half stem nut turns off the backseat to j allow for valve coasting. Instructions for this operation were not included in the procedure and the inspector questioned the basis for application of this method to all valve operator No procedure steps were included to verify '. hat this !.etting was adequate to prevent the valve from coasting into the backsea Test personnel stated that a clamp-on ammeter installed at the breaker was observed for sudden current increases during valve opening, as a sign of the valve contacting the backsea The inspector pointed out that these instructions were also not in the procedure, and would not be effective in identifying a valve which was coasting into the backseat because the motor contactor would already have dropped ou Attachment D of procedure 3.M.3-24.5 includes steps to test the functioning of the open torque switch for valves which are nor-i mally deenergized by a limit switch contact in the open direc-tien. This test is designed to verify that the torque switch would function to deenergize the circuit if the limit switch l fails to properly operat Test personnel are instructed to I
place a jumper across the appropriate open limit switch con-l tacts, to electrically drive the valve open and verify that the l torque switch trips. The inspector questioned the need for this
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at Pilgrim are typically set the same in both the open and close l
direction. Torquing the valve open on the much smaller valve q backseat area could cause damage and should be avoided. In -
addition some valves have had the open torque switch contacts permanently bypassed. In this case driving the valve open with
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the open limit switch jumpered could result in motor or valve failur While observing post work setup and testing of MOV-1001-43D on July 20, 1987 the inspector noted that the torque switch ap-peared to be unbalance This condition was brought to the attention of the supervisor at the job sit The supervisor contacted the cognizant engineer, and correctly balanced the switch. The method used to balance the switch appeared consis-tent with standard practices, however no steps for inspection or balancing of the torque switch were included in the procedur The inspector reviewed completed work packages for eight valve operator Due to limited maintenance department engineering resources the licensee's review and approval of these packages had not been completed, Two of the packages, for MOV-1400-25 and MOV-1201-5, characterized the as-found condition of the spring pack as ' packed with grease' . Excessive grease in-an operator spring pack can result in failure of the valve to function due . to operator hydraulic loc The inspector ques-tioned the cause and scope of this proble The packages for MOV-1001-7C and MOV-1201-5 identified that the
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operator motor leads were improperly spliced using standard butt splices instead of Raychem splices. These valves are considered environmentally qualified (EQ). The inspector questioned the acceptability of the as-found splices and their impact on the valve operator EQ statu These items indicate that motor operated valve settings and the methods used to obtain these settings are poorly controlled and may not have been adequately evaluated by the licensee before implemen-tation. In addition, it appears that procedures utilized for these activities are wea Individuals implementing this testing in the field do not adhere to the written guidance but instead rely on verbal direction and previous practice to supplement and correct the procedure This condition was previously identified by the NRC during inspection 50-293/85-30, and is the subject of existing open item 85-30-01. The concerns listed above were discussed with licen-see maintenance management. The licensee committed to evaluate the items specifically and as they apply generically. The acceptability of the licensee's program in these areas will remain unresolved pending review of the licensee's evaluation (87-27-05).
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16 Surveillance Testing During the period the inspector reviewed IE Information Notice 87-09, Emergency Diesel Generator Room Cooling Design Deficiency. This notice describes a single failure which could result in degradation of the Emergency Diesel Generators (EDG) due to a loss of ventila-tio The inspector examined results of monthly EDG surveillance testing and noted that significant increases in ambient room tempera-ture, jacket cooling water temperature and lube uil temperatures were evident during tests conducted coincident with high outside air temperatur These temperatures continued to rise through the con-clusion of the monthly two hour EDG runs. The inspector questioned the ability of the current room ventilation system to perform its function during extended runs with elevated outside air temperatures, or in the event of equipment failures. When questioned, the licen-see's system engineering group was aware of this potential problem
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and had initiated followu Preliminary data had been compiled dur-l ing routine EDG testing with both normal and abnormal ventilation
! configurations. The licensee stated that an Engineering Service Request had been drafted and would be issued to perform more indepth evaluations. The inspector will evaluate the licensee's findings during a future inspection (87-27-06).
