IR 05000293/1990005
| ML20042D718 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 03/22/1990 |
| From: | Eapen P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20042D716 | List: |
| References | |
| 50-293-90-05, 50-293-90-5, NUDOCS 9004050158 | |
| Download: ML20042D718 (19) | |
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U.S. NUCLEAR REGULATORY COMMIS$ ION
REGION I
i Docket No.:
50-293
Report No.:
50-?93/90-05 i
t Licensee:
Boston Edison Company
800 Boylston Street Boston, Massachusetts 02199
. Facility:
Pilgrim Nuclear Power Station i
Location, Plymouth, Massachusetts
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Dates:
January 16 - March 8, 1990 Inspectors:
J. Macdonald, Senior Resident Inspector i
T. ; erne, Resident Inspector
C. Carpenter, Resident Inspector
H. Eichenhoir, SRI - Vermont Yankee i
R. Freudenberger, RI - Maine Yankee i
R. Barkley, Pro t Engineer, RI
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J[.Irapp,SeirR ctor Engineer, RI E
rotti r, Ofp e of Nuc ear Reac r Regulation
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Approved by:/ /> -
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apen, Chief,ReactorPrpetsSection3A Y Date'
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Ins
~ pection Summary:
Ins l>T)jecticn on January 16 - March 8.1990 (Report No,
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29T/IB-05)
Areas Inspected:
Routine safety inspection of plant operations, maintenance /
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l surveillance and operational safety was performed by resident and region-based
inspectors (237 hours0.00274 days <br />0.0658 hours <br />3.918651e-4 weeks <br />9.01785e-5 months <br />). The licensee training to institute the Fitness-For-i Duty Rule (Temporary Instruction 2$15/104), the licensee response to NRC Bul-letin 87-02 (TI 2515/27) and the licensee implementation of two previous TMI
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Tast Action Plan Items were also reviewed.
Results:
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General Conclusions on Adequacy. Strengths or Weaknesses in Licensee Programs
Although engineering technical evaluation of the instrument line excess
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flow check valve issue was well supported by design bases documentation.
l the licensee failed to address the fundamental question of not verifying
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operability of these check valves as required by Technical $pecification.
It should be noted that failure of an excess flow check valve is an evalu-
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ated FSAR scenario which presents minimal safe +y significance, i
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i 9004050158 900328 I
l PDR ADOCK 05000293 Q
PDC j
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However, subsequent licensee actions following the inoperability deter-mination were comprehensive and well coordinated.
The licensee request for temporary relief from technical specification requirements was of suf-ficient technical content to support NRC issuance of discretionary en-forcement permitting continued operation through the March mini-outage (section 6.1).
The licensee has demonstrated a continuing conservative approach to the resolution of the salt service water pump discharge column circumferential fracture event. Extensive destructive and non-destructive examination techniques have been employed to definitively ascertain the metalurgical properties of the remaining installed discharge columns. Additionally, the licensee has provided frequent examination status reports to the resi-dent staff and regional metallurgical specialists (section 6.2).
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Violations One violation was identified for licensee failure to adequately verify the operability of instrument line flow check valves by satisfactory comple-tion of surveillance testing as required by Technical Specifications (sec-tion 6.1, NC4 90-05 01),
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Unresolved Items One unresolved item was identified to review the adequacy of the licensee investigation of the processes which resulted in the instrument line flow check valve non-compliancs (section 6.1, UNR 90-05-02).
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TABLE OF CONTENTS PAGE 1.
Persons Contacted....................................................
I 2.
Summary of Facility Activities.......................................
3.
Status of Previous Inspection Findings (IP 92700,92702,93702*).....
3.1 (Closed) TMI Task Action Plat Item II.K.3.18.C. ADS Modification..................................................
3.2 (0 pen) TMI Task Action Plan Item II.B.3, Post Accident Sampling System Capab111ty.............................................
3.3 (Closed) Violation 89-07-03, Changeout of Control Room Label Plates without a Controlling Document or MR...................
3.4 (Closed) Violation 89-07-02, Failure to Perform an Adequate Review o f a Surveillance Procedure............................
4.
Operational Safety (IP 71707,42700).................................
4.1 Plant Operations Review.........................................
4.2 Safety System Review............................................
5, Security (IP 71707 TI 2515/104).....................................
5.1 Observations of Physical Security...............................
5.2 Inspection of Fitness for Duty Training Program.................
6.
Plant OperaticAs (IP 71707,93702,61700,61726).....................
6.1 Discretionary Enforcement.......................................
6.2 Brittle Fracture of "A" Salt Service Water Pump Column..........
7.
Maintenance / Surveillance (IP 61726,62703,42700)....................
7.1 High Pressure Coolant Injection Pump Discharge Valve Position Indication....................................................
Il 7.2
"B" Emergency Diesel Generator Voltage Regulator Malfunction....
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Radiological Section (IP 71707)......................................
8.1 Radwaste and Chemistry Section Reor
ALARA Review.......................ganization...................
