IR 05000293/1981012
| ML20010B171 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 07/24/1981 |
| From: | Collins S, Elsasser T, Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20010B166 | List: |
| References | |
| 50-293-81-12, NUDOCS 8108140180 | |
| Download: ML20010B171 (25) | |
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(FOR DCS NUMBERS - See Next Page)
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U.S. NUCLEAR REGULATORY CCMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 50-293/8 1-12 Docket No. 50-293 Category C
License ho. DPR-35 Priority
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Licensee:
Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility hme:
Pilgrim Nuclear Power Station
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Inspection at:
Plymouth, Massachusetts Inspection conducted:
May 1 - 29, 1981 Inspectors:
Nbd YYN Se 'or Resident Inspector date signed T Johnson, %
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S. Collins, Reactor Inspector date signed (May11-15,1981)
date signed Approved by:
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T.C.Elsassef Chief, Reactor.. Projects date signed y
Section No.18. Projects Branch No.1 Inspection Summary:
Inspection on May 1 - 29,1981 (Report No. 50-293/81-12)
Areas Inspected: Routine Unannounced safety inspection of plant operations
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including an operational safety verification, followup on events occurring during the inspection, maintenance activities, surveillance activities, train-ing, leak rate testing of containment isolation valves. followup on the TMI Task Action Plan, licensee's preparations for potentii.. strike, I.E. Bulletin followup, fire protection modifications, and a review of Licensee Event Reports.
The inspection involved 119 hours0.00138 days <br />0.0331 hours <br />1.967593e-4 weeks <br />4.52795e-5 months <br /> by the resident inspector and one reactor inspector.
Results: One item of noncompliance was identified in two of the eleven areas inspected.
(Failure to provide adequate station procedures to prescribe activities affecting quality; Para sph 2.B(7).
810e140100 810729~
$DRADOCK 05000293 PDR Region I Form 12 (Rev. April 77)
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DCS Numbers for Report 50-293/81-12 50293-790125 50293-790222 l
50209-800108
50293-800115
50293-800426 50293-800807 i
50293-800813 50293-800821
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50293-800825 50293-800829 50293-800901
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50293-800910 50293-800930 50293-801005 50293-801023 50293-801030 50293-801116
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50293-801117
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50293-801129 50293-801209 l
50293-801223 50293-810512 50293-810514 i
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DETAILS 1.
Persons Contacted
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J. Aboltin, Sr. Reactor Engineer A. Caputo, Fire Protection Engineer J. Frazer, I&C Supervisor J. Fulton, Senior Licensing Engineer
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P. F. Giardiello, Sr. Compliance Engineer E. Graham, Sr. Plant Engineer
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R. Kennedy, Sr. Q.A. Engineer
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R. Machon, Nuclear Operations Manager (Pilgrim Station)
C. Mathis, Deputy Nuclear Operations Manager T. McLaughlin, Sr. Compliance Engineer W. Olsen, Senior Nuclear Training Specialist J. Seery, Staff Assistant, Nuclear Safety P. Smith, Chief Technical Engineer R. Smith, Chemistry Supervisor S. Wollman, Shift Technical Advisor
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E. Ziemianski,. Management Services Group Leader The inspector also interviewed other members of the health physics, operations, maintenance, security, and technical staffs.
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2.
Operational Safety Verification a.
Scope and Acceptance Criteria The inspector observed control room operations, reviewed selected logs and records, and conducted discussions w'th control room operators.
The inspector verified the operability of selected emergency systems and verified the proper return to service of affected components. Tours of the reactor building, turbine building, cable spreading room, switch-
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gear rooms, intake structure, euxilliary bay, security building, and control room (daily) were cont'ucted. The inspector's observations ia-cluded a review of equipment condition (including control room ani.un,. -
ators), potential fire hazards, physical security, housekeeping, and the implementation of radiological controls and equipment control (tagging).
The in @ector reviewed the documentation associated with several liquid radicactive waste discharges, and the logs, records, and control room instrumentation pertaining to gaseous release rates from the station.
These reviews and observations were per formed in order to verify con-formance with the Code of Federal Regulations, the facility Technical Specifications, and the licensee's procedures.
b.
Findings (1) During a tour of the control room on May 21, 1981, the inspector noted that control rod no. 22-35 had been valved out of service in the full out position (position 48) with the reactor at full power for the time interval 5:35 am to 10:00 am on May 21, 1981.,
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The control room SRO stated that this rod had been taken out of service in preparation for replacing the rod accumulator (Main-
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tenance Request No. 81-3-38) due to repetitive alarms in the past when small amounts of water had leaked into the accumulator.
The operator further stated that no maintenance was performed, that the work had been rescheduled for a later date, and that the isolation (tagging) was removed and the rod returned to ser-vice.
The inspector questioned the Reactor Engineer concerning his know-ledge of the event and verification that the shutdown margin (SDM)
required by Technical Specification 3.3.A.1/4.3.A.1 had been met with control rod no. 22-35 inoperable and in the full out positio.
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The Reactor Engineer stated that he.was informed by the control room operator that the rod was to be made inoperable and detennined that SDM would be met because of the results of the SDM verifica-tion test performed during the physics testing cn the first start-up after the last refueling outage.
