IR 05000155/1989013
| ML20245E648 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 08/01/1989 |
| From: | Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20245E635 | List: |
| References | |
| 50-155-89-13, IEB-85-003, IEB-85-3, NUDOCS 8908110311 | |
| Download: ML20245E648 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No.'50-155/89013(DRP)
Docket No. 50-155 License No. DPR-6 Licensee:
Consumers Power Company 1945 Parnall Road Jackson, MI 49201 Facility Name:
Big Rock Point Nuclear Plant Inspection At:
Charlevoix, Michigan Inspection Conducted: -June 18 through July 24, 1989 Inspectors:
E. Plettner
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N. Williamsen D. Schrum M. Huber Approved By:
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.' Ja kiw ief
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'f R ctor Pro ts Section 2B Date Inspection Summary Inspection on June 18 through July 24, 1989 (Report No. 50-155/89009(DRP))
Areas Inspected: -The inspection was routine, ur.3~1ounced, and conducted by the senior resident. inspector, the resident inspector, the project inspector, and a regional inspector.
The functional areas inspected consisted of the following:
management meetings; installing ad testing of modifications; refueling activities; surveillance activicies including those required for reiv' ling; maintenance activities on vatious components; operational safety verification including the emergency co,1 denser system; balance of plant; pump and valve inservice testing; and IE Bulletin and Temporary Instruction closure.
Results:. The licensee has responded in a timely manner to issues and concerns presented to them by the NRC.
The management meetings, modifications, surveillance, maintenance, balance of plant, and the pump and valve inservice testing programs appeared to be performed in a manner to ensure public health and safety.
Three violations were identified in this report:
one in refueling activities concerning inadequate tool controls and two.in operational safety verification concernirg failure to follow radiation protection procedures and l
performing an inadeque.e review of procedures.
8908110311 99o909
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DETAILS
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L 1.
. Persons Contacted
- l. Elward, Plant Manager
- R. Abel, Production ~and Performance Superintendent R. Schrada, Senior Engineer H. Hoffman, Maintenance Superintendent
- G. Withrew, Engineering Superintendent
- S. Beachum, Senior Engineer, Maintenance W. Trubilowicz, Operations Supervisor M. Bielinski, Senior Engineer, Plant Performance
- L. Monshor, Quality Assurance Superintendent
- D. Lacroix, Nuclear Training Administrator
- P. Donnelly, Nuclear Assurance Administrator
- J. Beer, Chemistry / Health Physics Superintendent
- R. Alexander, Technical Engineer E. Zienert, Director Human Resources M. VanAlst, Property Protection Supervisor
- T. Dugan, Property Protection Operations Supervisor The inspectors also contacted other licensee personnel in the Operations, Maintenance, Engineering, Radiation Protection, and Technical Departments.
- Denotes those present at the exit interview on July 24, 1989.
2.
Management (30703)
The Branch Chief, Reactor Projects Branch 2 visited the site and conducted several inspections.
Areas inspected included:
turbine deck, lower turbine deck and temporary GE turbine maintenance area, core spray recirculation pump room, UPS battery rooms, fire pump / core spray room, protected area perimeter fence, central clarm station, control room, machine shop, TSC, and inside containment.
Containment activities observed included routine refuel activities.
Considering the unit was in an outage, routine housekeeping and general.adioactive material controls appeared adequate.
No violations were observed.
The inspector noted the NRC bulletin board for routine regulatory posting was obscured from view because of the metal detector.
The licensee agreed to relocate the board to ensure its visibility.
2.
Installation and Testing of Modifications (37828)
The following inspection was performed on minor plant system modifications not submitted for NRC approval.
The inspection evaluated onsite system modification activities including:
hardware installation, system testing, quality assurance, updates to drawings and procedures, and verified conformance with the requirements of Technical Specifications; 10 CFR 50.59, " Changes, Tests and Experiments"; and 10 CFR Part 50, Appendix B, Criterion III, " Design Control".