8.2
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9.
Engineering / Technical Support (TI 2500/027)...........................
9.1 Review of Licensee Response to Bulletin 87-02, " Fastener Testing").....................................................
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Table of Contents
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10. Review of Periodic and $pecial Report s (IP 71707)....................
i 11. Management Meetings (IP 30703,40500,35502).........................
- The NRC Inspection Manual inspection procedure (!P) that was used as inspec-tion guidance is listed for each applicable report section.
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i DETAILS i
f 1.0 Persons Contacted Interviews and discussions were conducted with members of the licensee
staff and management during the report period to obtain information per-
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tinent to the areas inspected.
Inspection findings were discussed peri-
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odically with the management and supervisory personnel listed below.
i K. Highfill, Vice President, Nuclear Operations and Station Director i
R. Anderson, Plant Manager l
0. Eng, Outage and Planning Manager
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E. Kraft, Deputy Plant Manager
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R. Fairbenks, Nuclear Engineering Department Manager i
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D. Long, Plant Support Department Manager
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L. Olivier, Operations Section Manager i
N. DiMascio, Radiological Section Manager
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J. Seery. Technical Section Manager G. Stubbs, Maintenance Section Manager
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T. Sullivan, Chief Operating Engineer J. Neal, Security Division Manager
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W. Clancy Systems Engineering Division Manager
B. Sullivan, Fire Protection Division Manager l
2.0 Summary of Facility Activities i
Pilgrim Nuclear Power Station (PNPS, Pilgrim, the licensee, or the plant)
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continued full power operations during this report period.
Throughout the
period, short term scheduled power reductions to about 90% of full power were conducted to perform routine surveillances of control rod drives. On
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February 9, power was reduced to about 50% to backwash the main condenser.
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The unit was returned to full power on February 11.
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On January 20, the licensee notified the NRC Operations Center via com-mercial telephone that the Emergency Notification System (ENS) was not
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functioning as intended.
This notification was made in accordance with 10 (
CFR 50.72 criteria. Notification via the ENS was also made on February 9 when the licensee declared two instrument line excess flow check valves I
inoperable due to failure to perform the Technical Specification surveil-
lance within the required time interval (Section 6.1).
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By letter dated February 12, 1990, the NRC provided acceptance of the Boston Edison Company (BECo) completion and self-assessment of the power i
ascension test program, as well as release from Confirmatory Action Letter f
86-10 and its supplements. The staff concluded that management perform-ance, plant material condition, and operational performance supported pro-l ceeding with normal operation of the facility.
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On the evening of February 21, 1990, Region I Division of Reactor Projects management responsible for the inspection program at PNPS, attended a Plymouth Selectmen muting and presented town officials with a summary of NRC activities which led to the issuance of the February 12, 1990 letter.
3.0 Status of Previous Inspection Findings 3.1 (Closed) TMI Task Action plan Item II.K.3.18.C. ADS Modification The inspector reviewed the circumstances and supporting documentation and verified that this item was completed by Pilgrim Station. Tech-nical Specification Table 3.2.B and the applicable bases section were revised to reflect this modification to the ADS system.
In addition, completion of this item was documented in BEco letter 89-056 dated April 18, 1989.
The inspector reviewed Pilgrim procedures 2.2.23. " Auto Depressuri-zation System" and 8.M.2-2,10.9.1, " ADS Logic RX Other Than Shutdown" to verify that the modification had been incorporated into station procedures and its logic system is tested to verify operability.
No discrepancies were identified.
In addition, the system reference manual also included a description of this modification. Based on the above, this item is closed.
3.2 (Update) TMI Task Action Plan Item II.B.3. Post Accident Sampling Capability Recent events and equipment performance problems resulted in the lic-ensee's design review of the post accident sampling system (PASS).
According to Amendment No. 85 to the Facility Operating License, issued on December 17, 1984, the licensee was to install a PASS that met the requirements of NUREG-0737, Item II.B.3 by June 30, 1985.
The licensee design review, which included a comparison of the in-stalled system and capabilities to the requirements of NUREG-0737, Supplement No. 1, and Regulatory Guide No. 1.97, identified an issue involving the on-site chemistry facilities, which are used to analyze the reactor coolant samples obtained by the PASS. Although the PASS has backup power supply capabilities to ensure the retrieval of samples during design basis accident conditions, it appears that the chemistry facilities do not have this backup power supply capability.
Criterion (1) of NUREG 0737. Item II.B.3, specifies that the combined time alloted 1or sampling and analysis should be three hours or less from the time a decision is made to take a sample. The licensee de-sign reviewer's concern was the ability of the chemistry facilities to analyze a sample within the specified time, without having a back-up power supply.
In BEco letter 85-102, dated May 30, 1985, the lic-ensee stated in response to NRC questions pertaining to Criterion (1)
that system testing indicates that a sample can be obtained, trans-ported and analyzed in three hours or less from the time a decision
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is made to take a sample.