The inspector stated that the information provided during that test was insufficient to verify the T.S. SDM required for thfs configura-tion. The licensee acknowledged the inspector's comments and re-quested the General Electric (GE) Co. to perform calculations to verify the SDM available on May 21, 1981. On May 29, 1981, the Licensee informed the inspector that GE had perfonned the calcula-tions for the core configuration on May 21, 1981 with control rod no. 22-35 inoperable at the full out position. TheSDMavaflable (assuming the most reactive operable rod stuck out, cold 68 F, and
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no Xenon) was about.83%oK (T.S. limit is E.25% AK). The licensee further stated that documentation of these calculations would be 'provided to the inspector when available an site.
The inspector further questioned the licensee concerning the need for procedure revisions. Procedure No. 2.2.87 " Control Rod Drive System", Revision 9,Section VII.C, requires that the licensee's Reactor Engineering group be contacted prior to valving a rod out of service with the reactor operating. Section G of this procedure describes the action required for accumulator alarms (low nitrogen pressure or water). This procedure for adding nitrogen makes the control rod inoperable. Neither section requires that a SDM verification calculation be made prior to making (a control rodThe inspector stated tha inoperable.
a requirement to perfonn these calculations to verify conformance
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with T.S. Sections 3.3. A.2.B. 3.3. A.1, and 4.3. A.1, prior to making a control rod inoperable.
The licensee acknowledged the inspector's coments and stated that a review of Procedure No. 2.2.87 would be made and revised where apprcpriate.
The fa.iure to provide adequate instructions to verify conformance with T.S. Sections 3.3.A.2.b, 3.3.A.1, and 4.3. A.1, prior to making a control rod inoperable, is considered an example of an item of
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noncompliance.
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(2) During a tour of the control room on May 6,1981, the inspector noted that the Standby Gas Treatment System (SGTS) was in operation.
The licensee keeps track of the times that each train is in opera-tion because of T.S. surveillance requirement 4.7.B.l.a(6) which requires a methyl iodide test of the charcoal filters after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />. The inspector stated that since the SGTS dampers have been left in the accident position (since April,1981 pending re-placement of solenoid valves), whenever either ' A' or 'B' fan is run, there would be flow through each filter train.
Since the licensee is keeping track of the times according to which fan is in operation, this may not exactly match the times each filter is in operation. The licensee acknowledged the inspector's comments.
The failure to provide adequate instructions to ensure accurate run times of each filter train of the SGTS is considered an example of an item of noncompliance.
(3)' During tours of the station, the inspector noted that copies of an out of date procedure (No. 5.3.1) were in place at various equip-ment. The inspector also noted that the licensee's procedure no. 2.4.56 " Fire in the Cable Spreading Room / Alternate Shutdown Procedure" made reference to procedure no. 5.3.1.
These coments were provided to the licensee's management who initiated action to correct these items.
Procedure No. 1.3.8, " Document Control", Revision 25. does not address control of procedures posted throughout the station.
The failure to provide adequate instructions to control procedures through the plant is an example of an item of noncompliance.
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(4) During a tour of the control room on May 21, 1981, the inspector noted that the Residual Heat Removal System (RHR) was lined up to take a suction from the torus and discharge through a spectacle flange into the Fuel Pool Cooling and Cleanup System (FPCCS),
through the FPCCS demineralizer, and back to the RHR System through another spectacle flange.
The purpose of.this lineuo is to. clean up the torus water (conductivity and radioactivity)
in preparation for future maintenance near the torus.
The inspector reviewed the procedure for this lineup (No. 2.2.85
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" Fuel Pool Cooling System", Rev. 8, Section K, and No. 2.2.86
"RHR System", Rev.13, Section B) and noted that there is no mention of repositioning the RHR-to-Fuel Pool spectacle flanges.
The inspector also noted that the normal position of these spectacle flanges is not specified in the system lineup check lists (Appendix A) for the RHR System, the LPCI System, or the Fuel Pool Cooling System.
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The licensee management representative stated that the appropriate proccdure should contain the normal position of these flanges and reference to repositioning if requiied, and stated that these
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I procedures would be reviewed and revised where appropriate.
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The failure to provide adequate instructions for the nonnal position and repositioning of the RHR-to Fuel Pool spectacle flange is considered an example of an item of noncompliance.
(5) The inspector performed a review of the automatic primary contain-ment isolation valves listed in Technical Specification 3.7.D.1 and compared the required closing times with the acceptance criteria in the licensee's surveillance procedures.
s Technical Specification Table 3.7.1 specifies that the two RHR dis-charge isolation valves to radwaste must close in less than or equal to 20 seconds. The inspector noted that two of the licensee's
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procedures (No. 8.7.4.3 " Test Isolation Valves Except MSIV's",
Rev ; ion 5, and No. 8.5.2.1 "LPCI Subsystem Operability Surveillance Tc.at", Revision 7) specified that the maximum acceptable closing time for the two RHR to radwaste isolation valves (1001-21, and 1001-32) was 25 seconds.
Tha licensee immediately reviewed the Technical Specifications '
and revised these two procedures.
The inspector reviewed the completed surveillance tests for these two valves which were performed monthly during the past two years.
All the data reviewed indicated that the two valves in question had met the T.S. requirement of 20 seconds.
The failure to provide adequate acceptance criteria in procedures 8.7.4.3, and 8.5.2.1 is considered an example of an item of noncompliance.
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(6) The inspector has been monitoring the licensee's progress in
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clearing / correcting the conditions which cause control room annun-ciators to be either pulled (deactivated alarm) or continuously in alarm. The following table describes the number of annunciators in these two conditions for the past 6 month period.