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Two modifications were selected for inspection:
' Facility Change 636 was for nn wiring, raceways, and terminal blocks
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associated with the pressure anc level switches on the control rod drive accumulators to alleviate corrosion problems resulting in excessive.
maintenance work.. Facility Change 643A was for the initial' phase of cable replacement in the recirculation pump room, to eliminate' concerns
.regarding aging and embrittlement of the existing cables.
The resident inspectors verified by observation and record' review that-the modifications were properly installed and tested by qualified workers using approved procedures, drawings, and appropriate qualiS assurance-holdpoints.
System drawings were updated as required.
No' violations or deviations were identified in this area.
3.
Refueling Activities (60710)
Preparations' for refueling and ufueling activities were observed /
reviewed to ascertain that the activities. were meeting approved procedures and were in conformance with Technical Specifications.
During.a tour of the' reactor containment on June 14, the project inspector noted loose materials on the reactor building crane.
The licensee was informed and took corrective action.
On June 30, 1989, the resident inspector made a tour of the reactor building crane and again found loose tools-and material. The tools and materials were not listed on. log sheets or connected to a tether.as required.
Administrative Procedure Volume 1, No. 1.8, " Plant Housekeeping and Cleanliness",.Rev. 1, dated April 5, 1988, states in Section 4.1.3, " Tools, equipment, materials, and supplies shall be controlled, through utilization of such items as log sheets and tethered tools in areas requiring special_ considerations, to prevent the inadvertent inclusion in critical systems." 'The reactor bu;1 ding crane is a designated tool control area.
The failure to comply with the Plant Housekeeping and Cleanliness procedure is an apparent violation (155/89013-01).
The licensee took immediate corrective action by removing the tools and materials and performing a followup survey of the area.
A Deviation Report, No. D-BRP-89-34, was written by the licensee to review all related procedures, including training procedures, and to make changes to prevent future noncompliance.
The resident inspectors observed the fuel reloading conducted during the period of July 13 through July 15, 1989.
The fuel reloading was performed in a proper and professional manner, using the following procedures:
TR-46, " Fuel Bundle Core Loading Procedure", Rev. 26, dated May 12, 1989, including a Procedure Change Form dated July 11, 1989; and System Operating Procedure (SOP) 44 " Spent Fuel Pool operations and New i,
Fuel Handling," Rev. 126, dated October 8, 1987.
Status boards and records of fuel bundle locations were verified to be in accordance with procedure TR-46, Attachment 1.
Shutdown margin measurements and physics tests were conducted satisfactorily following fuel reloading using the following procedures:
TR-43 " Shutdown Margin Check", Rev. 17, dated March 8, 1989, and TV-42 " Reactor Core Physics Test Heads-off Critical",
Rev. O, dated May 11, 1989.
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l One violation and no deviations were identified in this area.
4.
Monthly Surveillance Observation (61726)
Station surveillance activities listed below were observed to verify that the activities were conducted in accordance with the Technical Specifications and surveillance procedures.
The applicable procedures were reviewed for adequacy, test and process instrumentation was verified to be in their current cycle of calibration, personnel performing the tests appeared to be qualified, and test data was reviewed for accuracy and completeness.
The NRC inspectors ascertained that any deficiencies identified were reviewed and resolved.
The NRC inspectors observed the licensee's performance ci the following surveillance tests on the indicated dates:
June 22 TR-84 " Emergency Diesel Generator Inspection and Repair",
Rev. 11, August 26, 1987.
June 23 TV-41, " Inspection of Big Rock Point Irradiated Fuel Assemblies", Rev. 1, June 8, 1988.
June 25 TR-41, " Station Power Transfer Test", Rev. 15, April 27, 1989.
During the performance of this surveillance certain events called out in the procedure did not occur.
The i
licensee immediately submitted a Deviation Report, No. D-BRP-89-31 to evaluate and determine the root cause.
Root cause was determined to be procedural inadequacies or clarifications associated with incidental equipment operation during the Station Power Transfer Test.
The licensee submitted a Procedure Change Form to correct the problem.
No safety issues were identified as a result of the deficiencies identified in the Deviation Report.
