IR 05000293/1987046
| ML20237A468 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 11/30/1987 |
| From: | Anderson C, Gray H, Woodard C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20237A460 | List: |
| References | |
| 50-293-87-46, GL-84-11, NUDOCS 8712150025 | |
| Download: ML20237A468 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-293/87-46 Docket No.
50-293
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License No.
OPR-35 Priority
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Category C
Licensee:
Boston Edison Company i
800 Boylston Street Boston, Massachusetts 02199 Facility Name:
Pilgrim Nuclear Power Station _
t Inspection At:
Plymouth, Massachusetts Inspection Conducted:
September 21-25, October 5-9, and October 19-23, 1987 Inspectors:
Cf0 b C. [.) d td u o
C.'Woodard, Reactor Engineer date
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YA ll. Y
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H.'Graf, Seni r'Reattor Engineer -
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C. Arfferson, Chief, Plant Systems Section date '[1 Approved by:
n Inspection Summary:
Inspection on September 21-25, October 5-9; and October 19-23, 1987 (Report No. 50-293/87-46)
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Areas Inspected: A routine announced inspection was conducted to review the licensee's followup and corrective actions related to several of NRC's previously identified open items. The actions taken in response to GL 84-11 on IGSCC were reviewed.
Results: A number of unresolved items and inspector followup items and one previously identified violation item were closed.
No violations were identified during this inspection.
The requirements of GL 84-11 were found to have been adequately addressed.
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DETAILS
1.0 Persons Contacted
l 1.1 Boston Edison Company (BECo)
- K. Roberts, Nuclear Operations Manager S. Hudson, Senior Operations Manager
- P. Hamilton, Senior Compliance Engineer
- B. Lunn, Compliance Engineer J. Pollack, Senior Engineer
- C. Stephenson, Senior Compliance Engineer
R. Whetsel, Senior Compliance Engineer l
N. Brosee, Maintenance Manager R. Cannon, Senior Compliance Engineer
- M. McGuire, Senior Electrical Maintenance Engineer J. Smith, Electrical Engineer i
- T. Beneduci, Senior Modifications Management Engineer M. McLoughlin, Senior Electrical Technical Group Engineer
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- R. Sherry, Chief Maintenance Engineer
- P. Manderino, Station Senior Test Engineer
- J. Purkis, Senior Systems Specialist N. Desmond, Senior Mechanical Engineer (ISI)
B. Ferkins, Senior QC Engineer (NDE)
F. Famulari, QC Group Leader J. Mattia, QA Group Leader B. Tucker, Material Protection Manager 1.2 Nuclear Regulatory Commission (NRC)
- J. Lyash, Resident Inspector
- T. Kim, Resident Inspector
- J. Golla, Reactor Engineer
- G. Napuda, Senior Reactor Engineer
- T. Rebelowski, Senior Reactor Engineer
- Denotes those present at exit meeting on October 9, 1987.
Denotes those present at exit meeting on October 23, 1987.
2.0 Followup on Outstanding Items (Update) Inspector Followup Item 86-14-04 - RHR Logic Deficiencies The licensee identified and reported under 10 CFR Part 21 an RHR situation where a single instrument failure could lead to loss of all four RHR Pumps.
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The inspector reviewed licensee evaluations and implementation of RHR flow l
control modifications under PNPS Plant Design Change 86-33, Revision 1, MO 1001-18 A&B Control Modifications.
PDC 86-33 changes the minimum flow valve position from normally closed to normally open.
It also deletes the valve automatic close input from the flow sensing instrumentation.
The net effect of these changes is that the minimum flow valves will initially be open and remain open during Low Pressure Coolant Injection (LPCI) system operatfor.
Because the valves remain open during LPCI injection, approxi-mately 525 gpm per pump will be diverted from the vessel. The inspector reviewed the licensee Safety Evaluation 1968, Revision 1.
This evaluation demonstrates that "this potential reduction of the LPCI flow has insignif-icant effect on the plant's core cooling capability."
This item is addressed by NRC IE Bulletin 86-01.
The licensee's response to this bulletin will be evaluated in a later report.
(Closed) Inspector Followup Item 84-28-02 - Process and Instrumentation Diagram (P&ID) Not Prepared The inspector had determined from a review and walkdown inspection that the licensee did not have a P&ID for the emergency diesel generator (EDG)
.l air start system.
