IR 05000369/1983021
| ML20024F706 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 06/22/1983 |
| From: | Brownlee V, William Orders, Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20024F690 | List: |
| References | |
| 50-369-83-21, 50-370-83-29, IEB-83-01, IEB-83-1, NUDOCS 8309090593 | |
| Download: ML20024F706 (21) | |
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Docket Nos. 50-369/83-21 and 50-370/83-29 Licensee: Duke Power Company Facility Name: McGuire 1 and 2 Docket Nos. 50-369 and 50-370 License Nos. NPF-9 and NPF-17 Inspection at McGuire site near Cornelius, North Carolina Inspectors:
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Ddte Si'gned Approved by: _.
8 A. e [n e si h (,' /") J /r3 V./L. Brownleeft Chief v Project Section 2A Dat'e Sigrfed
' Division of Project and Resident Programs SUMMARY Inspection on March 20 - April 27,1983 Areas Inspected This routine, announced inspection involved 193 inspector-hours on site in the areas of operations, surveillance testing, maintenance activities, IE Bulletin follow-up and license condition resolution.
Results Of the five areas inspected, no violations or deviations were identified in two areas; two violations were found in three areas (Violation-use of inadequate procedure resulting in inadvertent safety injection and failure to follow another procedure resulting in suction heacer overpressurization (369/83-21-01, 370/83-29-01) paragraph 12; Violation failure to control documents important to safety (369/83-21-02) - paragraph 5).
6309090593 830825 DR ADOCK 05000
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REPORT DETAILS
1.
Persons Contacted Licensee Employees
- M. McIntosh, Station Manager
- G. Cage, Superintendent of Operations E. Estep, Project Engineer
- M. Sample, Project Engineer
- B. Barron, Operations Engineer, Unit 2
- D. Mendezoff, Licensing Engineer C. Van Vynckt, Staff Engineer Other licensee employees contacted included technicians, operators, security force members, and office personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on April 27, 1983, with those persons indicated in paragraph 1 above. Licensee expressed under-standing of and concern over the issues presented.
3.
Licensee Action on Previous Enforcement Matters Not inspected.
4.
Unresolved Items Unresolved items were not identified during this inspection.
5.
IE Bulletin Followup
.IEB 83-01 On February 25,1983, IEB 83-01, Failure of Reactor-Trip Breakers Westinghouse-DB-50 to Open on Automatic Trip Signal was issued.
The-bulletin addressed failures of Westinghouse type D8-50 breakers. This
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bulletin required several actions to be taken by those utilities employing DB-50's as well as a negative declaration from_ those utilities not employ-ing DB-50's.
In a letter dated March 2,1983, Duke Power Company declared that no DB-50 breakers are employed at McGuire. This bulletin is closed.
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IEB 83-04 On March 11, 1983, IEB 83-04, Failure of the Undervoltage Trip Function of Reactor Trip Breakers was issued. The inspector reviewed the licensee's March 22, 1983 response to this bulletin 83-04. The licensee performed the testing of DS-416 breakers, on March 16 and 17, 1983 for Units 1 and 2, respectively, to satisfy the bulletin requirement. The results were satis-factory.
It was determined on March 18, 1983 that Unit 2 had five previous failures of one RPS breaker during testing in early 1983. As a result, on March 18 the breaker was tested with a failure rate of 3 in 125 cycles. On March 19 during response time testing one Unit 1 breaker also failed to trip on an under voltage signal.
Details of the failures are entailed elsewhere in this report.
In assessing the licensee's response to the bulletin the following procedure and vendor manuals were reviewed for adequacy:
a.
MCM 1399.39-1. Westinghouse Vendor Manual which contains I.B.33-790-18, effective May 1971, titled " Instruction for Low-Voltage Power Circuit Breakers Types DS-206, DS-416, and DS-532."
b.
MCM 1399.40-18. Westinghouse Vendor Manual I.B.33-790-IE, effective September 1979, w
c.
IP/0/A/3010/06, " Reactor Protection System Time Response Test."
d.
-0P/1/A/6100/05 and OP/2/A/6100/05, " Unit Fast Recovery."
e.
AP/1/A/5500/01 and AP/2/A/5500/01, " Reactor Trip."
f.
AP/0/A/5500/34, " Actions Required for an Anticipated Transient Without Scram."
g.
IP/0/A/3010/09, " Solid State Protection System Manual Input Functional Test."
h.
MP/0/A/2001/04. " Maintenance of Air Cooled Breakers."
The following items were also noted:
1.
Maintenance records showed the breakers as being treated as safety related components Code 2E as called for in the McGuire " Safety Related Structure Systems and Components Manual."
