IR 05000293/1981030
| ML20038C813 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 11/20/1981 |
| From: | Bettenhausen L, Rekito W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20038C808 | List: |
| References | |
| 50-293-81-30, NUDOCS 8112140152 | |
| Download: ML20038C813 (10) | |
Text
50293-810926
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 50-293/81-30 Docket No. 50-293
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License No. DPR-35 Priority
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Category C
Licensee:
Boston Edison Company M/C Nuclear 800 Boylston Street Boston, Massachusetts 02199 Facility Name:
Pilgrim Nuclear Power Station, Unit 1 Inspection At:
Plymouth, Massachusetts Inspection Conducted:
October 19-23, 1981 Inspectors:
N. k.
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// b W. A. Rekito, Reactor Inspector date signed date signed Ap; roved By:
NV./37Cde-
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I_.H. Bettenhausen, Ph.D., Chief, Test Program date signed Section, Engineering Inspection Branch Inspection Summary:
Inspection on October 19-23, 1981 (Report No. 50-293/81-30)
Areas Inspected:
Routine, unanr.ounced inspection of containment leakage rate testing; inservice testing of pumps and valves; high drywell air temperature problems; and licensee action on previous inspection findings.
The inspection involved 38 inspector-hours onsite by one region based NRC inspector.
Results: No items of noncompliance were identified.
Region I Form 12 (Rev. April 77)
2ff00293 124 (
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DETAILS 1.
Persons Contacted The below listed technical and supervisory personnel were contacted.
- P.
Cafarella, Shift Technical Advisor
- R. Machon, Nuclear Operations Manager
- K. Roberts, Chief Maintenance Engineer
- J.
Seery, Staff Assistance, Nuclear Safety
- P. Smith, Chief Technical Engineer S. Wollman, Shift Technical Advisor
- E. Ziemianski, Management Services Group Leader NRC Personnel J. Johnson, Senior Resident Inspector The inspector also talked with and interviewed other licensee personnel during the inspection.
They included members of the operating and technical staffs.
- denotes those present at the exit interview.
2.
Licensee Action on Previous Inspection Findings a.
Items Closed Unresolved Item (293/77-26-10):
Procedure SP 8.A.2, Revision 4, Drywell to Torus Vacum Breaker Leak Rate Test, was revised to provide a vent path for the pressure source to ensure no leakage into the drywell during the test.
This procedure change was implemented by a permanent procedure change notice and SRO temporary change No. 81-49 dated October 21, 1981.
This item is resolved.
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Unresolved Item (293/80-04-02):
Procedure 8.7.1.5, Revision 9, Local Leak Rate Testing of Primary Containment Penetrations and Isolation Valves had been revised and included a prerequisite to check the leak tightness of the test device bypass isolation valve.
This item is resolved.
Unresolved Item (293/80-04-05):
Procedure 8.I.6, Revision 3, HPCI System Pump and Valve Operability Surveillance, was revised to specify that the speed be adjusted to a reference value of 4000 RPM. This procedure change was implemented by a permanent procedure change notice and SRO temporary change No. 81-50 dated October 21, 1981.
The inspector also verified that a similar change to Procedure 8.I.5, Revision 1, RCIC System Pump and Valve Operability Surveillance, was implemented by SRO temporary change No. 81-51, dated October 21, 1981. This item is resolve.
Unresolved Item (293/80-04-06):
Inservice test personnel training.
The licensee conducted a special training session on September 2, 1980 which covered inservice test program requirements and ASME Code familiarization. The inspector reviewed the training records and verified all performance engineers had attended.
Inspector concern for this item is considered resolved.
Unresolved Item (293/80-04-07):
Inservice test quantities. The inspector reviewed sample pump operability test procedures for the Core Spray System, Salt Service Water System, and HPCI System and verified that lubrication was properly checked. This item is resolved.
Noncompliance (293/80-20-02):
Failure to perform a leakage rate test following maintenance on a pipe flange which forms part of the primary containment boundary. The licensee corrected the specific identified problem as documented in inspection report No. 293/80-20. To prevent recurrence of a similar problem, the licensee has provided guidance to responsible maintenance personnel for recognition of post-work test requirements as detailed in procedure 8.7-1.3, Local Leak Rate Test Program, and activities affecting primary containment boundaries in general. As an additional control, the licensee has established a Refueling Outage Startup Department which reviews all maintenance work requests in accordance with procedure SU-4, Revision 0, Refueling Outage Startup Postwork Test process Planning and Implementation.
The inspector interviewed several responsible personnel to verify implementation of the corrective actions described.