June 26
_ TR-65D, "RDS-UPS D' Battery Service Test and Discharge Alarm Operability Verification", Rev. 12, April 10, 1988.
June 28 TR-57, " Standby Diesel Generator Load Test", Rev. 10, June 14, 1989; with Procedure Change Form, expiration date July 31, 1989.
June 29 TR-42, " Emergency Diesel Generator Full Load Test", Rev. 14, July 2, 1988.
July 6 TR-85, " Diesel Fire Pump Inspection / Repair (Formerly MFPS-2)", Rev. 9, June 22, 1988.
July 7 TR-01, " Control Rod Drive Performance Test", Rev. 20, j
dated July 7, 1989.
July 8 TR-39D, " Emergency Condenser Isolation Valves and Gauge
Glass Leak Rate Test", Rev. 42, dated March 21, 1989, with Procedure Change Form, expiration date August 15, 1989.
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July 10 TR-70, " Fire Suppression Water System Functional Test and i
L Pump Capacity Test", Rev. 10, dated May 26, 1989.
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J July 11 TR-21 " Control Rod Drive Friction Testing Procedure",
Rev. 14, dated January 13, 1989.
i July 13 TR-32 " Reactor Protection System Scram Sensor Test", Rev. 19, dated March 16, 1989, in conjunction with Maintenance Work Request 89-RPS-0019, dated April 4, 1989.
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JC, 16 TR-43 " Shutdown Margin Check", Rev.17, dated March 8,1989 July IT
"!-2 " Reactor Core Physics Test Heads-off Critical", Rev. O, dated May 11, 1989.
July 20 TR-71, " Fire Protection Systems Deluge Test", Rev. 11, dated November 29, 1988.
July 22 TR-99, " Surveillance Check of Alternate Shut Down System Equipment", Rev. 4, dated June 29, 1989, with a Procedure Change Form dated July 22, 1989.
No violations or deviations were identified in this area.
5.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and components 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.
The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the 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 control records were maintained; rctivities were accomplished by qualified personnel; parts and materials used were cartified; radiological and fire prevention controls were implemented.
Work requests were reviewed to determine the status of outstanding jobs
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-and to assure that priority was assigned to safety related equipment maintenance which may affect system performance.
The NRC inspectors observed the licensee's performance of the following maintenance work orders on the indicated dates:
June 19 No. 89-RD5-004o, dated May 12, 1989, for full-stroke testing of Reactor Depressurization System valve "D".
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.s June 20 No. 88-EPS-0141, Emergency Diesel Generator dated 6/20/89 in conjunction with Surveillance Procedure TR-84,
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" Emergency Diesel Generator Annual inspection", Rev. 11, August 26, 1987.
June 23-2 No. 89-CRD-0056, dated June 2, 1989,_for re-wiring the control rod drive accumulator pressure and level switches.
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June 26 No. 89-EPS-0106, dated May 3, 1989, to install twenty new batteries in Uninterruptible Power Supply, battery bank
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June 26 No. 89-RCS-0011, dated May 11, 1989, to test the relief pressure of relief valve RV-5025.
June 26 No. 88-PIS-0058, dated September 28, 1988, for inspecting electrical boxes in the Post Incident System (ECCS).
June 27 No. 89-LRS-0010, dated May 24, 1989, for installing cables in the new conduit in the Recirculation Pump room.
June 27 No. 88-SLO-0022,' dated August, 18, 1988, for replacing two multi point temperature recorders in the Control Room, as part of a continuing upgrade program implemented by the licensee.
July 5 No. 89-ECS-0016, dated April 27, 1989, for maintenance on valve operator MOV-7052, including determining the as-found setting of the limit switches and re-setting if necessary.
July 6 No. 89-ECS-0019, dated April 27, 1989, for checking the limit switch setting on valve operator M0-7062, and resetting if necessary.
July 6 No. 89-RDS-0103 and 0104, dated June 22, 1989, for correcting RDS Pilot Isolation Valve seat leakage and Isolation Valve bearing repair.