. Physical Security
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During the period the inspector identified that the licensee had not established adequate controls to ensure that security access would be suspended in a timely manner for persons whose employ-ment was terminated for cause. Licensee security is not rou-tinely nctified when contractor employees are terminated until a substantial period of time has elapsed. On several ocassions contract employees have been terminated for cause, rehired by a second contractor, and regained site access without licensee evaluation, On July 24, 1987, the inspector brought this concern to the attention of the licensee's Security Group Leader and his direct supervisor, the Senior Vice President-Nuclea As immediate corrective action the licensee issued on July 24, 1987, a memor-andum under the signature of the Senior VP directing contractors to immediately notify licensee security of any terminations. An audit of all existing security badges to verify employment of individuals and security status was conducte The licensee stated that a policy requiring evaluation of any individual terminated prior to his return to site would be issue The licensee also committed to issue, through the Operations Review
- Committee (ORC), a station procedure establishing a system to l ensure proper termination practices by July 29, 198 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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-The licensee issued procedure 1.3.57, Contractor / Vendor Screen-ing Conformance Process, and 1.3.60, Access Authorization Pro- )
cess, on July 30, 1987. These two procedures were reviewed and l approved by the station Operations Review Committee (ORC), and j establish the requirements of the site access control progra Included are specific instructions regarding employee termina-
' tion notification I The lack of a strong process to control the access of indi-viduals upon termination was previously identified by the licen-see. Steps. had been taken to develop a coordinated site access control program, resulting in development of the station pro- 4 cedures described above. However, no effective action was taken f '
to resolve the already-identified weakness in the interim. This was discussed with licensee management during the inspectors'
exit interview, i Radiation Protection '
On July 24, 1987, an allegation was received at the NRC: Region I offices by a radiation protection specialist inspector. The alleger stated that he had not received a report of his radiation exposure during employment at Pilgrim upon his termination in 1986. In aadi-tion, the alleger stated that requests for his radiation exposure records were submitted to Boston Edison Co. but went unanswered. 10 CFR Parts 19 and 20 require that the . licensee supply exposure records upon an individual's termination or upon request. This information was brought to the attention of the licensee's . radiation protection group for evaluation. The licensee stated that in excess of one hundred similar failures to provide the required reports were iden-tified during their followu At the exit meeting, the licensee indicated that dose reports were now being issued in a timely manner and that the backlog of past dose reports would be reviewed and-the reports issued. This item will remain unresolved pending review of the licensee's actions by a NRC radiation protection specialist inspector (87-27-07).
4.0 Review of Plant Events The inspectors followed up on events occurring during the period to deter-mine if licensee response was thorough and effective. Independent reviews of the events were conducted' to' verify the accuracy and completeness of licensee informatio !
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a. Insulation Fire on the Emergency Diesel Generator On. June 29, 1987, during a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> post maintenance endurance run of the 'A' emergency diesel generator, licensee personnel discovered smoke and small flame 'on the outer wrapper of the insulatie blanket-around the diesel generator exhaust piping. The fire was . extin-guished immediately by the operations personnel performing the diesel testing, . using a portable dry chemical bottle stored in the diesel room. The diesel generator was manually shut down at the same tim The licensee suspected that oil contamination on the insulation materials caused the fire and subsequently replaced the insulation around the diesel generator exhaust pipin On June 30, 1987, . during a retest of the 'A' diesel generator, similar smoke and flame on the outer wrapper of the insulation blanket around the diesel generator exhaust piping was discovere The fire was extinguished immediately by the operations personnel performing the diesel testing again using a portable dry chemical bottle stored in the diesel room. The diesel generator was manually shut down at the same time. The licensee Systems Engineering Group initiated an investigation to determine the root cause and to formu-late corrective actions. The investigation focused on the insulation material and its configuratio The licensee had replaced the insulation material from the diesel generators as part of the diesel generator overhaul and silencer modifications during this outage. The material to be used for remov- ;
able 1.nsulating blankets is specified in the Pilgrim Specification "
(M-549 ED), section 7.1.1. 2 for low-alloy or carbon steel pipe. For temperatures up to 500 degrees Fahrenheit (F), silicone-coated cloth is listed as acceptable; for temperatures up to 1000 degrees F, plain glass cloths are listed as acceptabl The licensee determined that the outer wrapper of the insulation material (silicon impregnated glass cloth) which burned at places where the insulation blankets overlapped was probably due to a local '
chimney effect where the super heated air was swept across the skin fabric. The outer coating of the insulation material is rated for maximum temperature of 500 degrees The diesel generator turbo-charger outlet temperature is expected at about 900 degrees F. If the blankets are carefully edge-matched and tied tightly, the postu-lated chimney effect may be minimized, as evidenced previously in the
'B' diesel generator testing. The 'B' diesel generator had completed its 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test on May 2,1987 without any problems noted. However, thorough inspection of the insulation blankets on the 'B' diesel generator exhaust piping revealed brown spots where the blankets overlap which indicates a potential for similar problems.