Main Control Room Annunciators Date Number Number Total Pulled Pulled Continuously or in Alarm in Alarm 1/12/81
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1/30/81
21
2/27/81
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3/31/81
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4/30/81
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5/26/81
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i Although no items of noncompliance were identified during this review, the in* pector expressed concern that inadequate emphasis
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may have been i aced on correcting these conditions.
l The licensee representative stated that, following the station's previous review of these annunciators, the corporate engineering staff had been actively i.1vestigating each annunciator. The first phase of this study has been completed and each alarm has been reviewed according to cause and recomended method of resolution.
Status sheets for each alarm with the recommendation of either a Maintenance Request (for a setpoint change or replacement of de-fective component) or a Plant Design Change (for system modifica-tion) have been provided to the station.
The inspector acknowledged the licensee's coments and stated that the actions to correct these unnecessary alarms would continue to be monitored during future routine inspections.
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(7) The examples of inadequate procedures described in Paragraphs 2.b(1), 2.b(2), 2.b(3), 2.b(4), 2.b(5) above, as well as those in Paragraphs 7.b(2) and 7.b(7) below, are collectively consid-
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ered an item of noncompliance (50-293/81-12-01).
3.
Followup on Events Occurring During the Inspection Reactor Core Isolation Cooling (RCIC) System inoperable on May 14, 1981 a.
At 2:50 pm on May 14, 1981, the licensee shut the RCIC system outboard
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isolation valve (1301-17) and perfonned redundant equipment surveillance,
testing because of an engineering analysis perfonned in response to IE Bulletin 81-02. This preliminary analysis inc".i ed that the RCIC inboard isolation valve (1301-16) would not fu~ r i. lose against the design differential pressuw.
Following discus:'ons between the cor-porate engineering staff and station personnel the correct torque switch setting and type of valve packing were used in subsequent cal-culations. These calculations showed that the inboard isolation valve had been fully operable, and the RCIC system was returned to service on May 15, 1981.
No items of noncompliance were identified.
b.
Main Stack process radiation monitor inoperable on May 12, 1981 Due to a stcrm in the local area and as a result of a lightning strike l
on the evening of May 12, 1981, the main stack gas monitor channel 'A'
was rendered inoperable. The inspector verified the operabilit the remaining channel (T.S. 3.8.B.5 requires only one channel) y of and noted the return ta service of the damaged channel ('A') on May 14, 1981.
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No items of noncompliance were identified.
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4.
Maintenance Activities The inspector reviewed maintenance items in order to verify that the activities trere conducted in accordance with the licensee's procedurer, the facility Tech-
.;ical Specifications,and the Code of Federal Regulations. The inspector verified for selected items that the activity was properly authorized, and that appropriate radiological controls -quipment control tagging, and fire protection were being. implemented.
The it.ms/ documents eviewed are listed below.
-- Maintenance Request (MR) No. 81-45-90; repair main stack monitor Channel 'A'
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M.R. No. 81-45-93; torus level indicator / recorder M.R. No. 81-45-94; 'D' refuel floor radiation monitor downscale
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M.R. No. 81-9-22; Containmen! Atmosphere Process radiation monitor (C-19) blown fuses.
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M.R. No. 81-3-38; Control rod 22-35 accumulator (no work done - job rescheduled for the future)
M.R. No's. 81-50-2, and 81-50-3; Modify containment purge valves
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A0-5035B, A05036B. These two MR's were utilized to implement Plant Design Change Request (PDCR) No. 81-13 which modifies the two remain-ing 20 inch butterf'y valves limiting their opening to about 50%
(45 degrees).
The. inspector also reviewed the following additional documents associated with this activity:
- PDCR No. 81-13
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Field Revision Notice 81-13-3
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_ On-site and_0ff-site.appfoval fonts
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- NED memo 81-268 (references safety evaluation)
Completed surveillance test no. 8.7.4.3 documenting valve timing.
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No items of noncompliance were identified during this review of mainten-ance activities.
5.
Surveillance Activities The inspector reviewed the licensee's actions associated with surveillance testing in order to verify that the testing was performed in accordance with station procedures and met the Technical Specification limiting con-ditions for operation.
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Portions of the following tests were observed / reviewed:
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' A' channel main stack process radiation monitor calibration sumary 7.4.24-I-1; following damage due to lightning on May 12, 1981.
HPCI system pump and valve operability tests (8.5.4.1 and 8.5.4.4);
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following declaring the RCIC system inoperable on May 14, 1981.
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-- Core flow (jet pump) ca?ibration (procedure no. 9.17) being performed on May 18, 1981. The i',spector reviewed the calibration records associated with test instrument (digital voltmeter) being used. The serial number stamped on the instrument being used was 94294 and the serial number of the calibration recoro sheet from BEco. Standards laboratory was listed as 94694. The inspector questioned the I&C Supervisor concerning this discrepancy and determined that the instru-ment had been properly calibrated and that the I&C department had already identified the error on the calibration sheet and had initiated action to correct the records. The inspector had no further questions.
No items of noncompliance were identified during this review of surveillance activities.
6.
Training On May 11, 1981, the inspector observed the licensee's General Employee Training (GET) program for new emoloyees. The program is conducted to key.Y,(and.2hhection 6*4*
satisfy the requirements of Pilarim Technical snfng,i ati cif T
plant procedure 1.3.14. Indoctrination anc Train
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Pilgrim Nuclear Power Station (PNPS) Training Manual.