July 10 No. 89-PIS-0048 and -0049, dated April 27, 1989, for inspection and setting of limit switches on Limitorque Valve operators M0-7051 and M0-7061, respectively.
July 16 No. 89-NMS-0061 dated July 15, 1989,for running a discriminator plot on neutron source range monitor, Channel 7.
No violations or deviations were identified in this area.
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l 6.
Operational Safety Verification (71707)
The NRC inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during the inspection period.
Instrumentation and recorder traces were examined for
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abnormalities and discussed with the control room operators, as were the-
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status of control room annunciators.
Reviews were conducted.to confirm-that the, required leak rate calculations were performed and were within
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Technical Specifications limits. A system walkdown was performed to.
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verify the operability of the emergency condenser system.
Tours of the containment sphere 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
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initiated for equipment in need of maintenance. ' Radiation protection controls were inspected, including radiation work permits, calibration of radi4 tion detectors, and proper postir.g and observance of radiation and/or contaminated areas.
The inspectors observed site security measures including access control of personnel and vehicles, proper display of identification badges for personnel within the protected area, and compensatory measures when security equipment had a failure or impairment.
During the first week of the outage starting June 9, 1989, the senior..
resident inspector noted that several individuals failed to complete all required entries on the Radiation Work Permit Entry Log Sheet-(Form BRP051).
Section 5.0.c of Administrative Procedure Volume 1, Procedure 5.5, " Radiation Work Permit" Rev. 2, dated July 21, 1988 states in part, "All attachments to the radiation work permit are considered a part of the radiation work permit and require compliance"..The concern was brought to management's attention with subsequent corrective action.
The senior resident inspector during this inspection period identified more occurrences of procedure non-compliance on June 23, July 6, and July 17, 1989.
Each occurrence was brought to management attention to
' implement Edditional corrective measures.
The subsequent corrective actions appeared effective at the end of this inspection period.
The failure to comply with the Radiation Work Permit procedure is an apparent violation (155/89013-02).
The following procedures were reviewed by the Licensing Project Manager as part of an evaluation:
IRPS-1 Rev. 10, IRPS-4 Rev. 12, IRPS-5 Rev. 9, IRPS-6 Rev. 9, IRPS-9 Rev. 8, IRPS-10 Rev. 5 and TR-32 Rev. 19.
During the review, 6 of 7 procedures reviewed had typographical errors and in several of the procedures specific steps were absent or missing information.
Section 6.8.1 of Technical Specifications states in part that procedures defined in the Big Rock Point Quality List shall meet or exceed the requirements of ANSI N18.7 as endorsed by CPC-2A, Consumers Power Company's Quality assurance program implementing Appendix B of 10 CFR Part 50.
Appendix B section VI, " Document Control", states in part that measures shall assure that documents, including changes, are reviewed for adequacy and approved for release by authorized personnel.
The failure to perform an adequate review of procedures is an apparent violation (155/89013-03).
The licensee submitted Procedure Change Forms to correct the deficiencies before the procedures were used by licensee personnel.
Two violations and no deviations were identified in this area.
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Balance of Plant Inspection (71500)
The following inspection was performed to evaluate the effectiveness of the preventive and corrective maintenance programs for the Balance of Plant (B0P) systems.
Included in the evaluation were the areas of l
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management's effectiveness, B0P modifications, BOP operating procedures, and the licensee's root cause analysis.
The inspector reviewed the maintenance program and related documents including completed work requests and deviation reports to verify that equipment failures in the B0P system were evaluated for input into the preventive and corrective maintenance (CM) program.
Vendor manuals and manufacturer representatives inputs were used to improve the programs.
The existing preventive maintenance (PM) program has constantly improved over the last 15 years through changes in the performance periodicity and expanding the equipment list.
For many PM work items, the computer generated Periodic Activity Control Systems (PACS) sheets include a list of tools and procedures required to perform the task.
There have been no late PMs during the current year to date.
The inspectors attended several Corrective Action Review Board (CARB) and Plant Review Committee (PRC) meetings to evaluate management's effectiveness.