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The licensee'.s root cause analysis - also indicated that' there was no specific direction on' the ' insulation work to be. done on the diesel generator exhaust pipin The insulation work on . the silencer was
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directed by the licensee engineering . departments . Field Revision l- Notice-(FRN 84-41-05) to the existing. plant designschange (PDC 84-41)l l " diesel . generator silencer drain modification". The, insulation l-
' blankets : for. the silencer were specified to ..be constructed with. 2 x layers 'of 2 Linch- thick- blankets- with silicon coated 1 cloth. per FRN 84-41-05. The maximum temperature for' the silencer 1s estimated at about 600-700 degrees- F. . Although it did not directly apply, - FRN'
84-41-05 was also used in constructing'and applying insulation on the diesel exhaust piping. .The maximum temperature for the exhaust piping.is estimated at about 900-1000 degrees'F. Another FRN'(FRN 84-41-12) was. issued _on July 1, 1987 t'o specify and l direct the insulation work on the exhaust piping. The licensee have subsequently replaced the insulation ~ blankets for both diesel gener-ators from the turbo-charger exhaust to the silencer outlet. The new insulation blankets are made with plain glass cloth outer covers as
.specified in the Pilgrim Specification (M-549-ED), which is rated for up.to 1000 degrees.F. The 'A' diesel generator was tested .for its 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run on July 7, and July 8,1987 without any problems-noted. The inspector had no further questions concerning. the causes and corrective actions for the insulation fire ~
In response to the fires, the licensee ordered that operations per-sonnel be immediately dispatched to the diesel generator building to
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monitor the diesel generators if either started automatically. The operators were also instructed to be in the 'B' diesel generator room prior to a manual stai L to monitor for fir Later that day, June 30, 1987, th? 'B' diesel generator was operated during a routine surveillance-tes The inspector was-in the diesel building at the time- of the test and noted that two operators were in the 'B' diesel generator room monitoring the machin ~
The test was not required by the technical specifications since no fuel was in the reactor vessel. At the time of the : test, the licensee sus-pected that insulation was the cause of the f tes on the other diesel generato However, the root cause had not been positively iden-tified so a fire during the 'B' diesel generator surveillance test could not be ruled ou The. inspector questioned the wisdom of running the 'B' diesel genera-
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tor prior to the identification of a root cause for the fires in the
'A' diesel generator, in light of the plant configuration (i.e.,
since no fuel was in the _ reactor). The inspector also questioned a ;
lack of communication with the fire protection and system specialist groups prior to the test. The licensee acknowledged the inspector's
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concerns and subsequently suspended manual tests on the 'B' diesel l
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generatorf until the insulation question was resolve At the exit meeting, the licensee Lindicated that .the Watch Engineer: should not have conducted the test. The. licensee disagreed with the communica-
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tion concern. indicating that it was not important that the . fire pro-l"' tection and . systems groups be informed ' of the test. The: inspector.
l had no further questions.
