IR 05000282/1989029
| ML20012D728 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 03/15/1990 |
| From: | Burgess S, Choules N, Grant W, James Heller, Jablonski F, Slover W, Ulie J, Walker H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20012D724 | List: |
| References | |
| 50-282-89-29, 50-306-89-29, NUDOCS 9003280294 | |
| Download: ML20012D728 (33) | |
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I U. S. NUCLEAR REGULATORY COMMISSION
REGION III
l Reports No. 50-282/89029(DRS); 50-306/89029(DRS)
Docket Nos. 50-282; 50-306 Licenses No. DPR-42; DPR-60 Licensee: Northern States Power Company P. O. Box 59040 Minneapolis, MN 55459-0040
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I Facility Name:
Prairie Island Nuclear Generating Station - Units 1 & 2
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Inspection At: Prairie Island Site, Welch, Minnesota e
Inspection Conducted: January 8 through 12, and January 29 through February 23, 1990 Inspectors:
3D.&-yo 8-i4 90 C D' BurgeW Team Leader Date
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R. 0. Haroidsen EG&G Idaho 9003280294 90o319 b
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F. JC,/Jablonski, Chief Date
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Maintenance and Outages Section (
Inspection Summary Inspection on January 8 through 12_, 1990 and January 29 through February 23
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T990 (Reports No. 50-282/89029(DRS): 50-306/89029(DRS)).
Areas Inspected:
Special announced team inspection of maintenance, engineering, fire protection, support of maintenance, and related management activities. The
inspection was conducted utilizing Temporary Instruction 2515/97, the attached i :.
Maintenance Inspection Tree, and selected portions of Inspection Modules
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62700, 62702, 62704,.62705, 64150, and 64704, to ascertain whether maintenance
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Results: Based on the items inspected during the period that the inspection
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was conducted, overall performance in mainter,ance was considered good.
A-synopsis of the.overall implementation of the maintenance program is provided e
in Section 3.0 of the report.
There were three violations: failure to follow
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. procedures with five examples; failure to take adequate and timely corrective action with two examples; and two examples of a Technical Specification 6.5 violation regarding required approvals when changes were made to maintenance procedures.
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CONTENTS e
Section, Page
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Principal Persons Contacted....................................
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Introduction to the Evaluation and Assessment of Maintenance... 4 Performance Data and System Selection..........................
2.1.
2.1 1 Historic Data..................................................
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. Sy s t em S e l e c t i o n................................................ 5 i
2.2-
' Description of Maintenance Philosophy..........................
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2.3-Observation of Current Plant Conditions & Ongoing Work.........
2.3.1 Current Material Condition.....................................
2.3.2 Ongoing Work...................................................
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2.3.2.1 Ongoing Electrical Maintenance.................................
2.3.2.2 Ongoing Mechanical Maintenance................................
2.3.2.3 Ongoing Instrument-and Control Maintenance....................
2.3.2.4 Ongoing Fire Protection Activities............................ 13 l
2.3.3 Radiological Controls.........................................
.j 2.3.4 Maintenance Facilities, Material Control, and Control l
of Tools and Measuring Equipment..............................
'2.3.4.1 Maintenance Facilities........................................
i 2. 3. 4. 2 Ma te r i a l C o n tro 1.............................................. 16 2.3.4.3 Control and Calibration of Measuring and Test Equipment....... 17
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2.4-Review and Evaluation of Maintenance Accomplished............. 18 2.4.1 Backlog Assessment.and Evaluation.............................
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2;4.1.1 Corrective Maintenance Back1og................................ 18
.l 2.4.1.2 Preventive Maintenance Backlog................................
1 2.4.2 Review and Evaluation of Completed Maintenance................ 19 l
.2.4.2.1 Fast Electrical Maintenance................................... 20 2.4.2.2 Past Mechanical Maintenance................................... 21 2.4.2.3 Past Instrumentation'and Control Maintenance.................. 22.
2.5 Fire. Protection Controls...................................... 24 2.6-Ma i ntenance Wor k Contro1...................................... 25 2.7 Engineering and Technical Support.............................
