ML20215D405
| ML20215D405 | |
| Person / Time | |
|---|---|
| Site: | Monticello  |
| Issue date: | 12/11/1986 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20215D377 | List: |
| References | |
| 50-263-86-04, 50-263-86-4, EA-86-165, IEC-77-09, IEC-77-9, NUDOCS 8612160353 | |
| Download: ML20215D405 (2) | |
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NOTICE OF VIOLATION Northern States Power Company Docket No. 50-263 Monticello Nuclear Generating Station License No. DPR-22 EA 86-165 During an NRC inspection conducted during the period May 28 - September 5, 1986, which reviewed an incident identified by the licensee and reported to the NRC on June 12, 1986, violations of NRC requirements were identified. The violations involved a failure to assure that the Standby Liquid Control System was operable and to take timely effective corrective actions after the licensee was informed that a fuse coordination problem could exist. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions,"
10 CFR Part 2, Appendix C (1986), the violations are listed below:
A. Technical Specification (TS) 3.4.A requires that the standby liquid control (SLC) system be operable at all times when fuel is in the reactor and the reactor is not shut down by control rods, except as specified in TS 3.4.B.
TS 3.4.B provides that from and af ter the date that a redundant component is made or found to be inoperable, Specification 3.4.A shall be considered fulfilled provided the component is returned to an operable condition within 7 days.
TS 3.4.0 requires that if Specifications 3.4.A through C are not met, an orderly shutdown shall be initiated.
Contrary to the above, during various times between November 2, 1984 and June 11, 1986 when fuel was in the reactor and the reactor was not shut down by control rods, both trains of the SLC system were incapable of providing injection flow upon initiation from the control room and actions were not taken to initiate an orderly shut down. The squib valve detonators installed on November 2,1984 were tested on June 11, 1986 and caused a short circuit which tripped the SLC pump motor.
B. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.
Contrary to the above, as of June 11, 1986, the licensee's corrective actions program failed to assure that the fuse coordination deficiencies in the Standby Liquid Control System were promptly identified and corrected.
The fuse coordination problem was identified to the licensee: (1) by the NRC in IE Circular 77-09, Improper Fuse Coordination in BWR Standby Liquid Control System Control Circuits, dated May 1977; (2) by General Electric in a Service Information Letter ($1L) 236, Fuse Coordination in SLC System,
! issued in August 1977; and (3) by a licensee system engineer in response j to a March 1979 plant request. However, the problem was not corrected until after testing on June 11, 1986 which found both trains of the Standby
! Liquid Control System inoperable.
0612160353 061211 PDR ADOCK 0D000263 i G PDR
i Notice of Violation 2 DEC i 1 1986 Collectively, these violations have been evaluated as a Severity Level III problem (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, Northern States Power Company is hereby required to submit to this Office within 30 days of the date of the letter transmitting this Notice, a written statement or explanation in rely, including for each violation: (1) the reason for the violations if admitted; (2) the corrective steps which have been taken and the results achieved; (3) the corrective steps which will be taken to avoid further violations; and (4) the date when full compliance will be achieved. Where good cause is shown, consideration will be given to extending the response time.
Dated at Glen Ellyn, Illinois this o" day of December 1986
U.S. NUCLEAR REGULATORY C0194ISSION REGION III Report No. 50-263/86004(DRP)
Docket No. 50-263 License No. DPR-22 Licensee: Northern' States Power Company 414 Nicollet Mall Minneapolis, MN 55401 Facility Name: Monticello Nuclear Generating Station Inspection At: Monticello Site, Monticello, MN Inspection Cor. ducted: May 28 through September 5, 1986 Inspector: P. L. Hartmann Approved By: D. C 9-5-M Reactor Projects Section 2D Date Inspection Sumary Inspection on May 28 through September 5, 1986 (Report No. 50-263/86004(DRp))
Areas Inspected: A routine, unannounced inspection by the resident inspector of operational safety verification; maintenance; surveillance; standby liquid control; low pressure coolant injection logic; reportable events; startup from refueling; Part 21 report; regional requests; and Licensee Event reports; allegation reviews.