This item is closed.
b.
Items Remaining Open Noncompliance (293/80-20-01):
Failure to comply with leak repair requirements of 10 CFR 50 Appendix J during the Primary Containment Integrated Leak Rate Test (PCILD.T).
The licensee was in the process of revising Procedure E.7.1.4, Primary Containment Integrated Leak Rate Test.
The licensee described some of the proposed procedure changes intended to specify clearly the actions required upon discovery of leakages or valve lineup problems during the PCILRT.
The licensee stated that these corrective actions will be completed and the revised procedure used for the next PCILRT scheduled for December 1981.
This item will remain open pending NRC review of the revised approved procedure and its implementation.
Unresolved Item (293/80-04-10):
T.S. Hydraulic Snubber Inspection Schedule.
The inspector asked to see documentation for review of a HPCI snubber replaced during a previcus (1979) visual inspection period. The licensee could not locate these records during the inspection but stated that they would be obtained from their
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engineering office and provided to the NRC Resident Inspector.
This item remains unresolved pending receipt of the necessary records and review by the NRC.
Inspector Follow Item (293/77-15-08):
T.S. Hydraulic Snubber Lockup Rates. The inspector asked to see documentation for piping system design thermal expans bn rates during heatup to verify that they do not exceed the snubber lockup rates. The licensee could not locate this information during the inspection but stated it would be obtained from their engineering office and provided to the NRC Resident Inspector. 'This item remains unresolved pending receipt of the necessary information and review by the NRC.
Unresolved Item (293/78-17-01): High Drywell Temperatures. The inspector asked to see documentM.'on of the engineering evaluation for acceptability of the recognized problem with drynll temperatures exceeding the design maximum value of 148'F.
The licensee could not locate the evaluation results during this inspection but
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stated that this information would be obtained from their engineering
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office and provided to the NRC Resident Inspector. The current
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status of this problem is discussed further in paragraph 4 of this report. This item remains open pending receipt and review of the subject evaluation by the NRC.
Unresolved Item (293/80-04-08): Salt Service Water Inservice l
test results review. The inspector reviewed a sampling of records
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for inservice tests including the Salt Service Water System and
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noted that results (data) reviews were being conducted as required by the inservice test program procedures. However the inspector l
identified a generic problem with the licensee method for inservice pump operability test results evaluation which is discussed further in paragraph 5.d of this report. This item remains
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unresolved pending resolution of the generic problem identified.
Unresolved Item (293/80-04-04): Drywell head installation procedure; re. NRC IE Bulletin 78-09.
The licensee has developed a new i
f procedure 3.M.4-48, Revision 0, Opening and Closing of the Reactor Pressure Vessel, which will be used to install the drywell head
following the current refueling outage. Section 4.27 of this procedure includes each of the installation checks described in
the licensee's response to IEB 78-09 dated August 3, 1978 and
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utilizes a special power wrench to torque the head bolts to a
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value of 2000 foot pounds. Use of this tool and method is intended to insure reproducibly tight head installation. The licensee
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stated that this special wrench and method was used and proven successful to install the drywell head following the 1980 refueling
i outage and subseque,nt Primary Containment Integrated Leakage Rate l
Test. However, no documentation of that installation was available i
for review during this inspection period.
The licensee stated i
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that documentation would be located and provided to the resident inspector. This item remains open pending NRC review of the 1980 Drywell Head installation records and implementation of the new installation procedure.
3.
Containment Leakage Rate Testing a.
Documents Reviewed
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Procedure 8.7.1.3, Revision 4, Local Leak Rate Test Program.
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Procedure 8.7.1.5, Revision 9, Local Leak Rate Testing of Primary Containment Penetrations and Isolation Valves.
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Procedure SP 8.A.2, Revision 4, Drywell to Torus Vacum Breaker Leak Rate Test.
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BECo. Ltr. No.80-275, to NRC, dated October 27, 1980, Additional Information Concerning 10 CFR 50 Appendix J.
b.
Scope of Review The inspector reviewed the above documents to ascertain compliance with regulatory requirements of 10 CFR 50 Appendix J and Technical Specification 4.7.
This review was in addition to the inspection of licensee action on previous inspection findings in this area as discussed in paragraph 2 of this report. The inspector also discussed the status of the current local leakage rate testing activities.
Procedure 8.7.1.4, Primary Containment Integrated Leak Rate Test, was not examined because it was in the process of being reviewed and revised by the licensee and his engineering consultant.