2.7.1'
Sy s t em E n g i n e e r i n g............................................ 2 6 2.8 Maintenance ~and Support Personnel Control.....................
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2.9 Review of Licensee's Assessment-of Maintenance................ 28
i 2.9.1 Audit and Surveillance Reports................................
2.9.2 Review of Maintenance Self Assessment.........................
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2.9.3 Documentation of Nonconformances..............................
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2.9.4-Effectiveness of Corrective Action............................
~3.0 Sy n o p s i s...................................................... 3 0 3.1 Overall Plant Performance..................................... 30 3.1.1 H i s to r i c D a t a................................................. 3 0 3.1.2 P l a n t W a l kd ow n s............................................... 31 3.2 Management Support of Maintenance............................. 31
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3.2.1-Management Commitment and Involvement.........................
3.2.2 Management Organization and Administration.................... 31 3.2.3 Technical Support.............................................
i 3,3 Implementation of Maintenance.................................
3.3.1-Work Contro1..................................................
3.3.2 Plant Maintenance Organization................................ 32 i
3.3.3 Maintenance Facilities, Equipment and Material Control........ 32 3.3.4 Personnel Contro1............................................. 32 4.0.
E x i t Me e t i n g.................................................. 3 3 Appendix A: A c r o ny m s................................................. 3 4
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DETAILS
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i 1 ~. 0 Principal Persons Contacted Northern States Power Company (NSP)
- L. Eliason, General Manager, Nuclear Plants
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- K. Beadell, Superintendent of Technical Engineering
- W. Gauger..I&C Supervisor L
- M, Klee, Superintendent of Quality Engineering
- G. Lenertz, General Superintendent, Plant Maintenance h
- D. Mendele, General Superintendent of Engineering and Radiation Protection
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- G. Miller, Superintendent of Operations Engineering
- M. Sellman, General Superintendent of Plant Operations g
- A. Smith, General Superintendent of Planning
- E. Watzl, Plant Manager U. S. Nuclear Regulatory Commission (U.S. NRC)
- H. Miller, Director, Division of Reactor Safety
- S. Burgess, Team' Leader, Maintenance and Outages Section
- F. Jablonski, Chief, Maintenance and Outages Section
- T. O'Connor, Residen.t Inspector
- Denotes those present at the exit meeting on February 23, 1990.
2.0 Introduction to the Evaluation and Assessment of Maintenance
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~ An announced NRC combined team inspection of maintenance and fire protection was conducted at Prairie Island Nuclear Generating Plant during the period of
January,8 through 12, and January 29-through February 23, 1990, while Unit I was in a refueling outage and Unit 2 was in operation.
The inspection was conducted to address fundamental issues in the broad areas of maintenance, fire protection, engineering, and technical support where the team looked at plant performance, management support, and implementation. The team goal was to determine if maintenance and fire protection programs had been implemented-to assure the safe operation and reliability of plant structures, systems, and components to operate on demand. This inspection was based on the guidance
provided in NRC Temporary Instruction 425767-C, " Maintenance Inspection", and Drawing 425767-C' " Maintenance Inspection Tree." The drawing, which is
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attached to this report, was used as a visual aid during the exit meeting to depict the results of the inspection. Acronyms used in this report are defined in Apper41x A.
Results of this inspection were derived from data obtained by observation of current plant conditions and work in progress, by review of completed work, and by evaluation of the licensee's attempt at self assessment of maintenance and correction of weaknesses. Major areas of interest included electrical, mechanical, instrument and control and the support areas of radiological control, engineering, fire protection, quality control, training, procurement, i
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- and operations. Problems identified by the inspectors were evaluated for effect on Technical Specif! cation operability and technical or managerial weakness.
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2.1 performance Data and System Selection 2,1.1 Historic Data
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The inspectors considered the latest Systematic Assessment of Licensee Performance (SALP) report and completed NRC inspection reports.
Primarily, the inspectors were sensitive to technical and managerial problems that appeared to be maintenance related. Results of this review did not indicate any pervasive problems or weaknesses that existed in the maintenance process.
The inspectors also reviewed plant operations historic data since January 1989, including Licensee Event Reports (LERs).