Results: Of the 11 areas inspected, no violations were identified in 10 areas.
$ One violation was identified in the remaining area (having both trains of SBLC inoperable - Paragraph 5.d).
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DETAILS ,
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- 1. Persons Contacted .
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- W. A. Shamla, Plant Manager ,
N,> -
M. H. Clarity. Assistant to the Plant Manager ,
D. E. Nevinski, Plant Superintendent Engineering & Radiatien Protection' H. M. Kendall, Plant Office Manager '
D. D. Antony, General Superintendent of Operations.
R. L. Scheinost, Superintendent. Quality Engineering , i J. R. Pasch, Superintendent Security and Services L. H. Waldinger, Superintendent, Radiation Protection' ' -
W. J. Hill, Superintendent, Technical Engineering W. W. Albold, General Superintendent, Maintenance B. D. Day, Superintendent Operating Engineering L. L. Nolan, Superintendent, Nuclear Technical Services C. L. Silman, Project Superintendent The inspector also contacted other licensee employees including members of the technical and engineering staffs, and reactor and auxiliary ,
operators. ,
- Denotes the licensee representatives attending the management exit > _ t interviews. . /
- 2. Operational Safety Verification g.
The unit was in a refueling outage from the beginning of the inspection period until startup which occurred July 11, 1986. -
The inspector observed control room operations, reviewed ' applicable logs and conducted discussions with control room operators during the inspection period. The inspector verified the operability of selected emergency systems, reviewed tagout records and verified proper return to l
- l. service of affected components. Tours of the drywell, reactor building and turbine building were conducted to observe plant equipment
, conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated
- for equipment in need of maintenance, plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
During the inspection period, problems were encountered with Intermediate Range Monitors. This is the subject of Inspection Report No. 263/85006(DRS).
- 3. Monthly Maintenance Observation
) Station maintenance activities on safety-related systems and con.ponents
' listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.
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The following items were considered during this review: the limiting
. .. t, .. conditions for operation were met while components or systems were '
.' . removed from service; approvals were obtained prior to initiating the cc work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were
' ' performed prior to returning components or systems to service; quality e ... control records were maintained; and activities were accomplished by
- qualified personnel. Portions of the following maintenance activities
,s were observed / reviewed during the inspection period:
- Annual Inspection of D-2 Emergency Diesel Generator
'.,* Wiring Replacement of Motor Operators Repair of No.14 RHR Service Water Pump 4, 1$onthly Surveillance Observation h# The inspector observed surveillance testing and verified that testing L was perfonned in accordance with adequate procedures, that limiting
- condittans for operation were met, that removal and restoration of the
/ affecteo components wtre accomplished, that test results conformed with 4 technical specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and 7
j resolved,by appropriate management personnel.
1 The inspector cbserved/ reviewed the following test activities:
'* 'htahdby Liquid Control System (SLC) Functional Test
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- SLCRefuelibgValveExercise
. ; SLC bdiosi,ye Valve Actuation
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- SLC Relief Valve Setpoint Check e, 5. . Standby Liquid Control (SLC) Operability Problems w '
- a. J Event /
On June 11," 1986, at approximately 3:30 p.m. while shut down for l." refueling, the SLC refueling tests were conducted. These tests I,'
- caused a SLC pump to start, a squib valve primer to explode allowing L,4 i flow thrbugh the valve, Reactor Water Clean Up RWCU) to isolate, N
and flow to be verified from the SLC test tank filled with
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demineralized water) to the reactor vessel. During this test, j '... Syttem E of SLC was actuated by key lock switch from the control
' room. The 12 SLC pump started; test tank level was verified as
' decreasiiQ by an in-plant operator who concurrently heard the 12
,' sq'uto valve fire. Af ter about 1-1/2 minutes of operation, the 12
- y
~< 5LC pump stopped. The control room operator observed the RWCU
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valves had closed on the control board, and went behind the main control board to record meter relay currents, and observed zero current indicated. Theshiftsupervisor(SS)wasmonitoringthe main control board during the reactor operator's absence. The SS noticed the pump run light had gone out but believed that the light bulb had burned out. The test was secured after 2-1/2 minutes as per procedure. System 11 was initiated as part of the procedure to test a squib primer as one of a batch of replacement primers.