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2.
On a tour of the control room it was observed that the manual trip switch handles were not of the removable handle design.
3.
The operator on duty had been briefed on the Salem and San Onofre events as required by the bulletin.
4.
Procedures 0P/'/A/6100/05 and OP/2/A/6100/05 require the shift supervisor to determine the cause of the reactor trip.
The shift supervisor must determine and request assistance in the event the cause is not evident or easily resolved. The trip evaluation is performed by a performance group and, in addition, by the McGuire Independent Review Group.
5.
In reviewing procedures AP/1A/5500/01 and AP/2/A/5500/01, it was noted that no immediate action to follow on automatic scram with a manual scram is entailed.
Instead, the operator is directed to proceed to AP/0/A/5500/34 if the reactor fails to trip when required. The procedure then directs a manual trip be performed.
Pending final resolution of the problems surrounding the DS-416 breakers, this bulletin remains open.
During the above review, the inspector requested a copy of the procedure detailing the maintenance performed on the DS-416 breakers.
Procedure MP-0-A-2001-04 was received. MP-0-A-2001-04 pertained only to ITE Air Cooled Breakers.
It was subsequently determined that a revision to that procedure entailing the DS-416 information had been misfiled and mislabled as TCM-0-M-2001-04. Moreover, a revision to the DS-416 vendor manual, MCM 1399.39-1 (I.B.33.790-IE) had also been misfiled and mislabled as MCM 1399.40-18. These two examples singularly and collectively violated the requirements of 10 CFR 50 Appendix B Criterion VI. Appendix B Criterion VI requires effective control on issuance of documents to assure that they are distributed to and used at the location where the prescribed activity is performed.
The licensee failed to meet this requirement which is a Violation (50-369/83-21-02).
6.
Plant Operations The inspector reviewed plant operations throughout the report period, March 20 - April 27 to verify conformance with regulatory requirements, technical specifications and administrative controls.
Control room logs, shift super-visors' logs, shift turnover records and equipment removal and restoration records were routinely perused.
Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance person-nel on day and night shifts.
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Activities within the control rooms were monitored during all shifts and at shift changes. Actions and/or activities observed were conducted as prescribed in-Section 3.1 of the Station Directives. The complement of licensed personnel on each shift met or exceeded the minimun required by technical specifications. Operators were responsive to plant annunciator alarms and appeared to be cognizant of plant conditions.
Plant tours were taken throughout the reporting period on a systematic basis. The areas toured include but are not limited to the following:
Turbine Buildings Auxiliary Buildings Units 1 and 2, Electrical Equipment Rooms Units 1 and 2, Cable Spreading Rooms Station Yard Zone within the protected area Units 1 and 2 Reactor Buildings During the plant tours, ongoing activities, housekeeping, security, equip-ment status and radiation control practices were observed.
McGuire Unit 1 continued an extended maintenance outage throughout the report period. The major work performed during the outage consisted of Model D2-D3 steam generator modifications and loose thermal sleeve removal.
Details concerning maintenance of these activities and their respective postmaintenance ramifications are entailed elsewhere in this report.
McGuire Unit 2 progressed toward initial criticality during the report period. At the close of this report the unit is scheduled to achieve I
initial criticality on or about May 3, 1983.
7.
Surveillance Testing The surveillance tests categorized below were analyzed and/or witnessed by the inspector to ascertain procedural and performance adequacy.
The completed test procedures examined were analyzed for embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria, and sufficiency of technical content.
The selected tests witnessed were examined to ascertain that current written approved procedures were available and in use, that test equipment to use
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was calibrated, that test prerequisites were met, system restoration completed and test results were adequate.
The selected procedures perused attested conformance with applicable Tech-nical Specifications and procedural requirements, they appeared to have received the required administrative review and they apparently were performed within the surveillance frequency specified.
Procedure Title PT-0-A-4600-14C NI Source Range Functional Test PT-0-A-4601-06 Containment Pressure Transmitter Test PI-2-A-4200-01 L Air Lock Leakage Test PI-1-A-4600-56 Manual Reactor Trip Test PI-2-A-4200-14 A Ice Condenser Door Inspection PI-2-A-4150 0113 RCS Leakas Test PI-2-A-4600-05 Rad Monitor System Function Test PI-1-A-4252-01A-Motor Driven Auxiliary Feedwater Test PI-1-A-4600-05 Rad Monitor System Function Test TP-2-A-1600-02 NI System Function Test TP-2-A-1150-08 ASME Pipe Expansinn Test PT-0-A-4601-03 Protective System Channel 3 Function Test 8.