By a review of the licensee's currently approved P& ids, the inspector determined that the licensee has developed and has in use currently approved P& ids M219 and M259 covering the EDG Air Start and Turbo Air Assist Systems, respectively.
This item is closed.
(Closed) Unresolved Item 83-23-02 - Acceptability of Instrumentation and Procedures for Assuring Standby Gas Trettment System (SBGTS)
Negative Pressure Capability Technical specification section 4.7.C requires secondary containment surveillance testing each outage to include demonstration that the SBGTS is capable of maintaining secondary containment pressure at or less than 0.25 inches of water under calm wind (5 mph) conditions with a filter train flow rate of not more than 4000 cfm.
Questions and concerns raised during previous inspections include the following:
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The test procedure (TP 8.7.3) did not consider the effect of wind on test manometer readings nor did it provide precautions or test method changes to be considered if winds greater than 5 mph exis.
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The test procedure measures the average differential pressure generated by the operation of the SBGTS train and subtracts from it the average initial (baseline) readings of the manometers.
It was i
not obvious that the predictability of the external variables which generate the building exfiltration profile (wind, stack, and heat effects) and the consequent initial baseline manometer readings is sufficient justification for subtracting the baseline from the final manometer readings.
The inspector questioned the justification for subtracting the baseline readings from the final readings.
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The test procedure requires four test manometers located unsymmet-rically around the periphery of the containment at the 91 foot elevation.
The inspector questioned the effect of manometer
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placement on the resulting differential pressure measurement.
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The inspector confirmed licensee actions taken to address these issues as follows:
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The licensee conducted an engineering evaluation of the Secondary Containment Leak Rate Procedure 8.7.3 including an evaluation of wind, stack and heat effects.
The evaluation also covered the location of test manometers and the procedure for establishing and treating the initial baseline conditions in determining the contain-ment negative pressure with confidence.
This evaluation is reported in licensee Nuclear Engineering Department Documer.t NID 84-38 dated January 18, 1984.
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As a consequence of the licensee evaluation, the test procedure 8.7.3 was revised (revision 12) to provice restrictions on initial baseline manometer readings and allowable wind conditions.
It further clarified how to treat initial baseline manometer readings in determining test values.
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The licensee engaged a consultant from MIT to conduct an independent evaluation of test procedure 8.7.3.
This evaluation confirmed that the " leak test data described in Secondary Containment Leak Test Procedure No. 8.7.3, Revision 12,... is appropriate and correct."
This evaluation is reported by letter to the licensee dated September 4, 1984.
The licensee has conducted Secondary Containment Leak Rate testing on several occasions using T.P. 8.7.3, Revision 12.
The inspector reviewed the test results from tests conducted on 9/1/87 and 9/23/87. The test values of containment pressure from the manometers were -0.62 and -0.67 inches of water respectively.
Since the technical specification requires that the pressure be negative 0.25 inches or more, these test values are acceptable.
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Based upon the licensee's actions taken to address the issues raired and the conduct of test which demonstrate technical specification compliance, this item is close.
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(Closed) Unresolved Item 87-01-03 - Procedure for Cleaning Electrical Cantacts in the PASS Heat Trace Temperature Control Unit During a 1984 outage inspection of the PASS Thermon supplied heat trace temperature control unit, a sample line temperature of 364 F was observed.
Licensee procedure 2.2.133 requires maintaining this sample line at 250 F 20 F.
The malfunction was attributed to dust / dirt contamination of the temperature control contacts. The licensee corrected the problem by cleaning the contacts by rubbing with a pencil eraser, washing with alcohol, and then applying a silicone grease.
The inspector had ques-tioned the licensee in the use of this cleaning procedure since it was neither documented by licensee procedure nor substantiated by the vendor,
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Thermon.
The inspector confirmed that the licensee now has substantiation for this procedure from Thermon and has incorporated it into Maintenance Procedure 8.E66 which requires PASS calibration and contact cleaning each 18 months or earlier, if required.
This item is closed.
(Closed) Unresolved Item 86-40-03 GE HFA Relay Failures During a December 1986 routine surveillance test of the
"D" refueling floor ventilation radiation monitor, a GE HFA relay failed to make up a contact on dropout to provide a control room alarm.