By audible indication the valve fired.
The light bulb was then replaced on SLC pump 12 and the system was initiated to determine if the loss of run indication was related to the light bulb. The 12 SLC pump did not start. Subsequent investigation revealed the control power fuse had blown and the SLC pump had run about 1-1/2 minutes. At this point the licensee stopped activities surrounding the SLC tests in order to investigate the anomalies the next day.
On June 12, 1986, the events surrounding the SLC testing were reviewed. It was known that the squib valve continuity meter relays had been replaced and wiring problems could have been responsible for the anomalies. Investigation revealed that both squib valve detonators had shorted causing excessive currents and, due to control power fuse sizing for the SLC pump breaker, the pump breaker control power fuse blew causing the breaker to trip. By this same scenario, had the 11 SLC train been run, the 11 SLC control power fuse would have blown by the same circumstance of the detonator shorting.
At 1:05 p.m., June 12, 1986, the licensee reported the event to the NRC duty officer, and that both SLC trains were inoperable because of the circuits through the detonators for both squib valves.
- b. Background (1) Licensee Response to Circular No. 77-09 and GE SIL 236 Review of the past history surrounding squib valve firings and SLC fuse coordination disclosed the following infonnation:
September 4, 1970: During pre-operation activities two squib valves were fired It was noted that high current existed after the firing on both squib valves as evidenced by meter indication and the squib continuity lights remaining on. The system engineer concluded that a short existed across the squib detonators after firing. Corrective action at this point was to replace the detonators.
March 28, 1973: During refueling testing the meter current for the squib valve detonator increased after firing the squib l
valve. The system engir.cer identified this as a problem but l concluded that this increase in current was due to induced current in wiring. Upon recent review, it was determined this was probably a partial short circuit in the detonator.
Apparently no fuses blew during this test.
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April 27, 1977: 1.E. Circular 77-09, " Improper Fuse Coordination in BWR Standby Liquid Control System Control Circuits" was received by the Plant.
June 7, 1977: The system engineer provides input regarding I.E. Circular No. 77-09. The engineer concludes that the concerns addressed in the circular do not apply to Monticello because the control power fuses were 10 amps (A). This was an incorrect conclusion based solely on a review of electrical drawing without field verification of the rating of installed fuses.
August 6, 1977: General Electric Issues Service Information Letter (SIL) 236, titled " Fuse Coordination in SLC System."
The SIL recommends:
- 1. Reviewing the SLC system control circuit and verifying the pump breaker control power fuses have sufficient transient current capability to ensure that the squib fuses will open first if a short circuit occurs in the squib circuits when the squib is fired.
- 2. Testing the control circuit by intentionally shorting the squib circuit " hot" lead to ground and attempting a firing signal. This test was recommended to ensure the squib valve fuse would blow first.
March 26, 1979: Plant management requests documented responses to the circular and SIL.
In response to this request, the system engineer indicated the current design was inadequate. At this point it is noted that 2.5A and 1.6A fuses are installed in the control power circuitry versus the 10A fuse indicated in the system drawing.
The system engineer apparently concluded that with the existing
. ' fuse coordination, the squib valve fuses would blow before the control power fuse if one squib valve detonator shorted. If both squih valve detonators shorted, it is uncertain what would take placc as performance of current limiting resistors are uncertain. The design engineer recommends a design change of 1.6A fuses for the control power and 0.5A for the squib valve fuses.
March 4, 1982: The system engineer develops a design change package to change control power fuses to 1A, squib valve fuses to 0.5A.