Maintenance Observations The maintenance activities categorized below were analyzed and/or witnessed by the resident inspector to ascertain procedural and performance adequacy.
The completed procedures examined were analyzed for embodiment of the necessary prerequisites, preparations, instruction, acceptance criteria and sufficiency for technical detail.
The selected activities witnessed were examined to ascertain that where applicable, current written approved procedures were available and in use, that prerequisites were met, equipment restoration completed and maintenance results were adequate.
The selected work requests / maintenance packages perused attested conformance with applicable Technical Specifications and procedural requirements and appeared to have received the required administrative review.
Detailed below are maintenance activities which were observed and/or reviewed during the report period:
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WORK REQUEST EQUIPMENT 6287 EMF-51-A 6297 EMF-51-B 112139 2-NI-9 11214 SSF-BATT 64150 RVLIS 54192 FWPT-1A 53368 UHI 35566 WG Compressor 72157 S/G 1A 112934 2CA Pump Turbine 9.
License Condition Closecut Detailed herein in executive sunnary are the closecut actions associated with the precritical license condition for Unit 2 (NPF-17, Attachment 1, items 1.a. through 1.r).
The closeout actions consisted, on the main, of design evaluations and test completions. The tests involved in the associ-ated license conditions were analyzed and/or witnessed to ascertain procedural and performance adequacy.
The completed test procedures examined were analyzed for embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria, and sufficiency of technical content.
The selected tests witnessed were examined to ascertain that current written approved procedures were available and in use, that test equipment in use was calibrated, that test prerequisites were met, system restoration completed and test results were adequate.
McenseCondition:
1.a.
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Barton Class 1E transmitters exhibiting thermal non-repeatability (CDR82-06).
Resolution:
In a letter dated April 28, 1983 the licensee declared that based on a statistical evaluation of the ITT Barton Class IE transmitter thermal non-repeatability errors performed by Westinghouse, the errors are within the limits of the safety analysis. Thus no set point changes are
, justified. This conclusion is based on a review of the Barton transmitters used for steam generator level (narrow range) which have the least margin between the setpoint value and the value assumed in the safety analysis for low steam generator level. The review revealed that the maximum errors during accident conditions for all McGuire Unit 2 Barton transmitters should be less than the original error allowance assumed in the accident analysis.
This is based on taking credit for polarity of the dynamic temperature error, and the actual temperature compensation and the actual temperature conditions at McGuire.
Errors at lower temperatures (130 F) will most
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likely be increased slightly, but should be absorbed by the margin in the safety analysis.
The Westinghouse generic evaluation of this issue is still ongoing and involves more testing by Barton. Duke is following the progress of the generic evaluation and will provide a followup response concerning this issue as soon as data is available.
Status: Based on the foregoing analysis this issue is closed in terms of a pre-critical license condition.
License Condition:
1.b.
s Complete design engineering evaluation of problems experienced with Bussman indicating fuses (81-33-01).
Resolution:
In a letter dated January 16, 1983 from a Senior QA Engineer of
Bussman Division, McGraw Edison Company to Duke Power Company, Design Engineering it was relayed that a concern detailed in inspection report 50-370/81-33 relative to mechanical separation of fuse internals was "...an isolated case." Based on their own engineering review, with the results detailed in their internal letter from the Electrical Division dated April 25,1983, Duke has concluded that in their engineering Judgement these FNA series fuses are acceptable for use in safety related applications.
Status: Closed License Condition:
1.c.
Verify operability (i.e., sounding) of containment evacuation alanns. This is to assure alarm operability and adequate audibility of the alarms.
(A speaker malfunction has previously occurred in Unit 1 in November,1981 where personnel could not hear the actuated alarm (81-33-03).)
Resolution: The Communication System Test, TP-2-B-1350-01, w 1 completed March 1, 1983. Section 12.3 of that test verifies the operabi.ity of the
" Plant. Alarms" including adequate volume.
Pursuant to that test two additional speakers were installed per station modification NSM MG2-0101 and tested satisfactorily pursuant to work request 92665. The inspector reviewed the station modification and had no further questions.
Status: Closed
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License Condition:
1.d.
Identify, track and reinspect during next plant heatup, as appropriate, piping. system supports, restraints, and clearances, which were: (1)
unacceptable' for operations turnovers prior to initial plant heatup; (2)
adjusted during initial plant heatup; (3) shimmed during or after initial plant heatup; and (4) modified subsequent to initial plant heatup (82-22-02),(82-22-03),(82-22-04),(82-22-05).
Resolution: This license condition was inspected and closed out in inspection report 50-369/83-17,50-370/83-24.