The inspector noted that the licensee's GET lecture's included the follow-ing:
- Station Quality Assurance Indoctrination
- Radiological Health and Safety Procedures
- Station Contingency Procedures
- Industrial Health and Safety
- Facility Access Control and Security Procedures
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The inspector reviewed PNPS Training Manual, General Employee Training, Section 2.1.1, Program Requirements, the lecture content of May 11, 1981 and had the following coments:
The lecture and video tape series satisfied the requirements of Pt1PS
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Training Manual Section 2.1.1.
- The video tapes require updating in the following areas:
Changes to PNPS Organization Chart
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Changes in radiological monitoring hardware
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Changes in the PNPS Emergency Plan
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The inspector discussed the above with the Nuclear Training Supervisor and noted that it would be approporiate for the instructor to discuss deficiencies in the video tapes following each lecture. The licensee acknowledged the inspector's comments and added that the use of video tapes is being expanded and updated.
A review of Reg. Guide 8.13. Instructions Concerning Prenatal Radiation Exposure, dated November 1975, revealed that section C.2 recomends that instruc-tions in this area should be presented to the employee both orally and in written form. The inspector noted that although GET participants are re-quired to sign a form stating they have been made aware of Reg. Gui,de 8.13 requirements and the topic is discussed during the GET lecture scenes, a copy of the Reg. Guide or other written instructions were not provided.
The Nuclear Training Supervisor noted the inspectors comments and stated that copies would be made available to all PNPS female employees and provided as a GET handout in the future. The inspector reviewed the licensee's memorandum dated May 15, 1981, issued to all female employees at Pilgrim Station informing them of the availablity of Reg. Guide 8.13 and that
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future GET classes will receive copies of this Reg. Suide. The inspector had no further questions in this area.
The inspector reviewed PNPS GET Instructors Guide, Copy #5, prepared by the NUS Corporation. The guide is utilized to satisfy the requirement of PNPS Training Manual Section 2.1.2, GET Program Description, which states that each of the areas of topics covered by indoctrination training is con-
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The inspector had no further comments in this area.
No items of noncom-pliance were identified.
7.
Primary Containment Leak Rate Testing a.
Scope and Acceptance Criteria The inspector reviewed the licensee's Local Leak Rate Testing (LLRT)
program (Type 'B' and 'C') and the results of the individual penetration and isolation valve tests performed during the January - May, 1980 re-fueling outage. The inspector also reviewed those tests performed since the last outage following maintenance that would affect the sealing capability of the valves / penetrations.
This review was performed to verify conformance with 10 CFR 50, Appendix J, the facility Technical Specifications, and the licensee's procedurec.
b.
Findings (1) The licensee modified the Containment Atmoschdre Control System during the January - May,1980 refueTing outage by the addition of the following systems:
Dedicated penetrations (6) and isolation valves to the drywell
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and torus for hydrogen recombiners; Plant Design Change Request (PDCR) No._79-29.
- Penetrations: for redundant nitrogen supply and exhaust capability _
for the drywell and torus (4 one inch penetrations and 16
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valves);PDCRNo's.80-03and80-21.
The inspector questioned the licensee concerning whether these containment isolation valves had been local leak rate tested and whether they had been included in the last integrated leak rate test. The licensee representative stated that the design of the modifications was such that the isolation valves could not be local leak rate tested and that they had been included as boundaries in the integrated leak rate test.
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The licensee was unable to provide documentation that these valves
were included in the integrated leak rate test but stated that this documentation did exist.
Pending a review of the procedural controls utilized for includirg these valves-(dedicated hydrogen recombiner penetrations, and 16 one inch nitrogen purge and exhaust valves)
during the primary containment integrated leak. rate test in May,1980, and documentation thereof, this item is unresolved (293/81-12- 02)
The inspector also stated that, since these modifications were such that local leak testing (Type 'C') could not be performed, that the acceptability of this design with respect to 10 CFR 50, Appendix A, General Design Criterion No. 54, " Piping Systems Penetrating Pri-mary Containment" was unresolved (293/81-12-03)
(2) The inspector stated that the acceptance criteria in procedure No.
8.7.1.8 " Local Leak Rate Testing of Feedwater Check Valves", Revi-sion 2, was not consistent with the Technical Specifications and the other licensee procedures for an individual valve and for the sumation of all valves. The licensee stated that this procedure would be reviewed and revised if necessary.
The inspector verified that the measured leak rate of the feed water check valves did meet the requirements of the T.S.
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The failure to provide adequate acceptance criteria in procedure 8.7.1.0 is considered an example of an item of noncompliance.
(3) The inspector stated that, follcwing the review of individual valve leak rate test sheets, that it appeared that LER No. 80-20 erroneously listed MSIV No.18 as having failed instead of MSIV No.1C. The
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licensee stated that this would be reviewed and a revised LER issued i
if necessary. See also Paragraph No. 13.
(4) The inspector noted that there appeared to be a conflict in two station procedures.