H Spurious Manual Initiation of the ~ Ecergency Diesel Generator Dry Chemical Fire Suppression System On July 2,1987, Lat approximately.1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br /> the dry chemical fire-suppression system ' for the 'B' . Emergency Diesel Generator (EDG) . was -
spuriously initiated. : The. system consists of t'wo chemical storage
. tanks that' discharge into a covered fuel oil, piping chase _ located in the EDG room. Initiation of the system can be accomplished manually
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at two- locations within. the EDG. building, or automatically if asso-
- ciated. heat sensors . located in the pipe chase are tripped. Inspec-tion by the licensee . indicated that the system had been manually trippe The system was recharged and returned to service on July 3, 1987. .0ther EDG fire detection: and suppression systems remained operable during that time, and a continuous fire watch was poste The. licensee fire protection group initiated an investigation of the discharc Licensee corporate security was requested to identifywnd interview all persons accessing the area during the time period sur-rounding the~ discharge. The evaluation did not conclusively identify the cause. .However, based on the information obtained the licensee '
believes that the manual trip latch was inadvertently disturbed' by workers in the area. Personnel interviews indicate that jackets, tools or flashlights have been left in the area by workers and could have disturbed the latch. The trip lever is designed to ar.commodate a pull pin to prevent inadvertent initiatio This pin however was never installed. Other similar dry chemical systems were also found to be missing these pins. As corrective action the licensee instal-led the needed pull pins, revised the monthly equipment surveillance a to inspect for the presence of the. pins, and issued a memo to appli- '
cable managers stressing the need for careful treatment of fire pro-tection equipment oy their personnel. - The inspector had no further question Spurious Reactor Protection System Actuations j i
A spurious reactor protection system (RPS) trip signal was received i at 0530 hours0.00613 days <br />0.147 hours <br />8.763227e-4 weeks <br />2.01665e-4 months <br /> on July . 3, 1987, resulting in a reactor scram. The '
plant is shutdown and all fuel has been removed from the vessel since February, 198 All control rods were full in a_t the time of the scra The licensee had previously inserted a half-scram on the B
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RPS channel as .part of planned maintenance activities. A spurious-trip of the E average power range monitor (APRM) caused a trip of the A RPS channel, resulting in generation of a. full scram. Tne scram-signal. was. subsequently cleared and-the logic reset. The licensee is investigating the source of the spurious APRM tri On July 7, -1987, two Reactor Protection System (RPS) . trips occurred resulting in : generation, of two full scram signals. A half scram
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signal had been manually inserted in: RPS channel B to accommodate
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ongoing, maintenanc At 0300' hours the Electrical Protection
~ Assembly 1(EPA) on the output of the A RPS' motor generator (MG) set tripped, completing the -logic necessary for the full scra The EPA was reset, and the scram cleared by about 0400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />. _ Subsequently, the B channel of RPS was manually tripped to allow continuance of the -
planned maintenance. At 0105. the EPA on the A MG set again tripped'
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generating a second full scram. The second scram was reset at 0530 hours0.00613 days <br />0.147 hours <br />8.763227e-4 weeks <br />2.01665e-4 months <br /> after completion of the maintenance on .the B RPS system. All rods were full in' at the time of the scrams with both control rod drive pumps isolated for maintenanc Six electrical protection assemblies were installed on the RPS power supply as an upgrade to provide fully redundant class 1E protection for safety grade systems and components powered by RPS supplies. -Two assemblies are connected in series to each RPS power source to yo-vide overvoltage, undervoltage and underfrequency protection with seismically qualified devices. This retrofit addressed NRC concerns that a seismic event could render originally installed protection -
devices inoperative and permit RPS to receive an out of limits volt--