The three year equivalent availability goal of 75% was accomplished for both units with Unit I at 87%,
and Unit-2 at 85.3%.
The forced outage rate for Unit I was 0.3%, Unit 2 was
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2.5%; the plant goal was 1.4%.
The goal to not exceed one automatic reactor trip was met for Unit 1; however, was exceeded for Unit 2 with three (two occurred in December 1989). None of the trips was caused by maintenance
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personnel nor to ineffective or lack of maintenance.
Safety system
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availability goals for safety injection system (SIS), auxiliary feedwater system (AFW) and emergency diesel generators (EDG) appeared reasonable and I
achievable and were well within the plant goals.
There were zero unplanned safety system actuations for 1988 and 1989.
Prairie Island's 1989 collective radiation exposure, which included a one unit outage, was approximately 93 man-rem. The plant goal was 100 man-rem per unit.
The dose for 1989 was considerably below the industry average of 732 man-rem for a two unit site.
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2.1,2 System Selection The systems and components selected for this inspection were based on a review of data from the Nuclear Plant Reliability Data System (NPRDS) and the
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Probabilistic Risk Assessment (PRA) study furnished to the team by the
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Reliability Applications Section of the Office of Nuclear Reactor Regulation.
As described throughout this report, emphasis was placed on inspection of specific electrical, mechanical, and instrumentation components of the ac/dc power, Component Cooling Water (CCW), and Safety Injection (SI) systems.
Components from several other systems were also inspected.
2.2 Description of Maintenance Philosophy The inspectors reviewed site policy statements, administrative procedures, organization charts, established goals, and documents that described improvement programs for the maintenance process.
The licensee had a documented comprehensive maintenance plan that included milestones and completion dates for improvement programs and goals. Discussions by the inspectors with selected managers indicated that those personnel were knowledgeable and aware of established performance goals.
l The inspectors determined that the licensee's maintenance program was balanced between corrective maintenance (CM) and preventive maintenance (pM).
The licensee appeared to adequately address PM requirements for equipment.
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j Maintenance' history and vendor recommendations were used as a source of this 1' formation; however,'because there was no formal trending program, maintenance c
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n history consisted of system engineer memory or a manual computer search.
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- inspectors verified that vendor recommendations were included in the PM program or deviations were-technically justified.
k In the area of predictive maintenance the licensee's maintenance program was
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not at a level commensurate with the rest of the industry. The inspectors reviewed the status of licensee-programs that monitored component performance.
Four programs were identified:
(1) motor-operated valves (MOVs), (2) check i
valves, ~(3). vibration monitoring (exclusive of IST), and (4) ferrography.
Only o-the MOV program was considered to be effective. The others were not at a sufficient stage of development to be of value. The licensee had not established a definite goal for having these programs fully implemented.
The licensee's philosophy of maintenance included some aspects of the principles of Reliability Centered Maintenance (RCM).
The inspectors determined that the i
maintenance philosophy, in all disciplines, included some concepts of RCM.
2.3 Observations of Current plant Conditions & Ongoing Work i
2.3.1 Current Material Condition
The inspectors performed general plant as well as selected system and component walkdowns to assess housekeeping, the general and specific material condition of the plant, and to verify that work requests (WRs) had been initiated for
identified equipment problems. The selected systems and components are
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identified in Section 2.1.2 of this report.
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Walkdowns included an assessment of the buildings, components ems
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for proper identification and tagging, accessibility, fire en, y door
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integrity, scaffolding, radiological controls, and any unusual w. dons.
Unusual conditions-included but were not limited to water, oil or other liquids on the floor or equipment; indications of leakage through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting.
Since Unit I was in a refueling outage and
Unit 2 was operating at the time of the inspection, the inspectors could fully
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assess the material operating condition and outage conditions of systems and components.
Results fol aw:
i Cognizant plant management personnel were assigned responsibilities for specific areas and were required to perform periodic walkdowns of those
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assigned areas. The worksheets used for guidance were detailed and i
provided followup that corrected any adverse conditions noted.
The inspectors concluded that management walkdowns included work in progress.