Status: Closed License Condition:
1.e.
i Repeat the pressurizer functional test so as to verify operability of all pressurizer heaters (82-25-01), (82-30-01).
Resolution: TP-2-A-1150-03 Pressurizer Functional Preoperational Test was satisfactorily completed on April 27, 1983. The inspector reviewed the test results and had no further questions.
Status: Closed License Condition:
1.f.
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Resolve the issue of an acceptable containment leak rate test. Contrary to ANSI /ANS 5698,-the licensee failed to reduce containment pressure to less than 85% of ILRT pressure for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as to allow for outgassing of trapped air (82-27-01).
Resolution: The license condition was inspected and closed out in inspection report 50-369/83-17,50-370/83-24 Status: Closed License Condition:-
1.g.
Review licensee's evaluation of a measurement technique in obtaining appropriate inlet pressure to the flowmeter that was used for the supplemented leak rate test (82-27-02).
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Resolution: This license condition was inspected and closed out in inspection report 50-369/83-17,50-370/83-24.
Status: Closed License Condition:
1.h.
Verify operability of the Standby Shutdown Facility (83-19-06).
Resolution: TP-1-A-1350-34, Standby Shutdown Facility Essential Equi) ment Functional Test was satisfactorily completed on February 20, 1983.
T 1e purpose of the test was to verify that the Standby Shutdown Facility performs as designed and intended along with the facility's Unit 1 interfaces. The facility's Unit 2 interfaces were incorportted into the various system functional tests. Portions of the test detailed below were witnessed and/or reviewed in order to determine adequate facility performance and sufficiency of testing.
Procedure Title TP-1-A-1350-34 SSF Functional Test TP-2-A-1150-09 RCS Functional Test TP-2-A-1200-06A NV Functional Test TP-2-A-1250-02A AUX Feedwater Preop Test TP-2-A-1250-02B AUX Feedwater Functional Test TP-2-A-1250-07 Steam Generator Blowdown System Functional Test Status: Closed License Condition:
1.1 Complete the reactor coolant system functional test (TP/2/A/1150/09) in order to verify nonitoring capability of the core exit thermocouples in the SSF(83-19-07).
Resolution: TP-2-A-1150-09 RCS Functional Test was satisfactorily completed Arpil 19, 1983. Section 12.8 of that procedure verifies the operation of the incore thermocouples and digital indicators in the SSF.
Status: Closed
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License Condition:
1.J.
Complete the turbine driven auxiliary feedwater pump test (TP/2/A/1250/04),
(83-19-08).
Resolution: TP-2-A-1250-04 Turbine Driven Auxiliary Feedwater Pump #2 Baseline Data Test was satisfactorily completed April 27, 1983.
Status: Closed License Condition:
1.k.
Resolve the issue of acceptable ECCS centrifugal charging pump flow performance (83-19-09).
Resolution: License amendments Nos. 20 and I were issued April 13, 1983 modifying Facility Operating License NPF-9 and 17, respectively. The license amendments modifiea the surveillance requirement 4.5.2.h.1)b to require a total pump flow of less than or equal to 565 gpm. This in conjunction with the associated safety evaluation report resolves the issue of an acceptable ECCS centrifugal charging pump flow test.
Status: Closed
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License Condition:
1.1.
Complete electric hydrogen recombiner 2B system functional test (TP/2/A/1450/14),(83-19-10).
Resolution: TP-2-A-1450-14 Electrical Hydrogen Recombiner 2B Functional Test was satisfactorily completed on April 27, 1983. A temporary modifi-cation which was in place in the power supply panel for the 2B recombiner, but which did not affect the test results was replaced on April 28, 1983.
i The system was retested successfully.
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Status: Closed License Condition:
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Complete testing of power range detectors, NI system functional test (TP/2/A/1600/02),(83-19-11).
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Resolution: TP-2-A-1600-12 Nuclear Instrumentation System Functional Test which tests in part, the nuclear instrumentation power range detectors, was satisfactorily completed April 28, 1983.
Status: Closed License Condition:
1.n.
Complete annulus system functional and filter tests (TP/2/A/1450/06, TP/2/A/1450/19),(83-19-12).
Resolution: TP-2-A-1450-06, Annulus Ventilation System Functional Test and TP-A-1450-19, Annulus Ventilation System Filter Train Acceptance Test werc satisfactorily completed on April 15, 1983.
Status: Closed License Condition:
1.o.
Complete pre-operational filter test for containment purge and exhaust filters 2Aand2B(TP12/8/1450/21),(83-19-13).
Resolution: TP-2A-1450-21, Containment Purge Ventilation System Filter Train Acceptance Test was satisfactorily completed April 14, 1983.