However, the licensee described some of the proposed changes to the inspector including:
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Clarifications of actions required upon discovery of leakages or valves not in the correct position; l
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Inclusion of responsibilities for the newly formed Startup Department;
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Addition of new and modified piping systems;
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Reference and adoption of guidance contained in American l
National Standard ANSI /ANS-56.8-1981, Containment System Leakage Testing Requirements.
This revised procedure will be used to conduct the Primary Con-l tainment Integrated Leakage Rate Test scheduled for December, 1981.
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No items of noncompliance were identified. The inspector had no further questions at this time.
4.
Drywell Air Temperature The licensee reported a problem with high drywell air temperatures causing erroneous, oscillating reactor vessel level indications. This problem was described in LER 81-055/01X-0 dated October 1, 1981 and LER 81-055/01T-0 dated October 15, 1981.
These LER's identified the probable cause of this problem to be ineffective drywell cooling due to a degraded condition of the Drywell Ventilation System.
The LER's described planned corrective actions to restore the Drywell Ventilation System to its design capacity and to conduct inspections and evaluations of safety related equipment for possible detrimental effects.
The inspector held discussions with the licensee regarding the status of equipment inspections, evaluations, and corrective actions.
Two very significant inspection findings discussed by the licensee were:
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The air passages of all eight Ventilation System cooling coils were blocked excessively with dust and dirt.
These cooling coils are scheduled to be replaced during the current refueling outage.
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Twenty of the approximately sixty cables inspected as of October 22, 1981 were found to be defective due to extreme brittle conditions of the outer insulation.
The licensee plans to replace these and any other defective cables discovered during the current outage.
The inspector reviewed data depicting the history of drywell air temperatures during normal plant operations.
Included was a trend of temperature at one location (38' elevation) from November, 1972 until September, 1981 and the temperature at various locations from March to September, 1981.
This data revealed a significant general trend of increasing temperatures throughout 1981, with the highest temperatures at elevations 60-90 feet ranging from 202'F to 240'F.
The inspector noted that this problem of air temperatures exceeding the drywell design maximum of 148'F was reviewed during NRC inspection 293/78-17.
As stated in paragraph 2 of this report, the licensee is expected to provide an engineering evaluation for the acceptability of this recognized operating condition in 1978.
The licensee identified another significant problem regarding their equipment qualification program per IE Bulletin 79-01B.
The licensee stated that all equipment environmental qualification evaluations conducted in response to IEB 79-01D used an erroneous assumption for maximum air temperature of 148'F and that these evaluations would be done again using actual environmental temperature data.
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The inspector identified no items of noncompliance but stated that review of this area would be continu?d during subsequent inspections.
5.
Inservice Testing of Pumps and Valves a.
Documents Reviewed ASME Eoiler and Pressure Vessel Code,Section XI, Subsections
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IWP and IWV, Inservice Testing of Pumps and Valves in Nuclear Power Plants.
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BECo. Ltr. No. 79-73 to NRC, dated April 13, 1979, containing Pilgrim Pump and Valve Inservice Testing Program Description.
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NRC Letter to BECo., dated August 15, 1979, containing interim approval of the program and relief as requested.
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Procedure No. 8.I.1, Revision 0, Administration of ISI Pump and Valve Testing.
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Procedure No. 8.I.3, Revision 0, Acceptance Criteria and Reference Value Determination.
Procedure No. 8.I.5, Revision 1, RCIC System Pump and Valve
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Operability Surveillance.
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Procedure No. 8.I.6, Revision 3, HPCI System Pump and Valve Operability Surveillance and records of test results dated 7/23/81, 5/22/81, 5/14/81, and 12/18/80.
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Procedure No. 8.I.7, Revision 2, RBCCW System Pump and Valve Operability Surveillance and records of test results dated 7/18/81, 5/30/81, 4/18/81, and 1/19/81.
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Procedure No. 8.I.8, Revision 1, Core Spray System Pump and Valve Operability Surveillance and records of test results dated 9/13/81, 8/2/81, and 5/2/81.
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Procedure No. 8.I.10, Revision 3, Salt Service Water System Pump and Valve Operability Surveillance and records of test results dated 8/29/81, 7/18/81, and 4/18/81.
Procedure No. 8.E.29, Revision 2, Salt Service Water System
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Instrument Calibration.
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Procedure No. 8.E.30, Revision 3, RBCCW System Instrument Calibration.
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Procedure No. 8.E.14, Revision 2, Core Spray System Instrument Calibration.
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Procedure No. 8.E.23, Revision 2, HPCI System Instrument Calibration.
b.