August 25, 1982: The Superintendent of Technical Engineering, after review of the proposed design change, questioned the design and required concurrence from GE.
i June 27, 1984: Monticello requests GE to review the fuse coordination suggested by the design change of March 24, 1982.
September 24, 1984: GE replies stating the proposed fuse coordination is not as conservative as their recommendations.
GE recommends:
- Replacing the .200 KVA transformer with a .750 KVA Class IE transformer.
- Installing LPN or FRN 4A fuses for control power fuses.
- Installing FNA 1A fuses for the squib valve fuses.
In response to this recommendation, the plant decides the design change cannot be completed during the 1984 recirculation piping replacement outage due to procurement problems. Instead the design change is scheduled for the spring 1986 outage.
February 1986: The system engineer discusses the proposed design change with GE. GE states the previous review of the fuse coordination was extremely conservative.
June 1986: The SLC fails to operate properly during a
- refueling test because of short circuits in the fixed fuel detonators. After the squib valve shorting event, a final design change is developed as follows:
- Replacing the .200 KVA transformer with a .750 KVA transformer of the same seismic qualification as the original.
- Installing FRN 4A fuses for control power fuses.
- Installing FNA 0.8A fuses for the squib valves.
, _, This design change was completed. The SLC refueling surveillance was satisfactorily completed by July 1, 1986.
One detonator did short, the squib detonator fuse blew as designed, and the control power fuse remained intact.
(2) Results of Previous SLC Refueling Surveillance Tests The licensee has documentation of testing the SLC during refueling outages required by Technical Specification on 4 the following dates:
October 4, 1977 May 6, 1981 November 1, 1978 October 9, 1982 March 25, 1980 November 2, 1984 6
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During these tests, the SLC system was tested from the control board by initiating a train which started the pump and fired the squib valve. Verification of flow to the reactor vessel from the SLC test tank was accomplished. In addition to the above documented dates the licensee believes that the refueling SLC flow verification test was performed during all refueling outages.
The surveillance tests prior to 1977 were not available as these records have a six-year retention time. The refueling surveillance should have been run 11 times since commercial operation began. No failures were reported during these tests.
(3) Analysis There are several reasons why the licensee did not respond to the circular and SIL in a more prompt manner. The most dominant factor is that the licensee never concluded it was probable the fuse coordination situation would result in rendering both trains of the SLC inoperable. This position was identified by the background documentation and discussions with the licensee. There is some evidence that the March 26, 1979 review by the system engineer concluded one squib detonator could short with the associated squib fuse blowing before the control power fusa. Also, it was concluded that, if both detonators shorted, the control power fuse would blow.
The plant decided that the likelihood of shorting both detonators in both squib valves (which would be required by this analysis l
to render both trains of SLC inoperable) was extremely remote.
Based on this mindset, the licensee did not attach a high priority to this design change.
The second reason for untimely response to the fuse coordination concern is apparently an inadequate turnover of SLC system responsibility between system engineers. Since the plant's receipt of the SIL, at least five system engineers
.a have had responsibility for the SLC system. It appears that this turnover delayed resolution of the SIL concerns.
Specifica'ly, since the SIL in 1977, it took until 1982 for a design change to be developed. After the design change was developed, the letter requesting GE review and required in the August 25, 1982 plant memorandum did not go out until September 24, 1984.
! Third, contributing to this delay was the improper conclusion in 1977 that the fuse coordination was not a concern at Monticello because a 10A fuse was installed for the control power fusing. Although it is not certain a 10A fuse was not installed, it appears the system engineer reviewed the drawing only and did not verify the fuse size which was installed at the time of his review.
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A fourth reason for untimely response was when the system engineer reviewed the fuse coordination in 1979 and found the discrepancy between the system drawing showing a 10A fuse and installed fuses of 2.5A and 1.6A there was apparently no corrective action. Also, the SIL recomended testing the fuse coordination by shorting the _ squib hot lead. This test would have probably diagnosed the problem. The test apparently was not considered in the 1977 or 1979 SIL reviews.