Status: Closed License Condition:
1.p.
Complete valve stroke timing tests on valves equipped with Rotork model NA-2 electrical motor operator switches (CDR 82-04).
Resolution: All affected switches with the clear plastic parts were replaced with upgraded switches. Listed below are the work requests pursuant to which the work was performed:
Work Report 63784 63788 63792 63796 63785 63789 63793 63786 63790 63794 63787 63791 63795
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Also, listed below are the test procedures pursuant to which the valves were
stroke timed:
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PT-2-A-4401-02 PT-2-A-4204-05 PT-2-A-4453-02 PT-2-A-4403-02 PT-2-A-4204-018 PT-2-A-4206-02 PT-2-A-4456-02 PT-2-A-4208-02 i
i PT-2-A-4204-01A PT-2-A-4206-03 PT-2-A-4209-03P PT-2-A-4201-04 PT-2-A-4204-02 PT-2-A-4451-02 PT-2-A-4209-02P PT-2-A-4404-02
PT-2-A-4502-02
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These tests as of April 29, 1983, have been satisfactorily completed.
Status: Closed
, License Condition:
1.q.
Provide satisfactory resolution of any deficiencies that may be identified during the preoperational testing program.
Resolution: Current information indicates that there are no pre-op deficiencies.
Status: Closed j
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License Condition:
1.r.
Complete the containment high-range monitor calibration test (NUREG-0737, ItemII.F.2.c).
f Resolution: TP-2-A-1600-01, Radiation Monitoring System Functional Test which tests / calibrates the containment high-range monitors,.2 EMF-51A&B was j
satisfactorily completed on March 1, 1983.
E Status: Closed 10. _DS-416 Reactor Trip Breaker-On March 11, 1983, IEB-83-04, Failure of the Undervoltage Trip Function of Reactor Trip Breakers was issued to all licensed PWR facilities except
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those with Westinghouse 08-50 reactor trip breakers. On March 22, 1983 the license issued a response to the bulletin containing in part, the following information:
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a.
Testing of Unit 1 and Unit 2 breakers was completed on March 18, and March 17, 1983, respectively. This testing resulted in no failures; however, subsequent testing resulted in several failures which are discussed in Item d.
b.
The preventative maintenance program for these breakers is detailed in Maintenance Procedure MP/0/A/2001/04, " Air Circuit Breaker Inspection and Maintenance". This procedure references the Westinghouse manufacturer's manual, " Instructions for Low-Voltage Power Circuit Breakers Type DS-206, DS-416, and DS-532".
Previous maintenance has been performed in accordance with these instructions. This preven-tative maintenance is scheduled to be performed on breakers for both units prior to startup. Previous maintenance activity had identified no problems with breakers.
c.
Provisions have been made to notify licensed operators of the failure of RPS breakers at Salem and San Onofre and to review the failure-to-trip emergency procedure upon their arrival on-shift.
d.
On Unit 2, during the preoperational testing of the Reactor Protective System, and Rod Control System in early 1983, failure of one RPS breaker to trip on UV was identified. This failure to trip on a UV signal was identified on five occasions during this testing. As a result of these failures, work orders were initiated to check the breaker.
This work was completed on February 18, 1983, with no apparent problems being discovered. However, as a result of the continuing investigation into this problem further testing was initiated on March 18, 1983, with three failures out of 125 cycles being observed on the same breaker, which had previously experienced the failures on Unit 2.
Thete failures were reported to the NRC via the emergency notification system on March 18, 1983.
Subsequent to these failures in Unit 2, a failure to trip on UV occurred on one Unit 1 RPS breaker on March 19, 1983, during routine response time testing of the reactor protective system. This failure was reported to the NRC on March 19, 1983.
e.
The RPS breakers are identified as safety-related in the McGuire
" Safety-Related Structures Systems and Components" manual.
Procure-ment, testing and maintenance activities of these breakers has been in accordance with the QA Program for safety-related components.
Subsequent to the failure of March 19, further failures, in conjunction with an array of unique failure modes prompted a meeting with NRC staff on April 19, 1982 in which the resident inspector also attended.
In that meeting subjects discussed included but were not limited to the description of breaker failures and the identification of the causes of the failures as detailed below:
Identification of Cause of Breaker Failure to Trip
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Introduction and Overview March 21 - Westinghouse representatives inspected the two McGuire breakers that had failed to trip on undervoltage. Their preliminary assessment was that the Unit 2 breaker failed due to binding in the undervoltage device, and the Unit 1 breaker failed due to improper clearance between the UV device and the trip shaft pin.
March 23 - The Unit 2 UV device was disassembled at Westinghouse factory.