Scope of Review On a sampling basis, the inspector reviewed procedures and test results documentation for conformance with administrative and technical requirements of ASME Code Section XI. This review was in ti11 tion to the inspection of licensee action on previous inspection findings for pump and valve inservice testing.
In addition, the inspector toured the Service Water Intake, Reactor Building and Control Room to ascertain that instrumentation used for inservice testing met the quality and physical location requirements of Article IWP-4000. With the exception of the items noted below, the inspector identified no items of noncompliance and had no further questions at this time.
c.
Instrumentation Inadequacies Paragraph IWP-4113 requires that all instruments used for inservice tests be verified for calibration validity on a regular basis as established by the licensee.
From the sampling instrumentation review, the inspector identified two level indicators, LI-3831A and LI-3831B, which were not on a routine calibration schedule.
These instruments are used to compute the inlet pressure of the Salt Service Water Pumps in Procedure 8.I.10.
The inspector verified that these instruments had been recently calibrated (on 9/3/81); the licensee stated that they would be added to a routine calibration schedule or that another means would ba used to determine pump inlet pressure.
Paragraph IWP-4212 requires pressure instrument taps to be located as close as practical to the pump.
Procedure 8.I.7 utilizes a single pr essure gauge located on a common suction header for measuring inlet pressure for all RBCCW pumps.
The inspector stated that this measurement did not represent the inlet pressure condition of the individual pumps. He verified the existence of available pressure test connections at each pump inlet. The licensee acknowledged this inadequacy and stated that these test connections would be used to measure individual pump inlet pressure during future inservice tests.
The licensee's stated intentions satisfied the inspector's immediate concern for adequate performance of future inservice tests.
However, the two items described are considered unresolved pending implementation and NRC review of final corrective actions and are collectively designated an unresolved item (293/81-30-01).
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d.
Analysis of Results Procedure No. 8.I.1, Administration of ISI Pump and Valve Testing, specifies that the Performance Engineering Group will analyze inservice test data for compliance with the acceptance criteria within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> of test completion. This procedure also specifies that the Chief Operating Engineer be informed immediately of any inservice test results not meeting the acceptance criteria and falling within the " Required Action Range" so that the equipment can be " declared inoperative" and not returned to service until the faulty condition has been corrected.
Procedure No. 8.I.3, Acceptance Criteria and Reference Value Determination, re-iterates the results analysis process described above and includes a form for " Notification of Deviation" to the Chief Operating Engineer.
However, the inspector noted that step E.2.d. of this procedure allows a pump inservice test to be repeated if the results are not acceptable and the instrumentation is suspect. Additionally, the procedure states "no penalty be invoked until completion and evaluation of the repeated test."
The inspector explained to the licensee that their method of pump inservice test results analysis did not satisfy the NRC position regarding the relationship between time limits specified in Technical Specification Action Statements and the maximum data analysis time (96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />) specified in IWP-3220.
The licensee responded by explaining their normal practice. The Shift Technical Advisor (Performance Group Engineer) conducts the data analysis soon after test completion and does not wait the maximum allowed time before notifying the Chief Operating Engineer of unacceptable test results. Additionally, the licensee stated that, on occasion, faulty instrumentation had caused test results to be unacceptable and their practice of repeating the suspect test before declaring the equipment inoperable avoided needless immediate testing of other Emergency Safeguards Equipment.
The inspector stated that the NRC requires a pump be declared inoperable and the Technical Specification Action Statement time period started when the determination is made that pump inservice test data are within the " Required Action Range." The provisions of IWP-3230 to recalibrate instruments and rerun the test to show the pump is still capable of fulfilling its function are regarded by the NRC as an alternative to replacement or repair, not an additional action that can be taken before declaring the pump inoperable.
Further, the NRC requires that the method of results analysis permit the shift supervisor (or first reviewer) to make the determination whether or not the test data meets the inservice test requirements.
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This item is considered unresolved pending licensee action to declare a pump inoperable when the first reviewer determines inservice test data to be with the " Required Action Range."
(Item No. 293/81-30-02)
6.
Facility Tours The inspector made several tours of the facility including the Reactor Building, Service Water Intake and Control Room.
During these tours, the inspector observed activities in progress, im-plementation of radiological controls, and general condition of safety related equipment.
No items of noncompliance were identified.
7.
Unresolved Items Items about which more information is required to determine acceptability are considered unresolved.
Paragraphs 2.b, 5.c, and 5.d of this report contain unresolved items.
8.
Exit Interview The inspector met with licensee representatives (see Detail 1 for Attendees) at the conclusion of the inspection on October 23, 1981.
The inspector summarized the scope and findings of the inspection at that time.