GE had previous experience of this type with the HFA relay and had issued Relay and Accessory Service Advice Letter No.188.1 on November 14, 1986.
This letter reported two previous ir,cidents of incorrect operation of the HFA relay in which relays which were energized with A-C and when deener-gized, failed to provide the correct contact operation.
Root cause of'the problem was identified by GE as a manufacturing defect.
A tooling problem caused the incorrect location of a stop tab which is welded to the relay armature. This incorrect positioning combined with minor movement of the relay magnetic assembly (some vibration when energized with A-C power)
caused the armature to bind. GE indicated that relays manufactured between January 1983 and October 1986 were suspect and recommended that these relay.c be replaced for nuclear Class IE applications.
For non-IE applications, rephcement of the relay armatures was recommended.
The inspector reviewed licensee actions taken to resolve this problem as follows:
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Engineering evaluations were conducted by the licensee and a report is included in NED 87-571 dated June 12, 1987.
In this report, the HFA relays are tabulated and categorized with regard to their pri-ority for replacement and repairs as follows:
Phase 1 - Normally energized, safety-related in which both normally open and normally closed contacts perform safety functions.
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open performs a nonsafety function.
Phase 2A - Normally deenergized, safety-related which perform safety functions.
Phase 3 - Normally energized safety-related in which the normally closed contact performs a safety function and the normally open contact is not used.
All safety-related relays in the warehouse.
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The licensee has replaced / rebuilt all of the safety-related HFA relays in the phase 1, 2 and 2A categories and those phase 3 relays
in the warehouse.
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Licensee evaluations conducted during the HFA replacement / rebuild showed that in cases where relay binding had occurred, it did not prevent the relay from changing state but, in some cases, prevented full travel (GE SAL also indicates this).
Based upon the GE SAL and the licensee's evaluation, installed relays in the phase 3 category will be replaced on a case-by-case basis and as needed.
Routine surveillance maintenance / testing will be used to check the opera-bility of these relays. The licensee evaluation M87-158 shows that safety functions will not be impacted by this approach for phase 3 category installed relays.
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Based upon the licensee and GE evaluations of the root cause and the implementation of corrective actions to resolve this problem, this item is closed.
(Closed) Inspector Followup Item 86-06-13 - Preventive Maintenance Proaram - 480 Volt Molded Case Circuit Breakers In response to NRC inspection 50-293/86-06, the licensee committed to expand and strengthen preventive maintenance of 480 volt molded case circuit breakers.
The inspector confirmed that the licensee has developed and implemented
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maintenance, testing and acceptance of these circuit breakers in accord-ance with Procedure No. 8.Q.3-3 480 VAC Motor Control Center Testing and Maintenance, Revision 7, dated July 1,1987.
This procedure was developed by the licensee based upon manufacturer's recommendation and their own experience and studies. As of August 25,1987, 88 of the 198 safety-
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related 480 VAC molded case circuit breakers had completed maintenance,
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testing and acceptance.
The remainder of the circuit breakers will be completed prior to startup.
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dure on 25 percent of these breakers each outage.
However, the Preventive Maintenance Program does not currently include this periodic maintenance
requirement.
The licensee plans to formalize this program after startup.
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(Closed) Unresolved Item 86-40-04 - Adequacy of Procedure for Washing Electrical Switchyard Insulators During December 1986, normal offsite power was lost when an electrical
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l fault occurred in the station 345KV switchyard.
The fault was caused
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I when mist from washing an adjacent deenergized section drifted onto a live section and provided the conducting medium for the fault.
Review of the
event disclosed that the licensee's procedure used, 3.M.3-20, " Live High Pressure Wet Washing Procedure," was not strictly applicable in that it only addressed washing energized sections of the switchyard and did not address the same precautions for the deenergized sections.
It was also noted that the washing crew briefing was completed on the day prior to the incident which was considered satisfactory but the notification of l
the control room step should have been done on the day in which the wash was performed.
The inspector confirmed that the licensee has revised and implemented procedure 3.M.3-20 such that in all of its steps, it treats energized and deenergized sections of the switchyard the same in both the prerequi. sites and the washing procedures.
It also includes three initial prewash pro-cedural sign-off steps indicating permission received to start work at a specific time on a specific c' ate from both the maintenance electrical engineer and the watch engineer.