Westinghouse concluded that binding of UV device was due to improper clearance between the device components.
March 28 - During preventative maintenance of the Unit 2 breakers, the bearing surface of the breaker trip shafts were found to be improperly machined. Westinghouse was asked to evaluate the trip shaft problems.
March 30 - McGuire received a preliminary telecopy of the dimension checks to be performed on the UV devices.
March 31 - Westinghouse provided final dimension check requirements. No
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McGuire breakers passed all of the checks. Catawha breakers were checked and two of the eight Catawba breakers passed April 1 - The two Catawba breakers that passed the test were transferred to McGuire, inspected, serviced, and cycled 10 times, and installed as the Unit 2 Train A & B Reactor Trip Breakers.
April 2 - The Unit 2 Train B breaker failed to trip via the UV trip device during a functional check prior to rod drop tests.
April 4 - Westinghouse personnel inspected the Unit 2 Train B breaker at McGuire and determined the failure to be due to dislocation of the UV device roller arm shaft. The dislocation was attributed to a snap retaining ring missing from the shaft.
April 6 - A new UV trip device supplied by Westinghouse was installed on the Unit 2 Train B breaker and cycled 25 times without any pro-blems.
Response time tests were conducted with no problems. Rod drop test was initiated. No subsequent breaker problems were discovered.
Subsequent to the April 19, 1983 meeting, a series of communications between the licensee and NRC resulted in what were to become license conditions for the two units. The proposed license conditions and related information were detailed in a letter from the licensee to NRC/NRR dated April 28, 1983.
Detailed below is a condensation of that correspondence:
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Westinghouse has been involved in the undervoltage device problems at McGuire since early of March 1983. Duke and Westinghouse personnel have worked together in the identification and resolution of the UV devices.
With one exception, the deficiencies noted in the DS-416 UV device have been discovered on the breakers at McGuire. Thus, the recommendations that have been issued by Westinghouse have been implemented at McGuire. These include:
(1) Replacement of UV devices with new devices with all manufacturing problems corrected and with modified grooves to accommodate the new retaining rings.
(2)
Installation checks on UV attachment to verify proper alignment and interface with the breaker trip shaft.
(3) Alerting operators to potential problems relative to reactor trip switchgear.
(4) Re-emphasize to the operators indications available to detect failure of rods to insert into the core.
Westinghouse also recommended in a March 31, 1983 letter that the operator initiate a manual trip following any reactor trip from the reactor protec-tion system. Duke did not implement this recommendation since 1) existing procedures (Reactor Trip and ATWS procedures) require a manual trip if reactor trip does not occur, and 2) a modification to the reactor trip breakers was made such that the shunt coil is energized as a result of any reactor trip signal from the reactor protection system.
This automatic shunt trip of the reactor trip breaker obviates the need for a follow-up manual trip by the operator.
Thus, with all the actions taken by Duke, the potential safety problems identified by Westinghouse in its Part 21 notification and its letter of
March 31, 1983 to the NRC have been addressed.
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The NRC Staff identified additional surveillance that should be performed to
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assure the operability of the reactor trip breakers. Duke evaluated the staff's proposed testing and discussed this testing in a conference call on April 27, 1983. As a result, the following testing will be performed in addition to that required by Technical Specifications.
It is proposed that f
these additional tests be added to the Technical Specifications after the program has had the benefit of additional review to determine the generic applicabilit __.
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Test Frequency
1.
Independent test of UV and Every startup if not performed shunt trip.
within previous 7 days.
2.
Test of Manual Trip from Every startup if not performed Control Room, within previous 7 days.
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3.
Response time test of reactor Every 62 days on a staggered test
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trip breaker on UV signal from basis such that one breaker is RPS.
tested every 31 days.
4.
Functional test of shunt trip Every 62 days on a staggered test i
of reactor trip breakers, basis such that one breaker is tested every 31 days.
5.
Force test on trip bar and UV Each refueling.
devices of reactor trip breakers
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and bypass breakers.
6.
Response time test of bypass Each refueling, breaker on UV signal from RPS.
7.
Functional test of shunt trip Each refueling.
on bypass breakers.
The startup testing and bimonthly testing specified will be performed at the frequency for at least one year. This will include trending of breaker response times. After one year an evaluation of the benefits versus the
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impact of the testing will be made. A decision on the need to change the frequency would then be made and appropriate changes proposed. Accordingly,
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the following is a recommended license condition for inclusion in the McGuire Units 1 and 2 facility operating licenses:
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"The licensee shall implement the reactor trip breaker and bypass breaker testing as described in Mr. Hal B. Tucker's letter of April 28, 1983. The licensee shall not make any major modifications to this program unless prior NRC approval is received.