This statement was reflected in the NRC Safety Evaluation Report for NUREG 0737, Item II.B.3 issued on July l
1,1985, which concluded that the licensee met Criterion (1),
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In response to the licensee self-identification of this issue, Poten-tial Condition Adverse to Quality (PCAQ) 90-12 was issued to track
and resolve the matter.
The licensee is currently evaluating an
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operability determination for the PASS based upon the identified issue. The inspector will follow this item dueing routine inspec-tion.
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3.3 (Closed) Violation 89-07-03. Changeout of control Room Label Plates without a Controllino Document or Maintena.ae Request An NRC insnector observed the licensee staff replacing labels on con-
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trol room panels without proper administrative controls. Questions l
were raised by the inspector regarding the ability to maintain con-sistency among procedures, drawings and component labels in absence
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of administrative controls. Additional concerns were raised regard-ing the lack of an independent verification of label installation.
The licensee addressed these concerns by suspending the labeling pro-cess until administrative controls were established.
Procedure 1.3.79, " Operations Equipment Labeling," was developed to administra-tively control labeling of components.
Procedure 1.3.79, section 4.1
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requires a review be performed to assure consistency between design documents, procedures and component labels.
Independent verification for installed labels is performed in step 6.2[1](b).
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control for label changes is documented on a label request form.
l The inspector restawed the labeling controls procedure and found the controls established were adequate.
A check of the labeling control process for selected comoonents was performed which indicated com-pliance with the operations equipment labeling procedure. Based on the above inspection, this item is closed.
3.4 (Closed) Violation 89-07-02. Failure to Perform an Adequate Review of a Surveillance Frocedure Temporary Procedure TP 88-78, " General Electric CR 2820 Time Delay Relays for ADS, CS, RHR. and RPS System," was approved without an adequate review, the approved procedure had incorrect relay numbers, as identified by the licensee during the test.
In addition, technicians had completed procedure steps with incorrect relay numbers, without stopping and initiating procedure changes. A review of the current revision of TP 88-78, expiration date 7/13/90, found that the relay numbers in question had been correcte *
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The licensee also provided a memorandum to all Pilgrim Station employees i
and contractors emphasizing the corporate commitment to strict adherence
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to procedures, and restating the requirement to stop and revise inaccu-
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rate procedure steps. The inspector found that the corrective actions taken were appropriate. This item is closed.
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4.0 Operational Safety
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i 4.1 Plant Operations Review
The inspector observed plant operations during regular an shift I
tours of the following areas.
- Control Room Fence Line (Protected Area)
l Reactor Building Intake Structure i
Diesel Generator Building Turbine Building
Switchgear Room
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Control room instruments were observed for consistency between channels, function and conformance with Technical Specifications.
Existing alarm conditions in effect and alarms received in the control room were re-
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viewed and discussed with the operators. Operator awareness and re-
sponse to these conditions were reviewed.
Operators were cognizant of board and plant conditions. Control room and shift staffing were com-pared with Technical Specification requirements.
Posting and control of radiation, contaminated and high radiation areas were inspected.
Use of and compliance with radiation work permits and use of required per-
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sonnel monitoring devices were checked.
Plant housekeepitig controls, including control of flammable and other hazardous materials, were ob-served.
During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were cor-
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rectly made and to verify correct communication of equipment status.
These records included various operating logs, turnover sheets and
tagout and jumper logs.
Overall conditions were found to be acceptable.
In addition, operators and shif t supervisors were ciert, attentive and responded appropriately
to annunciators and plant conditions. A professional atmosphere was observed to be maintained in the control room.
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4.2 Safety System Review Portions of the emergency diesel generators, reactor core isolation
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cooling, core spray, residual heat removal, salt service water, safety-
related electrical, and high pressure coolant injection systems were reviewed to verify proper alignment and operational status in the stand-by mode. The review included verification that (1) accessible major flow
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path valves were correctly positioned; (2) power supplies were energized;
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(3) lubrication and component cooling were adequate; and (4) components were operable based on a visual inspection of equipment for lensge and general conditions. No violations or safety concerns were identifie !
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i 5.0 Security 5.1 Observations of Physical Security selected aspects of plant physical security were reviewed during regular and backshif t hours to verify that controls were in accord-ance with the security plan and approved procedures. This review
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included the following security measures: guard staffing, vital pro-l tected area barrier integrity, maintenance of isolation zones, and implementation of access controls, including authorization, badging,
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escorting, and searches. No inadequacies were identified.
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5.2 Review of NRC Temporary Instruction 2515/104 - Inspection of
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Fitness for Duty (FFO) Training program On June 7, 19P9 the NRC published the final rule and statement of f
policy on fitness for duty programs for commercial nuclear power reactors, with an effective date for program implementation of January 3,1990. Appropriate FFD awareness training for employees,
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supervisors and escorts is required by the rule.
The purpose of this inspection was te determine whether the required training was con-ducted to implement the program.