Management was responsive to self-identified B0P problems and those identified by NRC inspectors.
Included were the licensee responses to the Systematic Assessment of Licensee Performance (SALP)
Report 155/89001 and the subsequent management meeting documented in Inspection Report 155/89009, NRC IE Notices, Generic Letters and Bulletins. The licensee does participate in various owners' groups that address B0P problems and solutions.
The B0P modification process was thorough and complete.
The extensive check-offs done during the modification review process attempt to evaluate every conceivable interaction the modification may have on the I
system being modified and with other plant systems.
Safety evaluation reviews pursuant to 10 CFR 50.59 were performed for those modifications that required a change to the system or component description in the Final Hazards Summary Report.
The interfaces between engineering, quality assurance / quality control, and maintenance were well defined and functional. Good communications were noted between the va','ious l
departments.
Large improvements in the B0P portions of the plant ob urred during the 1989 outage with a major overhaul of the turbine bi.ng one of the improvements.
B0P operation procedures for the system were consistent with the as-built drawings for the system and reflected recent modifications.
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procedures were located in the control room and at applicable areas of the plant, e.g., condensate demineralization station. Material condition
.of the plant was adequate to assure component operability and valve line up was verified in the "as left" position documented in the latest valve checksheet. Operators were trained in and knowledgeable of recent system modifications that affected operations.
B0P maintenance was done by work orders and procedures, but more simple work items were left to the skills i
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of the crafts. The plant has been working on a project to upgrade existing procedures and prepare new procedures to ensure uniformity of work practices in the skill of the craft positions.
Three full time
_ personnel were assigned to write the procedures.
The individuals were well qualified for the job having been maintenance supervisors and/or superintendents at nuclear facilities.
A program for root cause analysis _was implemented but not approved formally in procedures. The licensee wanted a trial program for a year,to make adjustments in the program before final approval.
The licensee's tracking system used in root cause analysis appears adequate for the size of the plant. The completed maintenance orders were reviewed for
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completeness and entered in the equipment history file.
The equipment history can be reviewed to make decisions on what componert was repaired / replaced and if a reoccurring problem exists.
-The BOP programs appears to be adequate and improving under managements'
direction.
No violatiens or deviations were identified in this area.
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8.
Pump and Valve Inservice Testing (IST) Program Implementation (73756)
The licensee's pump and valve IST Program implementation was inspected to verify compliance with Appendix 8 of 10 CFR Part 50; 10 CFR Part 50.55a(g); and Subsections IWP and IWV of Section XI of the ASME Code (1977 Edition with Addenda through Summer, 1978).
The :nspection included a review of administrative controls, selected surveillance procedures, test results, and documentation.
Throughout the inspection period the senior resident inspector observed the activities associated with the Reactor Depressurization System valves (RDS).
These activities included the full stroke testing, valve leakage testing, disassembly of one valve for inspection and non-destructive testing, replacement of 1-inch isolation. valves, reassembly and post-maintenance testing.
The testing was performed using Procedure TR-101-RDS, "Depressurizing Valve Test", Rev. O and Rev.1 with Procedure Change Form, dated June 22, 1989, in conjunction with the following Maintenance Work Orders:
No. 89-RDS-0045 through 0048, dated May 12, 1989, No. 89-RDS-0103 and -0104 dated June 22, 1989, and No. 89-RDS-0126 dated July 1, 1989.
All four valves were successfully full-stroke tested and passed the minimum pressurization test.
All valves were then mechanically opened to check limit switch positions to ensure valve travel was the required full-stroke distance of approximately 2 inches.
RDS valve "D" was disassembled for visual and nondestructive testing.
The "D" valve showed no signs of excessive wear or corrosion as had been experienced during the last outage when one of the valves failed to full-stroke test because of excessive corrosion and pitting of the valve stem.
The cause of the corrosion and pitting was documented in Inspection Report 50-155/89002.
The licensee documented the current findings through high quality / resolution photos and engineer evaluations.