This item is closed.
Glosed) Inspector Followup Item 86-37-08 - Defects in Cable Supplied by B1W Cable Company On November 3, 1986, BIW Cable Systems, Inc., reported a defect in Bostrad 7E 600 volt instrumentation cable to Region I under 10 CFR 21.
The defect involved non-uniform insulation wall thickness.
Due to a manufacturing process problem, the individual conductor insulation was not adequately cured.
Consequently, insulation performance over the life of the cable cannot be assured under this condition.
Subsequently, the licensee reported that approximately 18,000 feet of the cable had been installed for the analog trip instrumentation upgrades and that it would be re-placed. None of the cable was installed in active plant systems.
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November 6,1986 letter to the licensee identified the defective cable reels that should be withdrawn from service.
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The inspector confirmed that the licensee has replaced installed cables l
from the affected reels.
Cables pulled out were scrapped and unused portions of the affected reels were returned to the vendor.
Replacement BIW Cable was tested and found to be acceptable. This work was performed and reported under Plant Design Changes P.equest 84-70.
This item is closed.
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[ Closed) Violation 87-01-02 - Failure to Track PASS Heat-Traced Sample l
l Line famperatures to Prevent Recurrence of Sample Tubing Degradation During 1984 outage inspection, PASS heat-traced sample line piping was found to have thru-wall cracking which was initially attributed to the presence of chlorides and sufficient temperature (above 300 F) to cause stress orrosion cracking of the stainless steel piping.
Licensee Pro-cedure No. 2.2.133 for the PASS system requires maintaining heat-traced portions of the lines at 250 F 20 F.
Contrary to this requirement, during January 1987, the inspector found that a thermocouple for one of the lines was readirg 364 F.
The root cause of the temperature control system problem was found to be dirty electrical contacts. However, a review of the problem revealed that the PASS sample line temperatures were not scheduled for surveillance and the results of any past surveillance were not available for review.
The inspector confirmed that the licensee has conducted both nondestruc-tive and destructive evaluations of the PASS sample lines and found no evidence of degradation of the sample lines.
Stone and Webster test reports dated February 24 and 27 and July 22, 1987 cover these tests and evaluations.
The inspector also confirmed that the licensee has developed and implemented Procedure No. 7.4.33, Post-Accident Sampling l
System Heat Trace Surveillance. This procedure requires daily surveil-l lance of the system including recording all temperature readings when i
the system is in service.
I The Boston Edison response to the violation included identification of the most likely areas for cracking to occur and removal of samples for internal examination and chloride analysis.
The inspector reviewed the i
visual examination resuits and chloride swipe test data shown in the SWEC memorandum dated July 22, 1987. The visual and chemical results indicate the system piping to be suitable for continued service.
Visual examination of pipe samples removed from 12 areas of the pass system in 1987 was performed by the inspector.
These pipe samples did not exhibit significant corrosion of internal surfaces.
The QC inspector present during the pipe sample removal progress stated that water was not l
observed in the piping during pipe sample removal.
Chloride analysis, j
pipe dryness, temperature control and observation of removed pipe samples do not indicate that conditions favorable for cracking to occur to be
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l Based upon the licensee's analysis and corrective actions taken to'
I prevent recurrence of this problem, this item is closed.
Klosed)InspectorFollowupItem 86-17-02 - Debris in MSIV Pneumatic Valve Operator While evaluating the causes of maloperation of the outboard primary containment Main Steam Isolation Valves (MSIVs), the licensee found paper
(Kimwipes) and plastic lodged in the pneumatic four-way valve operator for i
the "A" outboard MSIV.
Examination of all other (inboard and j
outboard) MSIVs did not reveal any foreign material.
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The licensee concluded from a root cause analysis that the debris was left in the valve operator after the valves and manifolds had been disassembled and reassembled during the 1984 outage.
The plastic and kimwipes had been used in protecting the valve ports from the entry of foreign material while disassembled.
The procedure used for this work did not have specific instructions for the inspection to assure the removal of such debris prior to reassembly.
l The inspector confirmed that the licensee has revised Procedure 3.M.4-8,
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Main Steam Isolation Valve Maintenance, to require inspection and sign-off i
to preclude recurrence.
This item is closed.