The inspector reviewed the licensee lesson plans for general employee training and management / supervisor training, including handouts and video slide material to determine the adequacy of the licensee train-ing.
The licensee FFD program presents the purpose of the FFD pro-gram, individual responsibilities with respect to the program, and the frequency and method of substance abuse and alcohol testing, as well as the consequences of possible positive results.
In addition, the availability of the Employee Assistance Program is explained to personnel.
The licensee uses a combination of lecture presentation and video to present the FFD program, including problems associated with drugs and alcohol and recognizing possible drug or alcohol re-lated behavior in personnel. Overall, the licensee initial FFD training program adequately conveyed to the employees, the licensee policy on Fitness for Duty and the possible consequences associated with drug and alcohol use. This Temporary Instruction is closed.
6.0 Plant Operations 6.1 Discretionary Enforcement As reported in Inspection Report 50-293/89-12, Section 5.2, during testing of the approximately 80 instrument line check valves in accordance with procedure 8.M.3-2, " Instrument Line Flow Check Valve Test," one of the valves tested and which failed to seat was a Dragon valve (of which Pilgrim has on?y two installed).
The licensee re-solved the leak rate failure or, one of the Dragon valves through the application of a previous engineering review (NED memo 88-448) which
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reviewed the design of the Dragon check valves.
NED recommended at i
that time that the Dragon valves be accepted as installed without any
,I additional testing until Refueling Outage No. 8 when the check valves
would be replaced with new Dragon valves having a 1 to 2 gpm actu-
ation flow, j
Technical Specification 3/4.7.A.2.b.1.d requires that the operability of the reactor coolant system instrument line flow check valves be verified at least once per operating cycle.
Further NRC review of the failure of the one Dragon valve to actuate during tN October 1989 outage and the decision not to test the other check valve re-
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vealed that these two excess flow check valves had not been satis-factorily tested since vendor testing prior to original purchase of
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the valves in May 1986.
The two Dragon excess flow check valves l
(263-2-125 A&B) cannot be successfully verified operable as installed
because sufficient actuation flow is not attainable due to instrument line configuration and downstream piping restrictions.
Failure to verify the operability of the two instrument line flow check valves at least once per 18 months in accordance with Technical Specifica-
tions is considered a violation (VIO 90-05-01).
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The two Dragon excess flow check valves were purchased and installed in accordance with Plant Design Change (PDC) 85-07, Reactor Vater Level Instrumentation Modification.
This PDC installed two new cold reference legs outside the drywell to replace existing Yarway heated reference columns located inside the drywell for reactor water level instrumentation.
The two valves were purchased for PDC 85-07 in accordance with Specification Number M-561.
Section 4.0 of spect-fication no. M-561, Design Requirements, paragraph 4.1 states that t
" valves manuf actured in accordance with this specification are in-
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tended to operate by closing when flow in the reactor water level
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sensing line exceeds 2 gpm as a result of a line break cutside of containment." Paragraph 9.2 states that " control requirements are that the valve closes on a flow of 2 gpm."
Since the purchased check valves were tested by the manufacturer and determined to actuate /
l close when flow reaches 5 to 6 gpm it appears that the valves d a
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not meet the original design specification.
i Following installation of the new cold reference legs in December, 1987, the licensee performed an instrument line flow check valve test
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in accordance with procedure 8.M.3-2.
The two newly installed cSeek
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valves failed to seat during the test.
In response to ESR 88-401 to e
provide acceptable seat leakage criteria, NED issued ESR Response Memorandum (ERM)88-606 on July 22, 1988.
The ERM noted that the tested actuation or closing flow for the Dragon valves was 5 to 6 gpm
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and due to the high actuation flow it will be difficult to perform i
in-line leak testing of the Dragon valve due to pipe /tubinr, restric-tions.
The ERM also stated that since the Dragon valves were bench tested by the vendor for leak rate under the Dragon QA Program and i
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the test report was provided as part of the "Q" documtitation pack-age, in-line tecting of the Dragon valves could be waived for that outage. NED stated that further engineering analysis of the Dragon valves was required to confirm that the 5 to 6 gpm actuation flow
satisfied'the FSAR requirements.
Subsequent NED review of the Dragon excess flow check valves, docu-
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mented via NED Memorandum 88-448 dated July 29, 1988, recommended that the check valves be accepted as installed without any additional testing for the next operating cycle, but be replaced during RF0 #8 because the installed valves were a testing problem and not a safety problem. NED review of the FSAR indicated that a leakage of up to 20
gpm into the reactor building had been evaluated to be well withh
the capability of the reactor coolant make-up system and radiological consequences are substantially below 10CFR 100 limits.
Jr Subsequently, during performance of procedure 8.M.3-2 on November 3, 1989, (Inspection Report 50-293/89-12), one of the two Dragon check valves failed to seat. The resolution to the failed surveillance 1-test on this valve (ERM 89-1066 dated November 3, 1989) was that the
previous NED Memo 88-448 applied to the Dragon valves.