Procedure No. 8.7.1.3 " Local Leak Rate Testing",
Revision 3,Section VII.F. states that leakages recorded as 0.0 on the data sheet should be changed to a minimum sensitivity for the purpose of conservativel all valves and penetrations)y determining the total (summary of
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Procedure No. 8.7.1.5 " Local Leak
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Rate Testing of Primary Containment Penetrations and Isolation
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Valves", Revision 8,Section VII.B.2, states that (for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> pressure drop test of electrical penetrations) if there is no pressure drop, the penetration should be declared to have 0.0 leakage and the data reported on the sumary sheet (Procedure 8.7.1.3) shall be entered as 0.0 and be exempt from measurement tolerances.
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The inspectcr also requested justification for using.1 SLM as the minimum sensitivity of the local leak rate flow measuring device.
l The licensee acknowledged the inspector's concerns and stated that this conflict in procedure no's. 8.7.1.3 and 8.7.1.5 would be resolved, and the use of.1 SLM for minimum sensitivity would be justified. These items will be followed by the inspector in a future inspection (293/81-12- 04).
(5) The inspector noted that the licensee has chosen to test several penetrations together using manifold devices. The inspector determined that the total leakage observed for the combination of 8 Gibs' manways and the TIP flanges was less than that allowable for an individual penetrition but stated that the licensee should
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document that the manifold device was not plugged. The licensee acknowledged the inspector's coment and stated that procedure no. 8.7.1.5 would be revised to require that if penetrations or seals are mani. folded together, then the method must be documented on the test sheet and the manifold verified to be free of obstruc-tion.
This proposed revision to procedure ns. 8.7.1.5 will be reviewed in a future inspection (293/81-12-05).
(6) The inspector noted that about seven type 'C' local tests performed between May 9-16, 1920, following the PCILRT, were not included in the licensee's subsequent summarizing of all penetra-
l tions. The licensee acknowledged the inspector's coment and corrected the sumary sheets for the period May,.1980 to May,
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1981 incorporating these seven tests.
The inspector verified l
that the re-calculated total leakage rates were less than that allowed by the Technical Specifications and had no further questions concerning this item.
(7) The inspector noted that many figures provided in procedure no.
8.7.1.5 (describing the lineup for individual isolation valves)
included incorrect locations for venting and draining during the test. The inspector discussed the valve lineup with the licensee's leak rate testing director and determined that he was knowledgeable of the correct method of venting and draining and that there was no reason to believe that the individual tests were invalid. The licensee acknowledged the inspector's coment and stated that procedure no. 8.7.1.5 would be reviewed ice incorrect diagrams and revised as necessary.
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draining during leak rate testing is considered an. example of an item of noncompliance.
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(8) The inspector noted that many isolation valves are not tested in the direction of accident pressure. The licensee had previously been requested to provide a list of all valves tested in the reverse direction and a justification that the leakage measured was equivalent or conservative (Inspection Report No. 77-26).
The licensee stated that this list and justification would be requested from the corporate engineering group and provided to the inspector. This will be reviewed in a future inspection (already described as unresolved item no. 293/77-26-11).
(9) The two examples of inadequate procedures described in 7.b(2)
and 7.b(7) above, are combined with those described in Paragraph 2.b.(7).
8.
TMI Task Action Plan a.
Scope and Acceptance Criteria The inspector reviewed the licensee's actions in response to the re-quirements of the NRC TMI Task Action Plan. This review consisted of discussions with licensee personnel, a review of station records, and physical observations of selected equipment.
TI'is review was performed to determine whether the licensee's actions were in agreement.fth NUREG 0737 and the licensee's written commit-ments to NRC:NRR concerning these items.
b.
Findings I.A.1.1.3 Shift Technical Advisor. The inspector reviewed documentatibn to verify that 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> (40 classroom and 40 simulator) of training was conducted for the STA's during the fall of 1980 by General Physics
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Corporation. The inspector detennined that the training required by January 1,1981 had been completed.
I.A.I.3.1 Shift Manning / Limit Overtime. The licensee has started annotating the station operations log book to indicate the names of the operators who are assigned to various positions during each shift (control board, tour, surveillance, etc.).
The inspector has verified l
implementation of the licensee's commitment to " ensure that the opera-l tor does not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in the control room performing safety related functions."
The inspector has not recently observed any significant problems in the area of excessive working hours or excessive overtime. However, the inspector requested that the licensee provide an explanation and/
or justification for each area where a commitment was not made to comply with the criteria in NUREG 0737 pgs. 3-6 through 3-7.
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The acceptability of the licensee's program for limiting overtime will be the subject of further review, I.C.2.
Shift Relief / Turnover; I.C.5 Feedback of Operating Experience
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The inspector reviewed a change to the Boston Edison QA Manual, Vol. II, Section 18, " Audits", dated April _ 30, 1981, which adds a requirement
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to conduct annual audits in these two areas to evaluate their effective-ness. The inspector had no further questions on these two items.
I.C.6 Verify Correct 'erformance of Operating Activities.
NUREG 0737 pages 3-49 and 3-50 spac.Q' the criteria for verification of equipment control. The licensee's response to NRR dated February 27, 1981 stated that Boston Edison Company would develope a station policy incorpora-ting the requirements of TAP I.C.6, that this policy would be in place by March 31, 1981, and that procedure changes effected by this policy would be revised by June 1,1981.
The inspector reviewed the Pilgrim Nuclear Power Station Policy state-ment dated April 1, 1981 which summarizes the stations policy concern-ing equipment control during surveillance testing and maintenance.