Pre-operation testing in 1970 resulted in detonator shorting with the same high current resulting. It appears that the pump was secured in 10-30 seconds which did not provide sufficient time for the same scenario of the control power fuses blowing. This pre-operation testing data was recorded on a hand-written log with the last entry in 1974. It appears that this information was not reviewed after the I.E. Circular and SIL were received. Only after the recent event was this information retrieved and reviewed. Personnel involved in the review of the fuse coordination problem did not recall the pre-operation squib detonator shorting.
(4) Conclusions The event at Monticello, which could have prevented SLC operation with no operator intervention, was pre-noticed by I.E. Circular No. 77-09 and SIL 236. The licensee's failed to respond to this information in a prudent and timely fashion.
The design change was assigned a low priority with years of delay at various stages of the design change process. A SIL recomended test was not performed that possibly would have diagnosed the inadequate fuse coordination experienced.
- c. Safety Assessment (1) SLC Purpose I .
The purpose of the SLC system is contained in the Technical Specification Bases 3.4.A and states in part:
"The design objective of the standby liquid control system I is to provide the capability of bringing the reactor from
! full power to a cold, xenon-free shutdown assuming that none of the withdrawn control rods can be inserted. To meet this objective, the liquid control system is designed to inject a quantity of boron which produces a
. concentration of 660 ppm of boron in the reactor core in less than 125 minutes."
The Updated Safety Analysis Report (USAR) states in part "it can be estimated that the reactor initially operating at 1670 MW would be at hot (547 degrees F) subtritical in about 20 or 30 minutes, depending on solution concentration and mixing assumptions and reactor coolant temperature."
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From the above, it can be concluded that the SLC system is an Engineering Safety Feature (ESF) which takes a significant amount of time to perform its function when compared to control rods activated by the Reactor Protection System or the Anticipated Transient Without Scram (ATWS) detection system, or manual actuation. The' SLC system is a manually actuated system. There is no automatic initiation of SLC, 7
(2) Analysis The SLC is an ESF system with one redundant train required at all times for operation. With the loss of SLC, an orderly shutdown is required by Technical Specification 3.4.D. The SLC system is a redundant method of inserting negative reactivity. The SLC is manually actuated at a point where control rods cannot be inserted to shut down the reactor by auto / manual scram or single rod insertion. It is important to note that SLC injection is not used in any of the accident analysis in the USAR.
Abnormal operating procedure C.4.1, Reactor Scram Part F., ATWS Event, addresses use of SLC injection. The procedure requires the attempt to insert rods by various means and when no rod insertion is possible, the procedure states in part, "If at any time the control rod system is unable to maintain the reactor in a subcritical condition and one of the following conditions exist: 1. Reactor vessel level cannot be maintained; or 2.
suppression pool water temperature cannot be maintained below the scram temperature limit (110 degrees F). . . initiate SLC injecting the entire tank volume."
The situation requiring initiation of the SLC system would result in specific actions by the emergency plan. Failure of the RPS system to initiate and complete a scram which brings the reactor subcritical would require an Alert to be declared.
i The complete loss of ability to achieve or maintain hot
- - shutdown, with inability to scram and an inoperable SLC system would require a Site Alert to be declared. These emergency l
plan activities would provide the manpower and technical
- expertise to address an inoperability situation. In the June 11, 1986, scenario, the fuse-blowing problem would probably be quickly recognized and remedied when SLC was required. The most pragmatic response would be to remove squib valve fuses and to replace the control power fuse. The system engineer stated this as a simple solution to interrupt the short circuits through the squib valve detonators, allowing the i SLC injection.
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(3) Conclusion The SLC system is vital to the operation of Monticello. It is a manually actuated system used to shut down the reactor after attempts to insert the control rods by various means had failed. When the SLC is required to be initiated, the plant would have already declared an Alert. The particular problem with SLC fuse coordination would probably be corrected in a short time period. The SLC is required by technical specifications, but is not assumed in any of the accident analysis.