Consequently, surveillance procedure 8.M.3-2 was signed off as acceptable based on
the previous ERM 88-606.
In addition, Failure and Malfunction Report (F&MR)89-422 on excess flow check valve 263-2-125A not seating was closed out by the Compliance Division as not significant and not re-portable.
No root cause analysis was required even though the F&MR identified that this valve was Technical Specification related. The close out of the F&MR states that the valve failure was not " port-able since the problem involved testing and not a safety prot,lem.
The F&MR closeout did not eddress the TS compliance aspect.
In both cases of failure to meet the acceptance criteria of the sur-veillance procedure, in December 1987 and October / November 1989, al-though review of the FSAR was conducted to determine the safety sig-nificance of the operability of these valver. the licensee failed to m
recognize and consider the Technical Specif aation requirement to veH fy the operability of these valves.
Following NRC review and discussion of the surveillance requirements
of these valves, the licensee began investigating the testing re-
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quirements per Technical Specification and the possibility that the 18 month surveillance per adicity had been exceeded.
Subsequently, the licensee initiated ESR 90-032 dated January 24, 1990 questioning the basis for referencing NED memo 88-448 recommen-dation that the valves be accepted as-is without further testing and
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suggested as a possible solution either the safety evaluation for PDC 85-07 be revised as a basis for Technical Specification relief or the actual surveillance be determined based on time of first use and re-place the valves during the mid-cycle outage.
ERM 90-90 responded to
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this E$R that the Dragon valves will be replaced during the scheduled March outage and that a Technical Specification interpretation was being investigated. A T$ clarification was prepared, citing that TS 3/4.7.A.2.b.1.d does not specifically list the valves to which the surveillance requirement applies and that valves 2-CK125 A&B maybe excluded from the purview of TS 3/4.7 A.2.b.1,d without degradation of the safety of the plant or the health and safety of the public.
Although the clarification, based on an NED memo, analyzes the safety aspects of these excess fluw check valves with respect to the FSAR, neither NED or other management personnel, acknowledged the TS re-quirement to verify these valves operable each operating cycle. The Operations Review Committee (ORC) upon reviewing the proposed TS clarification, rejected use of this method to address a TS compliance issue.
Af ter f urther NRC questioning on this issue, on February 9,1990, the licensee declared the two Dragon instrument excess flow check valves inoperable as these valves were not tested within their prescribed testing intervals.
The NRC operations center was notified via ENS at 7:25 p.m.
The licensee requested and was granted by the NRC discretionary en-forcement relating to TS surveillance testing for instrument line excess flow check valves. This action granted relief from TS 4,7. A.2.b.1.d. which requires operability verification of the instru-ment line flow check valves 2-CK125 A&B once per operating cycle until the outage currently scheduled to begin on March 9, 1990.
The granting of discretionary enforcement by the NRC was based on the minimal safety significance in the failure to perform the required TS surveillance. The Final Safety Analysis Report describes the con-sequences of a guillotine break of the instrument line upstream of the excess flow check valve located inside primary containment. This failure would result in a leak of 20 gpm to the secondary contain-ment; the flow limitation being strictly due to an upstream flow orifice.
This leak rate is well within the capability of the reactor coolant makeup system and, therefore, does not present a safety hazard to the reactor coolant inventory. Additionally, this flow does not endanger the integrity of the reactor building since there would not be any significant pressure rise due to the relatively high reactor building ventilation exhaust rates and the operation of one standby gas treatment filter train will prevent reactor building pressure from exceeding its design value.
Finally a leak rate of 20 gpm results in a site boundary exposure which is substantially below a
the criteria of 10 CFR 100.
Consequently, there was no adverse im-pact to the public health and safety in the granting of the Discre-tionary Enforcement.
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The discretion was contigent upon the 11censeo performing che follow-ing compensatory measures: (1) control access to the vicinity of the lines from the check valves to the instrument racks; (2) control work and maintenance in the area of lines from check valves to instrument racks; (3) prepare a standing Radiation Work Permit to allow opera-tions personnel to isolate root valves if required by a line break downstream of the check valve; and (4) inspect the affected lines for leakage each watch. The inspector verified that these actions were implemented.
The licensee plans to replace these two instrument line flow check valves during the March outage; the license is also conducting an investigation inte the events that led to the licensee request for Enforcement Discretion.
Licensee actions with respect to this issue have been inappropriate and not oriented towards compliance with Technical Specification surveillance requirement.
During performance and review of procedure 8.M.2-3 in December 1987 and subsequent ESR's and November 1989, the licensee failed to comply with station proce-dures and instead used an engineering document to change an approved procedure. When it became apparent that there was a TS compliance issue involved, the licensee inappropriately chose to attempt to clarify the technical specificatior, and exclude these valves from the TS surveillance requirement. Although ORC rejected the TS clarifica-tion, it appears ORC attempted to determine an alternative to the clarification rather than address the TS compliance issue.