(Closed) Unresolved Item 86-25-05 - Safety Buses Undervoltage Relay Calibration During a review of safety buses B-6 (480VAC) and D-6 (125VDC), the inspector had found that undervoltage sensing relays whose function is to initiate bus power source transfer upon sensing low source voltage was not addressed by the technical specifications and there were no station cali-bration/ test procedures in place for these relays. The inspector was of the opinion that the licensee's administration and control was weak since j
these and other safety-related relay settings and procedures and testing
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are handled by BECo offsite non-nuclear personnel.
As a consequence of these findings, the licensee committed to the follow-ing actions to resolve this problem.
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Controlled station drawings will be developed to show calibration and setting information for the 480 volt relays used in the safety-related motor control centers.
This will include not only the undervoltage relays but also the circuit breakers protective relays.
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Similarly controlled station drawings will be developed to show calibration and setting information for the 4160 volt safety buses relays.
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An evaluation will be made to identify other similar 480V and lower
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voltage relays that may warrant more administrative controls.
The inspector determined that the licensee has completed the evaluation and the development of station control drawings for the 4160 and 480VAC and 125VDC safety-related relaying and has implemented station procedures 3.M.3-1, 3.M.3-2, 3.M 3-27, 3.M.3-35, and 3.M.3-45 covering the cali-bration and testing of undervoltage relays and protective relays and electrical bus transfer devices.
This item is closed.
(Closed) Unresolved Item 85-30-16 - Circuit Drawing MIK-16, Revision 2, i
Not Properly Updated The inspector found that Elementary Diagram Core Spray System, Drawing MIK-16, Revision 2, did not include changes that were made by the licensee under Field Revision Notice 79-28A.2-03.
These were internal wiring changes within motor control centers MCC B1746 and MCC B1846.
The inspector confirmed that licensee drawing MIK-16, Revision E, now includes the required information and that licensee Procedure NED 3.02, Appendix D, Closecut of Modifications, now requires sign-off confirming that all affected drawings have been revised prior to the time a plant modification can be closed out as complete. This should prevent recur-rence of this type of problem.
This item is closed.
(Closed) Inspector Followup Item 87-03-03 - Safety-Related Circuit Breakers Sequence Timing Relays During the performance of Test 8.M.3-1, " Automatic ECCS Load Sequencing l
of Diesels and Shutdown Transformer with Simulated Loss of Offsite Power,"
I four significant deficiencies were reported as follows:
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The "D" R.H.R. circuit breaker A606 closed on the A6 Bus earlier than design time.
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The emergency diesel generator circuit. breaker A609 closed on the A6 Bus later than the design time.
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The shutdown transformer circuit breaker A601 closed on the A6 Bus earlier than the design time.
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The " Auto Transfer" of 480VAC Load Center B6 failed to transfer.
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The licensee conducted investigations and made analyses to determine the root causes of the deficiencies and recommended corrective actions.
Analyses of root cause for the circuit breaker sequence timing problem, items 1, 2, and 3 above, are made in licensee reports, Documents SG87-133,.
-134, and -135 dated May 21, 1987, and ERM87-386 dated October 8, 1987.
Item 4 above, the automatic bus transfer, is also covered by the licensee and NRC under Unresolved Item 86-25-05, discussed earlier in this report.
The licensee's evaluations attribute the timing problems to poor cali-bration instrumentation and excessive drift in the timing relay setpoints.
Corrective actions recommended in the evaluations were to improve the calibration instrumentation, to increase the calibration frequency, and to consider replacing the relays with new solid state units.
The inspector reviewed the actions taken by the licensee whic.h' include the following:
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The time for surveillance / calibration of relay logic circuits was decreased from once per cycle to a maximum of once each six months.
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The time for surveillance / calibration for LOP, degraded voltage, automatic circuit transfers, and load sequencing tests was decreased from once per cycle to a maximum of 18 months.
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The timing method was changed to require the use of a brush recorder to increase calibration accuracy.
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The GE Model No. CR2820 timing relays are scheduled for replacement during the next refueling outage.
Based upon the actions taken by the licensee to resolve this problem, this item is closed with regards to the sequence timing relay problem.
However this inspection reveals that there may be another problem which is associated with the 480 VAC B6 " Auto Transfer" circuit breakers closing spring reset mechanism which may inhibit transfer.