- d. Enforcement Technical Specification 3.4.A states that "The standby liquid control system shall be operable at all times when fuel is in the reactor and the reactor is not shut down by control rods, except as specified in 3.4.B."
Technical Specification 3.4.B states that "From and after the date that a redundant component is made or found to be inoperable, Specification 3.4. A shall be considered fulfilled, provided that:
The component is returned to an operable condition within seven days."
From the preceeding discussion it can be concluded that the failure to have both trains of the SLC system operable is a violation of Technical Specifications (263/86004-01(DRP). The system fuse coordination problem which existed since the initial installation of the system was pre-noticed twice to the licensee. The licensee did not properly respond to either of the notices, leaving the circuits essentially unchanged, which ultimately resulted in both trains failing simultaneously. Since the physical configuration of the explosive valves involved is unique, it can be concluded that the failures which occurred during the June 11, 1986 test firing would also have occurred at any other time the valves were detonated. Thus, since the valves that failed during the June 11, 1986, test had been installed in the SLC system on November 2, 1984, it can be concluded that both trains of the SLC were inoperable for a period of approximately twenty months, most l
of which time the plant was in power operation.
- 6. Low Pressure Coolant Injection (LPCI) Logic Deficiencies On June 28, 1986, while the reactor was shut down for refueling, the Emergency Core Cooling System Logic test was performed and an anomaly was discovered. During the logic test the loop selection failed to choose the correct loop for injection and instead chose the loop with the simulated break. Later investigation revealed that a design. deficiency existed which would allow an improper loop selection when simultaneous energization of both A and B LPCI logic circuits occurred. This WB
simultaneous energiration would result in a logic relay race between i loop selection and break detection. If the loop selection logic functioned first, the pre-selected loop would be selected independent of the break detection logic.
In response to this discovery, the licensee consulted with GE to determine corrective action. It was detennined that the remedy was to replace instantaneous contacts in the loop selection logic relays with 1/2 second time delay contacts. This delay would provide for operation of the break detection scheme prior to loop selection without delaying injection by the LPCI system. On July 7, 1986, the change to the loop selection relays were completed and later the LPCI loop selection logic test was successfully conducted.
The licensee had no pre-notice of this design deficiency. The failure of LPCI loop selection logic to select the proper loop would result in the loss of all LPCI injection to the vessel and the core would be cooled
! primarily with the two trains of low-pressure core spray. This condition is bounded by the current licensing evaluation which assumes an entire
' loss of the LPCI system by injection valve failure.
- 7. Reportable Events During the refueling outage which lasted fron' April 30 to July 11, 1986, 17 reportable events occurred resulting in LERs 86010 through 86023.
The inspector reviewed these events to determine whether a trend existed identifying a breakdown in any of the licensee's programs. Of these events, six were caused by procedural inadequacies; five were caused by hardware failures; two were caused by personnel error; three were caused by design deficiencies; and one was caused by maintenance
- activities. It appears the hardware and personnel error events were
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unrelated. The procedural-caused events appear to be related. Of these six events, three were directly caused by an inaccurate or inadequate procedure. In response, the licensee has begun a program to change the procedure review process. The proposed changes will require a user review for Revision 0 and other revisions to procedures. The intent
- - of this review is to bring the groups that utilize the procedures into the review process. Another improvement will be the requirement of an independent review for new and revised portions of procedures. The intent of this review is for the reviewer to perfonn a field walk-through I to ensure the procedure is accurate and effective. These actions should address the concerns identified by these events involving inadequate procedure reviews.
E. Startup From Refueling ,
The inspector verified that the control rod withdrawal sequence and
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rod withdrawal authorization were available and all surveillance tests required to be performed before the startup were satisfactorily completed; i that startup was perfonned in accordance with technically adequate and approved procedures which had been revised to reflect changes made to the facility and to the startup testing program; and that startup activities were conducted in accordance with technical specification requirements.
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The inspector also witnessed the benchmark criticality after refueling.
The inspector reviewed the estimated criticality procedure (ECP) and observed that criticality occurred within the reactivity parameters of the ECP.