- The inspectors noted an absence of steam or water leaks along with an absence of industrial sealant to seal steam leaks.
No water was observed on the floor from sample, blowdown or drain lines.
Funnels were added to sampling lines and any leak off was directed away from pathways to the room drains with tubing.
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During the first week of the inspection, Unit I was coasting down for a refueling outage while Unit 2 was returning to service.- During the second week, Unit I was in a refueling outage and Unit 2 was in power operation, The inspectors did not observe any indication that plant-maneuvering or steady state operation induced a strain on equipment such
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as vibration of piping, movement of hangers, or weeping of relief valves.
- The Unit I containment was congested with work; however, the work was very controlled.
Supervision and health physics personnel were observed in the containment throughout the outage.
Tools and hoses were neatly stored on racks.
.In the Unit I auxiiiary building, the inspectors noted extension ladders to. reach overhead valves, which were not secured in place to prevent personnel accidents during use. These were identified to the licensee and secured. A grinding wheel, located next to the tool crib on elevation 695, was not equipped to prevent the spread of airborne contamination if contaminated tools were used on the grinder. The inspectors also questioned the need for a clean grinder in the auxiliary building since the auxi'liary building could become contaminated. The inspectors determined that personnel knew the grinder was for clean use only. The licensee posted a sign that indicated the grinder was for clean use only.
- During walkdowns of the Unit I safeguards bus 16 room, cable spreading / relay room, D3 non-safeguards DG area, D2 EDG room, 121 battery room, and the 121 invertcr room, the inspectors noted small amounts of miscellaneous waste debris such as disposable coveralls, combustible plastic materials, and oil soaked absorbant materials. Also, items such as wooden carts, paper material and a chair appeared to be left over from previous maintenance work.
In all instances, the items were left
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unattended while work activities were not in progress. These examples individually were considered of minor safety significance; however, cumulatively, showed a breakdown in the control of combustibles.
Procedure SACD 3.13, " Housekeeping", Revision 3, required that all waste, debris, scrap, spills or other combustibles that resulted from work
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activities be cleaned up or disposed of in proper containers and removed from the area immediately following the completion of the work activity.
The failure to follow housekeeping procedures that could result in an unacceptable fire protection condition is an example of a violation of 10 CFR 50, Appendix B, Criterion V (282/89029-01A; 306/89029-01A).
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The licensee took prompt corrective action in cleaning the areas-identified and informed the inspectors that the Fire Protection and Industrial Safety Administrator would remind personnel during the next series of safety meetings that materials such as those described above need.to be removed in accordance.with plant procedures.
During walkdowns of the Unit 2 battery rooms, the inspectors noted that in battery-room 22, and to a lesser extent in battery room 21, a high rate of air flow was passing by the area fire detectors (one per room).
It appeared that this could delay or prevent the fire detectors from sensing
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i the products of combustion from a fire / smoke condition.
The fire-protection system engineer evaluated the condition and initiated WR
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P0296-ZT to readjust the louvers of the room ventilation systems so that the air flow was away from the room fire detectors.
- The inspectors noted that covers were removed from the 4.16 kV bus connecting the IM transformer to Bus 11 and 12 switchgear. The
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inspectors were told that corrosion of the bus near the 1M transformer had resulted in failure of the upper bus flexible strap connections from-the building bus to the transformer bus.
This resulted in severe overloading and overheating of the lower bus bars.
Bus sections near 11 and 12 switchgear were made of aluminum and the copper to aluminum connections also appeared to be contributors to the overheating and corrosion of the bus. The copper bus immediate to the transformer was also severely corroded.
This problem was attributed to pigeon droppings combined with water leakage onto the bus through the bus cover.
The licensee decided _to replace the entire bus work from the trantformer through Bus 11 and 12. WRs N8221, N8224, P0891-EA, P0907-EA, and p1082-EA-Q were written on the problem; however, no nonconforming item reports were written.
.Since there was a requirement to tag components that reeded maintenance, the inspectors selected 20 tags from equipment in the plant and evaluated-the effectiveness of the licensee's deficiency tag program. None of the tags appeared to be excessively old. Open WRs existed for all tags selected and three instances were identified where minor deficiencies existed and no WRs were written. The licensee's program for the identification of required maintenance appeared to be effectively implemented.