This is unresolved item 87-46-01.
(Updated) Inspection Followup Item 86-17-01 - CAL 86-10 - Iruda tent MSIV Closure and Scram, April 4 and April 12, 1986 For background the inspector reviewed licensee descriptions of the j
events, CAL 86-10, NRC Inspection Report 86-17, and numerous NRC meeting I
reports in which the inadvertent, unplanned MSIV closures and scrams are discussed.
The inspector reviewed licensee actions, analyses, and evaluations conducted since the events.
The licensee is continuing the investigation which now will include highly-instrumented start-up and shutdown tests in attempts to determine i
the triggering cause.
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l The inspector found that the licensee's inspections, analyses, and actions taken since the events have been extensive and exhaustive in attempting to determine the causes of the unplanned MSIV closures and scrams. As of the date of this inspection, in spite of 112 'iogged investigative activities, no concrete cause for the events has been uncovered.
The inspector reviewed the licensee's current investigative activities and plans which include running Test Procedure 86-81.
Conduct of this test will attempt to duplicate, under controlled conditions, the plant conditions during which the two events occurred in order to determine if they will reoccur.
The inspector reviewed Test Procedure 86-81, test instrumentation and test points to assess their adequacy for detecting the types of triggering causes which might lead to the unplanned MSIV closures l
and scrams.
The test will utilize General Electric Transient Analysis Recording System (GETARS) equipment.
Twenty-eight individual instruments-tion digital channels will monitor the multiple plant signals for the i
following parameters:
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Reactor Low-Low Water Level
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Main Steam Line Low Pressure
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PCIS Group I Isolation Relay
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Reactor High Water Level
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Main Steam Line High Radiation
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These signals will be derived from unused " dry contacts" on the associated l
relays wired out to terminal blocks and monitored by the GETARS.
By tak-j ing the signal from unused ontacts, there will be no effect on the normal J
plant signal circuits.
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In addition, there will be eight individual instrumentation analog channels which will monitor the mode selector switch bypass circuitry.
These signals will be derived from the circuits by the use of appropriate signal isolation devices to prevent any adverse or distorted affect on the i
normal plant signals.
l This item will remain open for the continuing investigative effort.
j Reevaluation will be made at the conclusion of Test 86-81.
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(Closed) Inspector Followup Item 293/85-11-03 - Determination of the Type of Cracking on the Inlet Recirculation Nozzle Thermal Sleeves A December 4,1984 letter (1.84.357) from H. Denton (NP.R) to W. Harrington (BECo) concludes that the actions required by the l
August 26,1983 "IGSCC inspection order confirming shutdown" were satis-factorily completed.
The licensee in this letter was requested to l
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continue study of the cracking mechanism on the recirculation inlet nozzle sleeves.
One purpose of this study was to confirm that this cracking was due to Intergranular Stress Corrosion (IGSCC) to establish that mitigation methods for IGSCC (for example hydrogen addition to the reactor coolant
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water) would be effective in controlling further crack growth of the thermal sleeves.
On January 2,1987 BECo letter (2.87.003) from J. Lydon to H. Denton transmitted the thermal sleeve cracking mechanism study results that
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concluded the most likely cracking mechanism of the recirculation nozzle i
thermal sleaves to be IGSCC. Hydrogen Water Chemistry (HWC) was chosen l
as the method for mitigation of IGSCC.
The NRC inspector reviewed the i
General Electric (GE) report titled " Pilgrim Nuclear Power Station Recir-I culation Inlet Thermal Sleeve Mockup Fabricat ion and Evaluation," dated October 1986 and noted that by mockup testing and analysis GE established the thermal sleeve cracking to be IGSCC.
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With the thermal sleeve cracking mechanism established as IGSCC and the
Hydrogen Water Chemistry IGSCC mitigation method institutea, the control I
on further thermal sleeve crack growth should be effective.
The inspector I
observed the hardware in place provides for the generation or supply of hydrogen, for injection of hydrogen into the feedwater, for measurement of a
hydrogen and oxygen content in reactor water and reviewed provision for recombination of hydrogen with oxygen under controlled conditions.
The inspector also examined the crack arrest verification system (CAVS) which will monitor reactor water chemistry and electro chemical potential and I
crack growth rates of test specimens in actual reactor coolant
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environment.