Maintenance performed earlier on the spare RDS valve revealed problems in the 1-inch
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pilot isolation valves. The ball b' earings associated with the valve-hadl become. corroded causing the' valve'.to malfunction.
The valves had been
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-purchased last year from another utility who had~ stored the valves for several years.
The licensee replaced all the bearings in the RDS pilot valves.
No violations or deviations were identified in this area.
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9.
, Licensee Action on IE Bulletins (IEB)
.(Closed) TI 2515/73 and IEB No.'85-03 (155/85003-BB) and Supplement 1 (155 85003-18)):
Motor-Operated Valve (MOV) Common Mode Failure During Plant Transients.Due-to Improper Switch Settings.
The bulletin requested licensees:to' develop and implement a program to ensure that switch settings on certain safety-related M0V's were selected, set, and maintained' correctly to accommodate the maximum differential pressures expected on these valves during both normal'and-abnormal events within'the design basis.
The NRC staff issued Supplement 1 of'the bulletin on April 27, 1988 and a Request for Additional Information (RAI) to the' licensee on May 11,.1988.
Subsequently, the licensee'provided the. required responses on June 2,
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1988.
On September 1, 1988, the licensee was netified that their program-to assure valve operability was approved by the !MC.
a.
Program Scope
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The motor operated valve included for consideration in the IEB 85-03 response is M0-7071, the valve closest to the reactor in the back-up core spray system.
M0-7071 has a rotork operator, Model 14NA1, which is a 480 volt AC powered operator.
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Switch Setting Evaluations
.Below is a discussion of the switches involved and concerns for.
their proper setting, typical setting approaches that have been taken in the industry, and the resolution adopted at the Big Rock Point plant.
The switches discussed are as follows:
Thermal overload relay
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Open torque switch Close torque switch
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Geared limit switch Open limit Open indication Open torque switch bypass Close limit Close indication Close torque switch bypass
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(1) Thermal Overload Relay
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. Discussion: Thermal overloads are sometimes used to protect motor. winding insulation from breakdown. Devices used consist of heaters at the-motor control center which trip a heat sensitive relay, the contacts of which either interrupt current to the contactor. closure coil (which stops the motor) or initiate an overload alarm, or both.
Where thermal overload relays stop operator. motor rotation.
on tripping, the heaters must either be sized to prevent
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inadvertently stopping the motor, or bypassed.when motor operation.is important to safety.
Site Specifics: Big Rock Point utilizes the thermal overload switch during testing and bypasses the thermal'
. overload during normal operation..Following testing where the thermal overload is in the circuit, realignment of the bypass removing the thermal overload from the circuit is done and.is then independently verified prior to putting the valve back in service. This is an acceptable configa ation.
(2). Open Torque Switch Discussion: This switch is normally used as a mechanical fuse to limit the mechanical thrust applied to a valve or operator.when stroking the valve in the open direction.
It generally provides no normal control function and is a backup for some other failure that may require its need.
If the switch is used, it must be set properly to enable the valve operator to apply adequate thrust on the valve stem to operate the valve against the limiting differential pressure ~(dp).
Site Specifics: The design of the rotork operator incorporates a switch mechanism that defeats the torque switch when the open limit switch is used to stop valve travel, which is the configuration at Big Rock Point. The open torque switch is not a concern.
(3) Close Torque Switch Discussion: The close torque switch is normally used to stop motor rotation on the completion of valve travel in the close direction. The limiting requirement for closure is at the end of travel when the thrust requirements are highest. The thrust at torque switch trip should equal the most limiting closure thrust requirement including the thrust needed to overcome the dp across the valve.
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Site' Specifics: The valve in the bulletin utilizes the close E'
torque switch to cut off the~ operator motor halting valve n
travel when the valve is fully closed.
The licensee.has P
set the switch setting based on the manufacturer's recommended' setting.
Changes to the switch are controlled by-the. requirement to only change the setting following consultation with a representative from the valve manufacturer ar.d by procedure, which verifies the ' setting to be left in its' original configuration following.
maintenance.