This policy statement essentially summarizes the requirements specified in the following station procedures:
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- 1.5.3 " Maintenance Requests" 1.3.18 " Relief of Personnel"
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1.4.5 " Tagging"
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- 8.XX Surveillance Testing Procedures The inspector requested that the licensee provide a justification for not being in agreement with all the criteria specified in NUREG 0737.
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The inspector provided the following coments:
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- The licensee has not defined who can hang tags and reposition valves.
The licensee's policy is that " tagging is done by and under the direction of qualified personnel in the Operations Group." The
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l licensee does not require that tags be placed by a licensed operator.
- A second person is not required to independently verify tagging.
For maintenance, the work supervisor er worker is required to verify tagging for his safety. For tags issued without maintenance, (Watch Engineer's tags) no second verification is required.
The licensee's policy states that procedure no.1.3.18 requires a
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once per shift verification of system operability but this is only for ECCS.
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- The licensee's policy does not require a second verification of system realignment (unless a Technical Specification required surveillance test is also performed following maintenance).
The acceptability of the licensea's program for verifying the correct performance of operating activities will be the subject of further review.
II.D.3 Valve Position Indication. Technical Specifications for this item have been issued. The inspector observed the completion of daily instrument checks in accordance with procedure no. 2.1.15 " Daily Surveillance Log", Revision 36. A station procedure is being prepared for performance of the once per cycle calibration tests. The inspector had no further questions concerning the TAP item.
II.E.4.2.6 Containment Purge Valves. The licensee modified the two remaining 20 inch drywell and torus purge inlet valves on April 30, 1981 to limit their opening to 45 degrees (half open)~. The inspector reviewed Plant Design Change Request 81-13, Maintenance Request No.'s 81-50-2 and 81-50-3, and reviewed post maintenance surveillance testing in accordance with procedure no. 8.7.4.3.
The inspector had no further questions concerning this TAP item (II.E.4.2.6).
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II.F.1.1 Noble Gas Monitor. The licensee has approved periodic sur-veillance/ calibration procedures for the high range noble gas monitors.
The following procedures were reviewed:
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3.M.2-19, "High Range Effluent Monitor Calibration, Rev. 0
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8.M.2-4.4, "High Range Effluent Monitor Functional Test, Rev. 0
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7.4.29, " Source Calibration of High Range Noble Gas Monitors,
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fev. O, and
- 2.1.15, " Daily Surveillance Log", Rev. 36.
The inspector has observed implementation of procedure no. 2.1.15 and had no further questions at this time.
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II.K.3.27 Common Reference Level. NUREG 0737 page 3-173 specifies that all reactor vessel level instruments be referenced to the same point (top or bottom of the active fuel). The licensee's response to NRR dated February 27, 1981 stated that marker plates would be in-stalled on all necessary level instruments referencing-them to the top of the active fuel by July 1,1981.
During a tour of the control room on May 19, 1981, the inspector observed implementation of this committent. The following instru-mentation is available in the control coom:
Zero Reference to Panel Instrument
]Dg31 Scale (inches)
Fuel on Panel 905 640-26 Gemac 0 to 60 127 in. above fuel Recorder 905 263-100 A,B Safeguard-50 to +50 77 in. above fuel Yarway Indicator 905 640-29 A,B Gemac 0 to 60 127 in. above fuel Indicator 905 640-28 Recorder No scale Not referenced
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904 263-101 Refueling 0 to 400 Not referenced Indicator 903 263-106 A,B Post-150 to +150 Top of Fuel
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Accident Yarways Following discussions with licensee personnel, the inspector deter-mined that LI 263-101 was cold calibrated, used only for refueling, and would not be used during plant operations or during the course of an acc' dent. The licensee further stated that LR 640-28 was not necessary during normal plant operations or during the course of an accident and was not necessary to provide information to the operators. LR 640-28 is a multi pen recorder which indicates either steam flow or vessel level depending on the position of a selector switch.
The licensee has maintained the selector switch red tagged to vessel level so that the recorder is always able to give a permanent station record of vessel level to a point below the core.
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The inspector acknowledged the licensee's statements,-determined that
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the licensee's actions were in agreement with the commitment as stated
in their February 7, 1981 letter and, had no further questions concern-ing this TAP item at this time.
No items of noncompliance were identified during this review of the TMI Task Action Plan.
9.
Licensee Plans for Coping with Strikes During the period of May 13, May 14,1981, the inspectors conducted a review of the licensee's preparations for a possible strike at 00:01 a.m.,
May 19, 1981.
Boston Edison Company, Pilgrim Nuclear Power Station, Security Procedure
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No. 3.14, " Loss of Station Labor Force through Work Stoppage or Labor Problem", Rev.1 was reviewed by the inspactor which details actions to
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be implemented by the Site Security Force in preparation for and during a
site related work stoppage.
The inspector noted from discussions with licensee personnel, that the i
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organization considering the possible strike u uld not affect individuals necessary to meet regulatory requirements.
At the completion of this inspection pericd, no job action had been initiated. The inspector had no further questiors at this time.
10.
I.E. Bulletin Followup The inspector reviewed the licensee's actions in response.to IE Bulletin
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l 80-17, " Failure of Control Rods to Insert During a Scram at a BWR", Supple-i ment 4.
The following " items" pertain to those paragraphs in the Supplement.
Item 5 and 6.
Operability of CMS During Reactor Operation, and Operating
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Procedure. The licensee 4 response dated February 4, 1981 stated that sur-veillance procedures were scheduled to be in place by February 28, 1981.