- 9. Part 21 Notification The licensee completed corrective action in response to a 10 CFR Part 21 Notification during the assessment period. The action for Monticello involved retorquing an enclosing tube nut on Magnetrol switches. The retorquing was accomplished on seven switch assemblies, four installes and three in warehouse storage. No other action is required.
- 10. Regional Pequests The inspector provided the requested information for the items below in response to written requests from C. E. Norelius, Director, Division of Reactor Projects.
- a. SURVEY OF LICENSEE'S RESPONSE T0 SELECTED SAFETY ISSUES (TEMPORARYINSTRUCTION 2515/77)
- b. REQUEST FOR INFORMATION REGARDING INSPECTION OF LIMITORQUE MOTOR VALVE OPERATION WIRING. (TEMPORARY INSTRUCTION 2515/75)
- c. DATA COLLECTION FOR THE PERFORMANCE INDICATOR TRIAL PROGRAM.
(TEMPORARYINSTRUCTION 2515/80)
- 11. Licensee Event Reports l
l Through direct observation, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.
(Closed) LER 85004 - Flow Through RHR Intertie Line While in Run Mode.
(Closed) LER 86007 - EFT Actuation Due to Broken Tape.
(Closed) LER 86009 - EFT Actuation Due to Radiation Monitor Spike.
(Closed) LER 86011 - EFT Trip Due to Broken Tape.
(Closed) LER 86014 - ESF Actuation Due to RPS Trip.
(Closed) LER 86015 - RHR Shutdown Cooling Interlock Trip.
(Closed) LER 86016 - Standby Liquid Control Improper Fuse Coordination.
(Closed) LER 86020 - RPS and Group II Trip from Loss of Power.
}2_,-_ _ _ _ , _ , _ - _ . , _ _ _ _ _ _ , _
O
. (Closed) LER 86022 - RBV Isolation, Containment Group II Isolation and SBGT Initiation During Switching.
(Closed)LER86023-LPCILoopSelectionDesignProblems.
- 12. Allegation Review (Closed) RIII-86-A-0050: On March 21, 1986, the NRC received an allegation concerning 16 and 20 inch pipe supplied to Monticello by AZCO. The alleger stated that the pipe was foreign made, had no heat numbers and did not conform to specifications. He further advised that the majority of the unqualified pipe went to the Sherburne County Station, a fossil plant, and the remainder was sent to Monticello. He did not have an exact number or the amount supplied to Monticello.
The alleger directly contacted the licensee with the same allegations which he provided to the NRC.
As a result, the licensee had made an investigation ir.co the areas identified. All purchase orders that AZC0 had with NSP were reviewed and the licensee determined which contracts dealt with Monticello.
The licensee further talked to engineers in charge of the AZC0 projects to verify the material used.
The records of those investigations were made available to the SRI onsite. From a review of the licensee's investigations, the inspector determined that the licensee compiled a list of all of the work that AZC0 perfonned at Monticello during the period in question as follows:
Addition to the administration building (EFT) - installing essential service water piping, roof drains, fire protection, heating and ventilation work.
Diesel generator building - fire protection, installed fire protection sprinklers.
Cable spreading room - fire protection, installed halon system.
Turbine building addition - installed roof drains, heating system, duct extension for turbine room.
Rad waste building addition - installed fire protection, heating system, ductwork, and drains.
From this review it was established that AZC0 had not furnished or installed any 16 or 20 inch piping at Monticello. Furthennore, the only safety related work that AZC0 did was in the EFT addition, installing the essential service water piping. The licensee went back into the EFT project documentation and verified that the essential service water piping was manufactured in the USA and had Certified Material Test Reports (CMTRs). This allegation is considered closed, se
- 13. Exit Interview The inspector met with licensee representative denoted in Section 1 at the conclusion of the inspection on August 19, 1986. The inspector discussed the purpose and scope of the inspection and the findings.
The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection. The licensee did not identify any documents / processes as proprietary.
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