.(4)' Open Limit Switch
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Discussion: This switch provides the control function of determining-the upper limit of valve stem travel in the open direction and stops motor rotation by opening the circuit to the associated motor contactor coil. The-setting.of this-switch must provide an adequate valve stroke but, normally, must prevent backseating.
Deliberate backseating using the power of the motor-operator, or motor inertia, can and has caused valve stem shearing, stem thread. twisting, und valve' bonnet metal working until stem scoring and packing blowout occur.
Hence, it is important to set the open limit switch away from the backseat and with enough margin to allow for motor contactor dropout time and inertia.
Site Specifics: Big Rock Point has set the open limit switch to open such that the valve does not backseat. The
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open limit switch setting is verified manually following
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electrical operation of the valve-following inspection or maintenance using procedure No. MPIS-15 titled, "Rotork Actuator Model 14NA1 Switch Mechanism Checkout of Backup Core Spray Valves MO-7070 and /or MO-7071." No problems were noted with this arrangement.
(5) Open Indication Discussion: Open indi:ation is usually identified by the presence of a red light that goes out only when the valve is fully closed.
Often the same rotor is used for the open torque switch bypass, which may cause problems because of conflicting requirements for the two functions.
In setting for ideal position indication, there is not adequate bypass of the torque switch to assure valve operability; conversely, changes to satisfy the bypass requirements have resulted in false valve position indication.
Site Specifics: Open indication is set to provide actual indication of valve position upon valve opening. The switch is set to actuate on closure into the seat. That
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v is to say,'as soon as the valve comes off the seat the-p open. indication will be given. With this configuration-f accurate val.ve position is given and is an. acceptable approach.
(6) Open Torque' Nitch Bypass Discussion: When an.open torque switch is used, th'e bypass switch is required to function during the initial portion of the 'open stroke so that the torque switch will not uL prematurely stop valve travel due to the high torque conditions required for initial valve movement. There is no clear answer on where to set the bypass'; but,. if the valve disk (not the stem) has moved between 10% and.20% of its total: travel distance away from the seat when the bypass. opens, this,has been accepted.as adequate.
Site Specifics: The open torque switch bypass is not used on M0-7071 at Big Rock Point due to the valve operator
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design. The operator design defeats the open torque switch when the open limit switch is used and therefore, there is no concern for the setting of.the switch.
Bypass is verified by correct use of the open limit switch.
(7) Close Limit Switch Discussion: The close limit' switch is not often used on rising stem' valves. When it is utilized, it is:usually related to a special application and takes the place of the'close torque switch by. opening the motor circuit at the end of. valve closure.
Site Specifics: The valve in the bulletin is wired to "close on limit." The circuit is opened for the valve, stopping the motor by actuation of the close torque switch.
-(8) Close Indication Discussion: Close indication is usually identified by the presence of a light that goe. ut only when the valve is fully.> pen. This function is usually Jerived off the same rotork as the open limit switch, and wh le concern exists for the setting of the open limit, no problem has been identified with the corresponding closed indication light switch.
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Site Specifics: The close indication corresponds to the open limit switch actuation on MO-7071. There were no problems noted with this configuration.
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(9) Close Torque Switch Bypass
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Discussion: The close torque' switch bypass acts in the.
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.same manner as the open torque switch bypass; however, contrary.to its counterpart function, it normally bypasses.
the torque. switch during the lightest' duty portion of the
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stroke.. If ~ utilized, it should 'be set to operate during-
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the initial part of the stroke.
Site Specifics: The setting of close torque switch bypass is not a concern since the valve was properly guarded.
against backseating.
c.
Demonstration of Operability The bulletin. required valve testing at the maximum differential pressure determined from the design' basis analysis or conditions resulting from inadvertent mispositioning of the valve to demonstrate operability.
In accordance with their approved program, the licensee conducted testing.of the M0-7071 in' July 1988 and May 1989.
' Procedure No. T30-22 titled, " Emergency Core Cooling System Valve Tests," was performed in July 27,'1988 following startup.