The inspector concluded that the licensee had provided sufficient study to confirm that recirculation nozzle thermal sleeve cracking was most likely IGSCC and that provisions to provide for IGSCC mitigation by HWC are in progress.
This item is closed.
3.0 Generic Letter 84-11 (GL 84-11) - Actions Taken by BECo on IGSCC Susceptible Piping
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During the refuel outage No. 6 (RF0 No. 6), IGSCC susceptible piping i
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l RHR, core spray and RWCU lines were replaced. A total of 156 welds and l
l related susceptible pipe were removed leaving 125 susceptible welds
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including one jet pump instrument nozzle weld with an overlay. Of the 125 susceptible welds, all but four were UT inspected during RF0 No. 6.
At the conclusion of RF0 No. 6, only one weld was known to contain IGSCC and this weld was weld overlayed to provide for structural integrity.
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The program for GL 84-11 implementation during RF0 No. 7 is detailed in BECo letter 87-071 dated May 6, 1987.
The inspector reviewed portions of this program noting the provision to have more than 20s of the susceptible I
i welds previousiy examined in RF0 No. 6 reexamined by UT during RF0 No. 7.
l Two of the four welds not examined in RF0 No. 6 were to be examined in RF0 No. 7, one by RT and one by UT.
The remaining two welds are not ac-cessible.
Of the IGSCC susceptible welds exandned doHag RF0 No. 7, non indicated new IGSCC or growth of existing IGSCC.
The results of radiographic and ultrasonic examinat.;ns conducted to meet Generic Letter 84-11 requiremerits for RF0 No. 7 are contained in the BECo ISI report dated August 11, 1987.
Review of ISI records, GL 84-11 requirements applicable to the Pilgrim plant and interviews with ISI and control room operators verified the following GL 84-11 related conditions.
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Induction Heating Stress Improvement (INSI) has not been selected as an IGSCC mitigation factor at the Pilgrim Plant, therefore the GL 84-11 rules on IHSI treated pipe are not applicable.
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Visual examination of reactor coolant piping is performed after each outage where the containment is deinerted unless this inspection has been performed during the previous 92 days in accordance with the partial relief dated February 12, 1986.
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The UT examiners performing IGSCC examinations are qualified by l
formal capability demonstrated testing such as that conducted at
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EPRI.
The qualification of UT examiners is also discussed in Inspection Report No. 293/87-05.
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Level 1 UT personnel art required to work under the supervision of
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Level II or III personnel.
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The current daily surveillance log, Procedure 2.1.1b, page 9 specifies that plant shutdown shall be initiated when the rate of unidentified leakage increases by more than 2 GP cver a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.
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The current technical specification requires shutdown within 24
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hours if the unidentified leakage into primary containment exceeds 5 GPM. This requirement is implemented by Procedures 2.1.15 and 2.2.77 by providing for drywell unidentified leakage measurement every four hours.
These two procedures were revised during inspec-tion 293/87-46 to clearly require plant shutdown to be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the containment sump collection and flow monitoring system become inoperable.
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B
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UT test records for 28" (2RHIB-8),18" (10R-1B-14) and 10" (14-B-17)
I were checked to confirm that welds designated for examination were examined.
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The purchase order requirement for the UT contractor and documentation for six UT examiners were reviewed to confirm suitable qualification to the requirements of GL 84-11.
The current program provides for inspection scope expansion in l
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accordance with the rules of IEB 83-02 in the event that new cracks are identified or if existing cracks show significant growth.
The augmented inspection program for GL 84-11 IGSCC examinations subsequent to RF0 No. 7 provides for expansion of the sample size if cracks are identified in accordance with the ASME Code,Section XI, Paragraph IWB-2430.
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The inspector concluded that the requirements of GL 84-11 have been adequately addressed at the Pilgrim Plant.
4.0 Exit Meeting The inspector met with the licensee's representative (identified in paragraph 1.0) at the conclusion of the inspection of October 9, 1987, to summarize the findings of this inspection.
The NRC Resident Inspectors, J. Lyash and T. Kim, were also in attendance. A second exit meeting was
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held by E. H. Gray on October 23, 1987.
I During this inspection, the inspector did not provide any written material to the licensee.
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