Generally, equipment problems identified by the inspectors during plant and system walkdowns had already been identified by the licensee's WR program.
The material condition of the plant was considered good to maintain the operability of components at a level commensurate with-the components' function.
2.3.2 Ongoing Work
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The inspectors observed ongoing work in electrical,.I&C, and mechanical maintenance areas. The inspectors selected these activities from the plan of the day listings, work assignments in individual maintenance shops and
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through discussions with individual foremen. Where possible, safety significant activities were chosen for follow-up.
Maintenance activities were witnessed / observed to determine if those activities were performed in accordance with required administrative and technical
requirements. -Work activities were assessed in the following areas:
l work control and planning; management presence, involvement, and knowledge;-
s Quality Control (QC) presence and involvement; health physics (HP) support and hazards; procedures available, adequate, and used; personnel trained and qualified; materials available, adequate, and used; measuring & test equipment (M&TE) and tools proper, calibrated, and used; and post maintenance testing (PMT) acceptance criteria performed as specified.
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2,.3.2.1 Ongoing Electrical Maintenance
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zThe inspectors observed portions of six electrical maintenance activities as discussed below:
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EP17-17-18 Trip check of 4.16 kV bus
EP17-41 PM for 480 volt breaker #H61521A-1-
-EP17-42 PM for 480 volt breaker #H61521E6
N9147-CC-Q -PM 3119-1-11 on #11 CCW pump SP 1708 Emergency Lighting 18 Month 8 Hour Test
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SWR 105 Repair of 345 KV switchyard breaker #8H13 The inspectors concluded that electrical maintenance activities in the pertinent areas described in Section 2.3.2 were adequate and accomplished by skilled maintenance personnel.
The maintenance personnel appeared to be knowledgeable
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and adequately trained in the work performed, however, concerns were identified with inadequate corrective action on emergency lighting failures,
_ failure to report non-safety related equipment nonconformances, and the lack of QC involvement on breaker and relay work.
SP 1708 - eight hour discharge test of emergency lighting unit #63. On January 10, 1990, this lighting unit went conipletely out within three hours into the test.
The unit was required to operate'for eight hours before being considered satisfactory. The battery for this lighting unit was replaced and retested successfully on January 11, 1990.
Electrical maintenance work history for emergency lighting unit #63 showed that since March 1988, demineralized water was added to the battery ten times because low electrolyte level caused low voltage.
The inspector reviewed SP 1205, " Emergency Lighting Quar'terly and Semi-Annual Tests", Revision-4. The quarterly surveillance included a visual check of the electrolyte level..The semi-annual surveillance included both a visual check of the battery's state of charge (voltage reading),
electrolyte level and a 90 second operational test that simulated a power failure. The emergency lighting unit vendor recommended surveillances
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that detailed specific information for excessive battery water usage.
Vendor information also indicated that it was necessary to report to
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supervision this unit condition if the previous month's test record indicated water was added within a 60 day per_iod.
The vendor suggested that excessive water use indicated that the lighting unit was in too warm an area and the battery could be relocated to solve the problem. The licensee decided to increase the unit's quarterly surveillance to a monthly surveillance. A work history of all eight hour lighting units for post safe shutdown was initiated.
In instances of excessive maintenance activities, the licensee will add the unit to the increased surveillance schedule.
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I Based on the inspector's review of the maintenance work history for unit
- 63, it was concluded that the licensee failed to properly determine the root cause for repetitive electrolyte level deficiencies to prevent-further recurrence.
The failure to take adequate corrective action is an example of a-violation of 10 CFR 50, Appendix B, Criterion XVI t
(282/89029-02A;306/89029-02A).
In observing work in nonsafety-related areas, the inspectors noted that Nonconforming Item Reports (NIR) were not written on significant nonsafety-related equipment failures, which is discussed in detail-in Section 2.9.3.3 of this report.