If there is no leakage across the valve, performance of T30-22 verifies operability of M0-7071 under high differential pressure.
Conversely, shutdown Procedure No. 0-TGS-1, titled, " Master Check-Off Sheet," requires stroking MO-7071 when reactor pressure is less than 50 psig to ensure that the valve is' verified to stroke
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under maximum expected differential pressure if there is leakage across the valve. This test was recently performed in May 1989 for the current outage. M0-7071 was successfully stroked during both surveillance, d.
Maintaining Correct Switch Setting Action Item d of the bulletin requires plant procedures that will assure the maintenance of correct switch settings throughout plant life. To some extent, this involves all programmatic activities that assure long term valve operability because wear and degradation of either the valve or operator affect the adequacy of the switch settings.
The licensee has procedures in-place to perform maintenance on the valve and operator. These procedures are:
(1). MPIS-12, " Inspection and/or Repair Backup Spray Valves M0-7070 and M0-7071," dated 7/2/88.
(2) PMIS-15, "Rotork Actuation Model 14NA1 Switch Mechanism Checkout of Backup Core Spray Valves M0-7070 and/or MO-7071," dated 7/14/88.
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'(3) MGP-19, " Motor Operated Valve Component Inspection and
. Packing Adjustment," dated 4/10/89.
- The inspector. reviewed the procedures listed above to determine if applicable industry recommendations were considered in the preparation of the procedures. The NRC inspector also verified that the procedures supported the licensee's methodology and approved program.
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These procedures required personnel to return the valve to its as-found configuration following any maintenance done on the valve.
Additionally, no changes to the established settings may be made unless the valve and actuator manufacturers are consulted.
In addition to the procedures in place to direct maintenance activities, the licensee has a system to schedule the maintenance activities.
This.is done through the Periodic Activity Control System (PACS).
The Maintenance activity Inspect Oil Level of the Operator, for example,.is scheduled on the PACS. The PACS coordinator then reviews the PACS data and schedules the activity. The schedule is-then forwarded to the planning group to establish the timeframe for operations and maintenance to complete the maintenance activity.
When the activity. is scheduled,-it is recorded in the Daily Log-In Journal to record the activity and its completion date.
The PACS specifies the activity title and description, the equipment ID, date scheduled and date due, and a description of.the specific details required by the technician to plan the job. This system may provide better trending and testing documentation to allow the licensee to better detact and prevent valve degradation.
e.
Undervoltage Capability The Rotork operator was sized for a voltage drop of 30% by the vendor.
Big Rock Point recalculated the nominal stall torque requirement (the maximum torque that could be delivered by the operator) to ensure that the valve could deliver adequate thrust to the operator against the maximum expected differential pressure using plant specific data.
The NRC inspector reviewed the calculations made by the licensee which assumed only a 20% voltage loss, due to plant conditions such as emergency diesel start at 15% rated voltage. The licensee's calculation showed that a margin does exist to allow the valve to deliver adequate thrust at 80 percent rated voltage.
No problems were noted.
f.
Conclusions The licensee has addressed 411 the significant aspects of the bulletin. The commitments communicated t-the NRC in the references (listed below in 8.g) were verified to be met. Based on the review
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of the licensee activities, it was concluded that there is reasonable l
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assurance that the valve covered under the bulletin can perform its safety function during normal and abnormal operation. This
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item is closed.
g.
References 1.
Letter from K. W. Barry, CPCo to J. G. Keppler, USNRC, Region III dated May 6, 1986.
I 2.
Letter from R. R. Frisch, CPCo to USNRC dated December 28, 1987.
3.
Letter from R. R. Frisch, CPCo to USNRC dated February 1,1988.
4.
Letter from K. W. Berry, CPCo to USNRC dated June 2,1988.
5.
Letter from K. W. Berry, CPCo to USNRC dated January 20, 1989.
9.
Exit Interview The inspectors met with licensee representatives (denoted in Paragraph 1)
throughout the month and at the conclusion of the inspection period and
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summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any such documents or processes as proprietary.
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