age supply which could damage sensors and ' degrade. RPS ability to scram. A failure and malfunction report and a maintenance request were generated 'by the licensee to investigate the cause and to cor-rect the problem. The licensee discovered a faulty logic card on #2 EPA and the logic card was replaced. The 'A' RPS channel was put back in service for about 3 ' weeks and an installed recorder has not detected any abnormalities. The station electrical engineer informed the Inspector that he is investigating the root cause of the EPA logic card failure with the vendo Contractor Employee Found Positive on Drug Screening On July 7, 1987, the licensee informed the resident inspector that a contractor security guard was found positive on his annual drug screening. The security guard was escorted off site and his site access was terminated as of July 7,1987. The individual had under-gone drug screening acceptebly in July, 1986 before being hired. The inspector had no further question ;
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22- Contractor' Employee Contaminated with Promethium
' On July 27, 1987, at' 9.:40 pm, _ a contractor worker was found 'to be
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radioactively contaminated. The worker indicated the contamination probably occurred while he tried to remove the luminous material (believed by the worker to be radium) from a watch dial at his home in Maine,_ earlier that day; Up to 27,000_ disintegrations. per minute-(dpm) of radioactivity was detected on the worker's skin, including 16,000 dpm on his fac Radioactive material, was also found on the worker's clothin The licensee, altho' ugh not responsible for the m 3te ri al , decontaminated the worker and' furnished other health physics assistanc The licensee subsequently determined that the worker was apparently contaminated with promethium-147, and not radiu Promethium-147 presents fewer health risks- than radium. Licensee surveys of the individual'and his cloth _ing and effects failed to detect the specific activity (alpha activity) associated 'with radium. 'The licensee also -
contacted the watch manufacturer, who indicated that promethium-147 was the isotope used in watches of the vintage to make the dial-luminous. These watches are exempt from NRC regulations following distributio A representative ' from the State of Maine. Emergency Management' Agscy surveyed the worker's home 'on ' July . 28, 1987. Contamination was identified on and surrounding a workbench, and en the razor. blade used by the worker to remove luminous material from the watch face and hands. Again, no evidence of radium W' Stected in the contam-ination. Clean-up of the workbench and surrounding areas will be performed with subsequent verification surveys to be performed by the St&te of Main The inspector noted that the "eicensee although not responsible for the material, furnished significant health physics assistance to the ;
individual. The inspector had no further question '
5.0 Review of LER's LER's submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further j information was required from the licensee, whether generic implications j were indicated, and whether the event warranted onsite followu The following LER's were reviewed: l y
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LER N Event Date Report Date Subject 87-006 05/06/87 06/04/87 Loose and/or miss-ing bolts on hydraulic control unit structural frames '
LER 87-006 documents the licensee's finding of loose or missing bolts on 31 out of 145 HCU frames. The licensee's investigation was initiated by a GE letter No. G-MK-6-326 dated October 22, 1986 informing all BWR util-ities of potential improper HCU installations. The inspector's review of the licensee's root cause analysis and corrective actions are documented in the Section 3.a of this repor .0 Meetings At periodic intervals during the course of the inspection period, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspectors. No written material was given to the licensee that was not previously available to the publi On July 23, 1987, several NRC senior managers 'and the NRR Licensing Project Manager (LPM) met with the resident staff onsite to discuss inspection resources and scheduling. The licensee made a brief presenta-tion to the group on their proposed prestart schedule. On July 24, 1987, the resident inspectors, the LPM and the NRC: Region I Section f.hief responsible for the inspection program at Pilgrim met onsite with repre-sentatives of the Commonwealth of Massachusetts to discuss the NRC inspection process.
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Attachment _I to Inspection Report 50-293/87-27 Persons Contacted 3-
- R. Bird, Senior Vice President - Nuclear 'b K. Roberts, Station Manager -
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D. Swanson, Nuclear Engineering Department Manager ,
N. Brosee, Outage Manager n ,
J. Jens, Radiological Section Head N. Gannon, Chief Radiological Engineer
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J. Seery, Technical Section Head -,
P. Mastrangelo, Chief Operating Engineer af R. Sherry, Chief Maintenance Engineer C. Higgins, Security Group Leader F. Wozniak, Fire Protection Group Leader
- Senior licensee representative present at the exit meetin . dw
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