The surveillance for response and power output of the transducers is contin-uous and automatic with an alarm in the control room to warn of system degradation. The frequency for a calibration check would be quarterly-
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and for a water injection test Juld be once per cycle.
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The inspector reviewed the following station procedures:
- 2.2.122 " Scram Discharge Volume CMS", Revision 2, dated February 27, 1981, and
- 2.1.5
" Daily Surveillance Log", Revision 35, dated Februar-27, 1981.
These two procedures describe the CMS system operation, provide actions in response to various alarms, actions in response to inoperable equipment, and require a daily test of the alarm annunciation in the control room.
On May 8, 1981, the inspector questioned the licensee concerning the quarterly and once per cycle tests. The licensee stated that these pro-cedures were in draft stage and had not been approved yet.
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On hay 18, 1981, the inspector reviewed the following approved procedures:
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8.M.2-7.1
" CMS Full Calibration", Revision 0 dated May 13, 1981 (once per cycle full electronic calibration)
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8.M.2-7.2
" CMS Functional / Calibration", Revision 0, dated May 13, 1981 (functional check quarterly, and calibration check semiannually).
The inspector verified that these procedures contain a requirement to
notify the NRC of any setpoint changes. The procedure for a once per cycle injection of water into the scram discharge volume has not been approved yet and is planned to be written prior to the next refueling outage scheduled to begin September 1981.
Item 4.
Full Test of CMS to be Conducted During a Planned Outage.
0,n May 12, 1981, the inspector reviewed the results of the full test of the CMS system perfcrmed March 4-5, 1981 in cccordance with procedure TP 81-07.-
The completed test procedure had not been signad by the Watch Engineer as having met the acceptance criteria because of.1 anomaly identified con -
cerning one of the four UT sensor alann setpoints.
The CMS analog and '
digital output voltages indicated that the alarm, for sensor 14A on the East header, came in at l' 5 inches (the setpoint is 1.25 +.25 inches).
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The independent measurements using a sight glass and a haiid held UT instru-ment indicated the alarm came in at about 2.5 inches.
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s The inspector questioned the licensee concerning plans to resolve this discrepancy. The licensee stated that plans were in effect to perform a survey of the piping system (to accurately determine the relative height of the sensor in reference to the sight glass measurements performed on March 5, 1981) and to perform radiograph tests (to determine the possibility of slag buildup inside the 6 inch header next to the UT sensor) some time before the end of the next refueling outage.
The inspector stated that it was unacceptable to wait until the next out-age to resolve whether the UT sensor would alarm at a point that would provide adequate free volume left to accept scram.
The licensee acknow-ledged the inspector's statement and performed calculatior.s to determine the amount of free volume at the alarm setpoint.
On May 13,1981, the licensee informed the inspector that there would be adequate free volume remaining in the scram discharge header in question even if the level of water were in fact at 2.5 inches when the alarm came
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in.
On May 18, 1981, the inspector reviewed the licensee's calculations and verified the licensee's determination that there was adequate free volume remaining to scram the reactor upon reaching the alarm setpoints far'all CMS sensors.
IEB 80-17 remains open pending a review of the verification that TP 81-07 met the acceptance criteria and a review of the approved periodic once per cycle injection test procedure.
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No items of noncompliance were identified during this review.
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11. Fire Protection During performance of control room panel reviews, the inspector noted an alaming condition on the fire detection instrumentation for the reactor building 23 ft. elevation zone. A review of the condition with the licensed operators indicated that the condition had been reported and was being in-vestigated. The inspector determined that the affected zone was not re-quired operable by FSAR section 10.8.3.3 or PNPS Tech. Spec. section 3.12.A.
The inspector determined that the licensee is in the process of
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updating the fire detection system per PDCR's 79-08-C thru 78-08-C-3 to meet applicable 10 CFR 50, Appendix R, requirements.
Fire detection i
panels C-221 and C-220 (Simplex equipment) have been installed in the control room and are operable. The original fire annunciator panels C-114 and C-ll5 (Pyrotronics equipment) remain installed and are also operable.
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The following documents were reviewed by the inspector:
Pilgrim Operations Department Temporary Procedure 80-79, Rev. O dated
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November 5,1980," Smoke Detection Systent'
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l Pilgrim Operations Department Procedure 8.B.4, Rev. 5, dated February 28,
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1980," Smoke and Heat Detection Systems Main Process Buildings"
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The inspector noted that procedure 8'.B.4 which provides instructions for testing the smoke detection system of the main process building addresses I
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only the Pyrotronics equipment. Although procedure 80-79 provides instructions for operation of the Simplex Detection System, it has no current provisions for periodic surveillance.
Pilgrim Tech. Spec. section 4.12.A requires that each of the fire detection instruments noted in Table 3.12,1, including the NFPA Code 72A supervised circuitry, shall be demonstrated OPERABLE by a functional test at least once per 6 months, and the fire detection in-strumentation supervised circuitry associated with detector alarms, shall -
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be demonstrated OPERABLE at least once per 2 months.