In November 1989 the licensee processes appeared to have failed in that an engineering memo was used as basis to sign off on a surveillance as acceptable and allow plant startup when the F&MR addresses that a TS item is involved.
In three instances, in the summer of 1983 be-ginning with ERM 88-606, November,1989 and early 1990, the Ikensee processes appeared not to identify and prevent the non-compliance with Technical Specification 3/4.7. A.2.b.1.d.
However, licensee aC-tions following the inoperability determination were comprehensive and well-coordinated.
Until further information is established for the original purchase and installation of the Dragon valves in accordance with the PDC and the licensee completes the actions with respect to the failure to verify operability of these two excess flow check valves and the apparent failure to recognize and comply with Technical Specification requirements, this is an unresolved item (90-05-02).
6.2 Brittle Fracture of
"A" Salt Service Water Pump Column On January 11, 1990 while transporting an assembled Salt Service Water (SSW) pump from the maintenance shop to the intake structure for re-installation, the bow 1/ impeller end of the "A" SSW pump was dropped approximately 6 to 12 inches.
This led to a 360 degree throughwall fracture of the second, 80 inch column section from the bowl / impeller end.
The operability concern was that the remaining
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pumps in service (there are a total of five $$W pumps) may have columns with similar material properties that could affect operabil-ity under design loading conditions.
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Subsequent licensee visual and metallurgical examination showed the column apparently did not experience anticipated plastic deformation
and failed by brittle fracture.
The area of the fracture had reduced
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material properties (e.g., yield strength, ultimate strength, percent elongation) relative to specification.
The licensee considers two factors to have contributed to the fracture of the column.
First, the initial casting process likely produced a susceptible material, caused by slow cooling of the casting.
This likely produced a mate-rial in which the required single phase of the material was not achieved, producing a "eutectoid" condition. With the continued exposure to sea water, de-alloying of the material occurred.
Second, a pre existing crack due to weld build-up in the upper flange region existed. The existing flaw provided an initiation site for the frac-l ture.
The de-alloyed condition caused the embrittled-type properties
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in the failed material making it susceptible to brittle fracture.
The high impact load from the drop then caused the 360 degree throughwall fracture.
Visual inspection by the licensee revealed that on three of the SSW pumps, newer column types are installed in various locations.
These improved columns are :entrifugally cast versus sand casting used in the failed column. Also', these columns are cast in two smaller pieces which. allows for more uniform cooling and reduces shrinkage and porosity concerns.
The licensee performed ultrasonic testing of the uppermost section of pump. "A" to verify minimum wall requirements in the area of highest stress.
The results indicated a uniform, acceptable wall thickness.
Liquid penetrant examinations of the out-side diameter of all columns on "A" $$W pump in the flange was per-
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formed.
No cracks were detected.
The "A" SSW pump was subsequently returned to service on February 13, 1990.
The licensee plans the following corrective actions to verify the material and integrity of the remaining $$W pumps.
The remaining
pumps (8,C, D and E) will be inspected and tested in two phases. The
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first phase will consist of external tests and inspections of all columns followed by tie-rod installation on all but the lowest column
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before returning each pump to service.
The inspections and tests in
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the first phase include: (1) ultrasonic testing wall thickness meas-urement in the vicinity of the flanges; (2) visual inspection of the outside diameter; and (3) hardness testing on the outside diameter near the flanges on all areat, not tested previously.
In the second inspection phase, each pump will be removed and dis-assembled to perform the following inspections and tests: (1) liquid penetrant examination on the outside diameter at the vicinity of the
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column flanges; (2) visual inspection of the inside diameter near the
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flanges; (3) hydro test at 125 psig with a 15 minute holding time and (4) liquid penetrant examination on the inside diameter in the i
vicinity of the column flanges, j
Columns found to have degraded properties are planned to be system-atically replaced with satisfactorily tested columns.
If an inser-
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vice salt service water pump becomes inoperable while one salt ser-vice water pump is tagged out of service for inspection and testing and pump column fracture can not be eliminated as the cause, a 24 l
hour Limiting Condition for Operation (LCO) will be entered.
In the
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longer term, newly ordered columns will replace all columns in each i
pump.
l These licensee actions were determined to be comprehensive and con-i servative.
The inspectors will continue to monitor licensee actions
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with respect to the SSW pumps during routine inspections.
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7.0 Maintenance / Surveillance l
7.1 High Pressure Coolant Injection (HPCI) Pump Discharge Valve
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Position Indication i
On January 29, 1990, plant operators were performing a routine system alignment in accordance with procedure 8.M.2-2.10.4.3 "High Pressure
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Coolant Injection (HPCI) Simulated Automatic Actuation (outboard)."
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System realignment preceding the test required the HPCI pump dis-
charge valve (MO-2301-9) to be closed; its normal position is open.
The valve did not indicate closed on the n.ain control board when the operator attempted to clo a it.