Major modifications are defined as:
a.
Elimination of any identified testing.
b.
Changes in the frequency of performing the identified testing, and c.
Reduction in the scope of any of the required testing."
During the meeting with the NRC Staff on April 19, 1983 a copy of several test procedures and a maintenance procedure were provided. The staff, in reviewing the maintenance procedure, did not see evidence of adequate QA
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involvement.
In a conference call on April 27, 1983 it was explained that the maintenar.ce procedure by itself was not the only document that controlled QA/QC activities. The scope of QA coverage is specified in Maintenance Management Procedures which described the work request system and QA requirements detailing specific inspection requirements for
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electrical equipment including circuit breakers. Copies of the following documents were sent to the NRC staff on April 27, 1983 by express package service. They were:
(1) Copy of McGuire Nuclear Station Work Request Form (2) Procedures describing work request-Maintenance Management Procedure 1.0-Maintenance Management Procedure 3.0 (3) QA/QC requirements for inspection of electrical equipment (4) Revised copy of Air Circuit Breaker Maintenance Procedure Duke is pursuing with Westinghouse a follow-up evaluation and reliability program for the DS-416 UV device problems, and the commitments made for future actions provide a sufficient basis for operation of both McGuire units. All of these actions have been discussed in some detail with the NRC staff and general agreement was reached on the essential points. Accord-ingly, it is our intention to proceed with startup of both units consistent with the plant schedule (currently Unit 1 criticality is scheduled for May 4, 1983 and Unit 2 for May 2, 1983). However, operation will be limited to zero power physics testing on both units until receipt of the NRC staff safety evaluation report on the reactor trip breakers.
At the close of this report period the final resolution to this problem is yet to be concluded. Therefore, IEB-83-04 will ramain open pending resolution.
For further details concerning IE Bulletin Followup, refer to paragraph 5.
11.
Inadvertent S.I.
On the morning of March 29, McGuire Unit 2, was in Mode 5 when at 10:45 a.m., while energizing a cabinet of the solid state protection system (SSPS), an I&E technician inadvertently initiated a Train B Safety Injection. The S.I. in itself was relatively inconsequential in that no injection occurred nor was any system required for Mode 5.
Those systems /
components required to start / operate during an S.I. did so, unless de-ener-gized as a function of the operational mode.
In assessing the event, the inspector interviewed the technician to deter-mine the purpose of his efforts and the extent of procedural guidance employed.
It was recognized that the technician was attempting to return
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SSPS to normal lineup employing procedure IP/0/A/3090/02, Controlling Procedure for Instrument and Electrical Safety-Related Maintenance.
The S.I. occurred when the technician inappropriately manipulated switches 5501 and S502 in the SSPS Logic Test Panel through a sequence which gene-rated an initiate signal.
Procedure IP/0/A/3090/02 does not contain adequate guidance to facilitate the completion of a task of such complexity. The procedure was written to facilitate troubleshooting which had been completed, and the system was being returned;to normal. Moreover, as stated in the " Purpose" section of the procedure it (the procedure) is "...not to be. used to perform normal corrective or preventive maintanance that is of a complex or repetitive nature...".
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The procedure inadequacy discussed above coupled together with failure to follow another procedure for Unit 1 as described in the. subsequent paragraph constitutes a violation. Details of the violation are provided in
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Paragraph 12.
12. Containment Spray Test Deficiency
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On April 13,1983, at 10:55 a.m. during the attempted performance of PT-1-A-
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4208-018, Containment Saray Pump 1-B Performance Test, when the pump was started, it was noted tlat the pressurizer relief tank (PRT) level was
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increasing and the refueling water storage tank (RWST) level was decreasing.
The purpose of the test is to recirculate water from and to the refueling water storage ta'nk. The pump was stopped at 11:05 a.m., and an investi-gation ensued to determine the source of the PRT inleakage.
It was deter-mined that the.le'ak' age into the PRT was from the containment spray pump "A" suction line relief. valve, 1-NS-19.
It was subsequently determined that the i
flow path was from the discharge of the containment spray (NS)' pump "B" through the "A" and "B" recirculation valves, 1-NS-25 and 1-NS-8, through
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the "A" pump to the suction' header: Recirculation valve 1-NS-25 is to be closed while running the "B" pump in the recirculation mode.
The inspector in interviews with operations personnel determined that on the evening shift of April 12-13, 1983, Unit 1 operating staff person.nel performed what was to be the necessary valve-alignment to facilitate the
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performance of the above mentioned test.