The licensee verified that the main process building quadrant rooms are currently being monitored b3 the Simplex Detection System with the i
Pyrotronics equipment disabled in these areas. The inspector noted that the l
HPCI and RCIC pump areas are located within the quadrants and are required to be functionally tested per Tech. Spec. Section 4.12. The licensee re-ported that a Quality Assurance Preoperational Test had been perfomed on April 24, 1981, prior to placing *:.e Simplex Detection System in service and that a procedure was currently being written to implement the' required functional testing for the new fire detection equipment. The inspector reviewed Q.C. Fire Alarm Preoperational data records and determined that HPCI and RCIC smoke detector surveillance conducted per PNPS Preoperational Test Procedure had been completed during the periods of:
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Oct. 24, 1980 and April 24, 1981 (SD 173P and.17'P): HPCI Zone 4 Oct. 23-24,1980 (SD 170P and 171P); HPCI Zone 5 April 22,1981 (SD 209 and 210); RCIC Zone 1 September 18,1980(SD212Pand211P)iRCICZone2
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As a result of this review, the inspector noted the following concerns:
- PNPS Operations Department Procedure 8.B.4, Stroke and Heat Ir ' =ction Systems Main Process Buildings has not been upgraded to add-
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Spec. Section 4.12.A required surveillance on the installed simplex Smoke Detection Equipment.
- If the current requirement of Tech. Spec. Section 4.12.A.2 is not going to be applied to the Simplex Detection Equipment, the licensee must formally evaluate and document the exception to the current T.S.
requirements.
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A review of preoperational test data for HPCI and RCIC zones, which is
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current.ly being utilized to meet T.S. section 4.12.A surveillance require-ments revealed that only 2 out of 4 of the installed smoke detectors in each quadrant room are currently within the six month functional test requirement. The remaining 2 smoke detectors in each quadrant had not be2n declared out of service or identified to the control room operators as inoperable.
It is noted that Table 3.12-1 of the T.S. requires only one (1) operable smoke detection instrument to monitor the safety related pumps in the HPCI and RCIC locations.
As a result of interviews with control room operators and fire protection
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personnel, it became evident that the current status of the Fire Detection Instrumentation was not fully known. Although PNPS Operations Department l
Procedure 80-79," Smoke Detection Systenf,, was issued on November 5,1980, tie operators were not fully aware of its contents nor the status of HPCI and RCIC monitoring equipment. Training in the status and operation of the-Fire Detection Instrumentation is needed in order to ensure proper re-sponse to the instrumentation by the operators.
The above items have been addressed to the Se ar Fire Protection Engineer and will be reviewed during a subsequent inspection (293/81-12-06).
No items of noncompliance were identified.
12. Licensee Event Report (LER) Review
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The inspector reviewed the following LER's to verify that the details of
i the event were clearly reported, including accuracy of the description l
of the cause, corrective action, whether further information was required, whether generic implications were involved, and whether the reporting I
requirements of the Technical Specifications had been met.
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LER Number Subject 80-03 Torus Vacuum breaker failed L T 80-06 RHR Snubber inoperable 80-48 HPCI and RCIC fire detection alarms inoperable 80-50 RBCCW and SSW pumps not operable from alternate shut-down panels 80-51 Setpoint drift - vessel level switch LIS 263-12N 80-56
'A' 125V DC Batter. Charger failure 80-57
'A' Reci rc. Mli Set trip due to faulty relay 80-58 HPCI throttle valve oscillations (the original LER submitted on September 19, 1980 erroneously listed this as LER No. 80-57.
Following discussions with the inspector, the licensee resubmitted revised LER No. 80-58/03L-1 on May 18, 1981).
80-61 Core Spray valve M0V 1400-24A inoperable 80-64 Reactor Building air lock door interlock inoperable 80-66 Diesel Fire pump inoperable 80-74 CondenseraT above 320F 80-75 Fire protection equipment inoperable 80-77 Containmentatmospheremonitor(C-19) inoperable 80-81 Reactor Building vent monitor sample pump inoperable 80-82 Trip of 480V breaker B52-204 80-85 HPCI turbine overspeed due to failed governor 80-88 Diesel fire pump flow low 80-89 Torus water level instrument inoperable 80-92 RWCU pump trip and inoperable isolation valve no.1201-2 80-93 RWCU valve no.1201-5 inoperable 80-95 Fire Brigade not summoned.
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No items of noncompliance were identified during this review.
13.
Licensee Event Report (LER) Followup Through direct observation, discussirns with licensee personnel, and a review of records, the LER described below was reviewed to detennine whether the reporting requirem ntiwere fulfilled, and thau corrective action to prevent recurrence had beer, accouplished in accordance with the Technical Specifications.
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LER 80-20/03L-0 " Primary Containment Isolation Valves". This LER pro-vides a sumary of the valves which were found to have seat leakage in excess of that permitted by Technical Specification 4.7.A.2.f during the Type 'C' testing performed during the Janua r - May,1980 refueling outage.
The inspector reviewed the licensee's file of completed local leak rate tests and compared the (before and after maintenance) leakage rates with those reported in this LER.
All information presented in this LER was in agreement with the individual valve records with the exception of a typographical error in one valve.
This LER erroneously lists valve A0 203-1B (MSIV 'B' inboard) as having failed and having a final passing leak rate of 7.30 SLM on April 5,1980.
This entry should have been for valve A0 203-16 (MSIV 'C' inboard).
No items of noncompliance were identified, however, other connents per-taining to leak rate testing are described in Paragraph 7.
14. Unresolved Items Areas for which more information is required to determine acceptability re considered unresolved.
Unresolved items are discussed in Paragraph 15.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and findings.
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