The HPCI system was declared in-operable and the NRC was notified using the Emergency Notification
System (ENS) in accordance with 10 CFR 50.72.
Surveillance testing
required by Technical Specifications due to HPCI system inoperability was completed.
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Further review by the Itcensee indicated that the safety function of
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the valve was to be in the open position.
Since the valve was nor-i mally aligned in the open position and there was no indication that the valve would not have opened if required to do so, it had not been
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necessary to declare the HPCI system inoperable.
The licensee made a followup notification to the NRC on January 30, 1990 to retract the
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previous notification.
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The inspector considered operator action to declare the HPCI system inoperable for these circumstances to be conservative.
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7.2
"B" Emerger.cy Diesel Generator Voltage Regulator Malfunction On February 6, 1990, during routine surveillance of the "B" Emergency Diesel Generator (EDG) per procedure 8.9.1, " Manually Start and Load Each OG Once Per Month " the reactor operator observed load swings between 400 KW and 2500 KW following operator adjustment of the
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l governor speed and voltage regulator setpoint.
Following the ob-
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served voltage swings, the ED3 output breaker automatically opened, I
tripping the EDG.
Failure and Malfunction Report (F&MR) 90-23 was t
initiated. The licensee determined that the ED3 output breaker tripped open on reverse power protective relaying.
The "B" EDG was declared inoperable and Maintenance Request (MR) 90-61-11 was issued
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to perform further investigation.
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Licensee troubleshooting activities were unable to identify the cause
cf the anomalous E03 performance.
Subsequent performance of proce-
dure 8.4.1 and other troubleshooting did not cause a repeat of the load swings and the procedure was successfully completed.
No further
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deficient performance of the "B" EDG was experienced and the "B" ED3 was subsequently declared operable.
On February 8, 1990 during perf;,rmance of procedure 8.9.1 as part of l
preparation for the removal of the other plant equipment from service and following startup of the EDG, the operator observed oscillations
in the generator output voltage wiiile manipulating the voltage regu-lator (VR) setpoint control.
The "B" ED3 was again declared inoper-able.
F&MR 90-31 and MR 90-61-14 were initiated to document and con-trol the maintenance activities.
Licensee troubleshooting activities identified deficient performance characteristics in the VR circuitry.
Although adjustments of certain VR components resulted in the VR per-forming in an adequate manner, the licensee believed that the adjust-ments made were masking more significant equipment deficiencies,
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This concern resulted in the replacement of the inservice voltage regulator with a spare unit.
The "B" EDG was returned to service on l
February 9,1990, following successful completion of ti.e 8.9.1 sur-veillance test.
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Additional corrective actions by the licensee in response to the re-
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cent "B" EDG performance issues include: (1) maintain the EDG on a biweekly accelerated surveillance schedule as an added confidence
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factor that further maintenance is not warrented; (2) have the manu-i facturer of the VR perform an indepth failure analysis of the removed
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unit; and (3) complete the root cause/ corrective action analysis and documentation requirements of the F&MR process.
The investigations of the cognizant sytems engineer, as part of the
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licensee corrective actions response identified two potential items of concern.
The first involves minor "B" EDG output voltage drifting t
that necessitates reactor operator adjustment of the VR every fifteen
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to twenty minutes of operation while the t,iit is in a manual mode.
Because the replacement VR unit installed on February 9, 1990 had a shelf life of approximately 11 years, the licensee was addressing r
shelf life related issues with the manufacturer.
The second concern involved the "B" EDG room supply and exhaust fans, VSF 208B and VEX 2148 respectively, being operated continuously. A January 1, 1990
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initiated MR (90-24-3) documented this equipment deficiency. This
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condition, along with seasonnally low outside air temperatures re-sulted in the "B" EDG room experiencing temperatures below 50 degrees F.
The specific concern involves the viscosity of the oil used in
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the "B" EDG governor unit, which has a low temperature limit of 80 degrees F.
Potentially, out of specification oil temperatures in the governor could result in sluggish or unstable speed control of the
"B" EDG.
The inspector reviewed recent procedure 8.9.1 surveillance
results and noted that when the EDG was operated a number of times in
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January and February,1990, that the room ambient temperature was
recorded as less than 50 degrees.
Not withstanding this condition,
the EDG each time successfully started with output breater closure l
within required time limits. Although this governor unit is affected
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by the ambient room temperature, the greater than 100 degree F operat-
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ing temperature of the EDG's jacket water cooling system has appar-l ently precluded this condition from adversely influencing the per-
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formance of the EDG governor.
Since the above described condition was less than optimal and the fact that as of February 22, 1990 the "B" EDG room ventilation system
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was still malfunctioning in a continuous operating mode, the inspec-tor discussed these concerns with cognizant systems engineering and operations management representatives.
Immediate corrective actions were initiated to mitigate the identified concerns.
l Licensee response to the investigation and repair of "B" EDG due to
the malfunctioning of its VR indicated a good safety perspective, r
with timely and appropriately implemented corrective actions.