H The reviewing the applicable test procedure PT-1-A-4208-01B, the inspector l
l noted that prerequisice 8.3 requires the NS system be aligned fpb automatic
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inii.iation pursuant to 0P-1-A-6200-07,. Containment Spray System. Pursuant to step 2.1 of that procedure valves 1-NS-8 and 1-NS-25 are to be' closed.
Step 12.1 of procedure PT-1-A-4208-01Bl0 pens 1-hS-8 creating the recircu-
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In a subsequent conversation with operations management personnel, it was concluded that the operating personnel who performed the valve lineup had failed to follow the procedure.
Tt.chnical Specification 6.8.1 requires that written procedures be esta-
.blished, implemented and ma ntained cover ng sa ety re ated system activi-i i
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ties (Regulatory Guide 1.33, Revision 2, February 1978, Appendix A, Iten3.d.).
Implic'it in that requirement is the necessity that the procedure be appropriate to the task and entail sufficient specificity to facilitate the desired results. Specifically, this refers to lack of procedural
. guidance to procedure IP/0/A/3090/02 as discussed in paragraph 11. Also, implicit in the Technical Specification requirement is the necessity to follow approved procedures.
Contrary to Technical Specification 6.8.1 the licensee used a procedure in-adequate for the task resulting in an S.I and failed to implement the requirements of procedure PT-1-A-4208-01B as described above. This is a violation (50-369/83-21-01, 50-370/83-29-01).
13. Missing Thermal Sleeve As reported previously in inspection report numbers 369/83-16 and 370/83-23, for one of the major maintenance items for the current Unit 1 outage was the removal of the RCS thermal sleeves.
Six of the seven thermal sleeves were removed during the outage, however, as detailed in an April 22, 1983 letter from Duke Power Company to NRC/RII the detached thermal sleeve which was thought to be in the reactor vessel has not been located despite an exten-sive search.
Duke. Power has concluded that the detached thermal sleeve is not in the Reactor Coolant System (RCS). Although the mechanism for its removal from the RCS cannot be conclusively determined, it is believed that the thermal sleeve became detached during preoperational testing and was removed fron: the RCS before initial fuel loading. An investigation by the McGuire Safety Review Group has identified no deviations from approved station procedures and no failures to fulfill quality assurance require-
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ments. Therefore, the. licensee plans to return the unit to operation at the conclusion of the current cutage in late April.
In searching for the detached thermal sleeve, all fuel assemblies were removed and video taped. inspections were made of all places in the reactor coolant system where the 13 cold leg accumulator injection line thermal sleeve could have traveled after coming loose, i.e. the reactor vessel and the RCS cold legs. The inspectors also looked for any unusual signs of wear, loose or broken parts, or damage due to the loose thermal sleeve.
t The lower core plate prevents the thermal sleeve from entering the hot legs.
All four reactor coolant sy; tem cold legs were inspected from the reactor vessel to the reactor coolant pump turning vanes at the pump discharge.
These vanes were chosen as a boundary because reverse flow through any pump after it is shut down would not take the sleeve past the turning vanes even if the sleeve were/ broken into quarter section pieces.
Video tapes made
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February.24, 1983. show the inspection of these areas. No thermal sleeve or impact danage possibly caused by the thermal sleeve was found in these areas.
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The lower interHals were removed and inspected from the sides and bottom.
Video tapes made of the_se areas revealed no sign of the thermal sleeve or
' impact damage caused by the sleeve in these areas. A video taped inspection
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was then made inside the empty reactor vessel. Again no evidence of the thermal sleeve was found and there-was no indication of either wear marks or
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TThe lower internal' areas were reinspected on March 28, 1983 after the core t
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support structure was installed by looking through the lcwer core plate flow-holes and by-yoing through selected periphery and central lower core plate t
flow holes. There was:no sign of the thermal sleeve or wear or impact scars caused by,the sleeve-in these areas.
The licensee concludes that visual inspection of the vessel included all areas that the thermal sleeve could physically have gone, therefore they are certain that even though the thermal sleeve has not been found, it is not in the reactor vessel or any of the connecting piping systems.
'The McGuire Safety Review Group investigated the incident concerning the detached thermal sleeve. Conclusion drawn;from this investigation are:
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(1). The thermal sleeve was originally installed in the RCS.
(2)
Infp?ction of the "B" loop nozzle where the sleeve was installed
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indicated that the sleeve broke loose and wore down the weld
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(3)'L The thermal sleeve is not currently in the RCS.
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testing and was removed fron tFe RCS, although this cannot be
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(s) No administrative or personnel errors were identified.
At the close of the report period the licensee plans startup and operation of the unit pendfog any negative response.
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