The
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involvement of systems engineering personnel in responding to off
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normal equipment performance continues to be viewed as a licensee
strength.
However, the circumstances that caused the above 6egraded i
environmental condition in the "B" EDG room not to receive timely
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management attention for resolution were not fully assessed and
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established.
l 8.0 Radiological Controls i
8.1 _Radwaste and Chemistry Section Reorganization i
t On February 5,1990, the Radwaste and Chemistry Section initiated a
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reorganization which eliminated the Program Services Division (PSD).
l The responsibilities of the PSD have been assumed by the Chemistry t
and Radwaste Divisions. Additionally, the Radwaste and Chemistry l
Section Deputy Manager position was abolished.
The effectiveness of
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the reorganization will be evaluated during routine inspection acti-
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vities.
The inspector h&d no questions.
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8.2 ALARA Review j
The inspector reviewed the following reports:
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ALARA Committee Meeting Minutes (12/21 - 12/29/89)
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ALARA Outage Report -- October / November 89 Mini-Outage
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The Pilgrim 1989 exposure goal was 225 man-rem; the licensee actua)1y expended 212 man-rem (the industry average BWR exposure was 472 man-rem for 1989).
In addition, the licensee 1990 goal of 185 man-rem represents a challenging goal for the licensee to strive towards con-sidering a 6-week outage is included.
During the planning phase for the October 1989 mint-outage, an ALARA specialist was dedicated for review of each outage item.
During these reviews, the ALARA specialist made recommendations to the per-forming group in an effort to minimize impact during the performance of the job.
Also during the outage, the staff was augmented to pro-vide round-the-clock coverage. With ALARA as part of the planning and outage department, requirements were easily integrated into the work clans.
For planned outage tasks, no exposure estimates were exceeded.
For three jobs that were emergent work and exceeded their exposure estimates, the ALARA group conducted post job review meet-ings to develop " Lessons Learned."
In conclusion, the ALARA group performance was particulary noteworthy during the previous October outage in the area of planning and the licensee commitment to further reduce personnel, exposure in 1990 is also noted.
9.0 Engineering / Technical Support 9.1 Review of Licensee Response to Bulletin 87-02, " Fastener Testing" - Tl 2500/6P7 The inspector reviewed the licensee responses to NRC b iutin 87-02 and Supplements 1 and 2, in accordance with the requincents of Tem-porary Instruction 2500/027.
The responses, dated January 11, 1988 and July 20, 1988, indicated that the licensee complied with all the actions outlined in the Bulletin and its supplements.
The only note-worthy finoings as a results of the review were deviations in the hardness properties of various non-safety-related fasteners.
In accordance with TI 2500/027, the inspector reviewed the licensee engineering evaluation of the noted hardness deviations with the re-sponsible engineer.
Review of the six hardness deviations noted with the non-safety-related fasteners indicated that all but one of the deviations were within or near the testing accuracy of the hardness measuring equipment. Only one deviation (fastener 2NQB9 - ASTM A307 Gr. B) was found to have a significant hardness deviation (4.5 Rock-well B scale points of the high side - about a 5% deviation) from the accepted value.
The licensee subsequently tensile tested this bolt and found that the ultimate tensile strength of the fastener was acceptable.
Engineering evaluation of these deviations indicated (
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that chemical and mechanical testing of the bolting materials were the most reliable methods of measuring the acceptability of the fastener; hardness testing was a coarse (although easily performed and inexpensive) measure of the acceptability of the fastener. As a result, the licensee determined that the hardness deviations noted were not significant. The inspector found this determination to be acceptable.
To prevent any future problems with the procurement of safety-related fasteners, the licensee developed a detailed specifi-cation, C-113-ER-0-E1, dated June 26, 1989, regarding the procurement and handling of fasteners.
No further actions were taken with regard to this Bulletin since the licensee considered that their existing QC program for fasteners was acceptable.
The inspector reviewed the administrative controls regarding the handling of safety-related and non-Safety-related fasteners by in-spection of the physical storage of a representative fastener (13 TP1 GR 2H - A194) and a f astener locking compound with a limited shelf-life.
No problems were noted. Overall, licensee actions taken in response to this Bulletin were viewed as comprehensive, technically sound, and timely.
This T1 (2500/27) is closed.
10.0 Review of Periodic and Special Reports
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Upon receipt, the inspector reviewed the Monthly Statistical Report for January 1990 submitted pursuant to Technical Specifications.
This review verified, as applicable:
(1) that the reported information was valid and included the NRC-required data; (2) that test results and supporting in-formation were consistent with design predictions and performance speci-fication; and (3) that planned corrective actions were adequate for reso-lution of the problem.
The inspector also ascertained whether any re-ported information should be classified as an abnormal occurrence, 11.0 Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings.
A summary of findings for the report period was also discussed at the conclusion of the inspec-tion and prior to report issuance.
No proprietary information was identi-fied as being included in the report.
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