- In reviewing electrical breaker PMs, the inspectors noted that one WR was written for each electrical bus and all breakers associated with that bus were worked under this WR.
However, individual procedures were completed c
for each breaker. -This practice would seem to affect the ability to use the computer system to accurately reflect work history of individual breakers.
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The inspectors noted that neither QC involvement nor the requirement for QC involvement was included in the procedures or the work packages. Most of the work witnessed by the inspectors was breaker and relay work performed by the Northern States Power relay or systems group who did not report directly to plant personnel.
There was no evidence of QC coverage on this type work.
2.3.2.2 Ongoing Mechanical Maintenance The inspectors observed portions of ten mechanical maintenance activities as discussed below:
WR M2978-CC-Q PM on #12 CCW heat exchanger WR M2982-CC-Q Clean #12 CCW heat exchanger tubes WR N6003-CC-Q Eddy current inspection of #12 CCW heat exchanger WR N7109-MS-Q PM-3170-1-12 on Main Steam Isolation Valve, CV-31099 l
WR N7133-MS-Q Weld disc nut to disc on #12 Steam Generator reverse flow check valve, RS-19-2 WR N8171-SI-Q Install larger orifices in #12 SI miniflow line WR N8555-AF-Q PM on #12 Motor Driven Auxiliary Feedwater Pump WR P0072-SI-Q Repack SI valve, MV-32067 WR P0093-SI-Q PM on #11 SI Pump WR P8825-SI-Q Prefab inlet flanges for reliefs and test reliefs
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- The inspectors. concluded that the mechanical activities in the pertinent areas
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described in Section 2.3.2 were adequate and accomplished by skilled maintenance personnel. Maintenance personnel appeared to be knowledgeable and adequately trained in the work performed.
However, concerns were identified with potential modifications performed without the proper modification process and " pen and ink" changes made to WRs.
WR N7133-MS-Q - The cover sheet indicated that the changes resulting from completion of the WR were not a modification, but in fact, modification package 90A0138, "S and K Swing Check Valves Upgrade" was completed on
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January 30, 1990.
Since seal welding of the disc nut to the disc had not yet started, the engineer agreed to revise the WR to reflect the modification number. The inspectors were concerned with the practice of making potential modifications without using the proper modification process, which is discussed further in Section 2.9.4.
The associated weld control record listed a disc nut material
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specification of A194 Grade 7 with a " pen and ink" change from grade 7 to grade 4.
The licensee provided documentation that such a change would not affect the weld.
- WR N7109-MS-Q - The inspectors reviewed the control copy of the WR and-noted a number of " pen and ink" changes, which were permitted-by plant adminstrative procedure. The " pen and ink" changes resulted in loose control, confusion, or missed instructions.
For example, step 6.3.17 specified a stuffing box nut torque of 400 pound feet, but because a torque wrench could not fit into the work space, a " pen and ink" change was made to estimate the torque and verify proper gasket crush by feeler gauge. However, no acceptance criteria were given to determine proper
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The working copy of the WR at the job site had " pen and ink" changes made to step 6.3.13,a, which required seal welding of the disc nut to the
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disc. The system engineer indicated that securing the nut in place by a seal weld was a vendor recommendation; however, because of the inspection frequency for the main steam isolation check valves, the licensee deleted the step.
The system engineer showed the inspectors that on the previous day, the controlled copy of the WR had deleted step 6.3.13.a, the weld-procedure, and the weld cards. The system engineer revised the working copy:with another " pen and ink" change to conform with the control copy.
Again the inspectors were concerned with the practice of making potential modifications without using the proper modification process, which is discussed further in Section 2.9.4.
WR M2978-CC-Q - Installation of a return channel drain plug, was required; however, this was deleted by a " pen and ink" change and instructions added to close the drain valves added per WR N5979.
The inspectors were unable to find the drain valves, The system engineer stated that the drain valves were not installed because parts were unavailable. The system engineer deleted the requirement by another " pen and ink" change and reinstated the previous requirement to install the drain plug.
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The inspectors concluded that " pen and ink changes" made to the above WRs, F
minimized licensee planning and prevented delays to the work activity without implementing a formal review as required in Technical Specification 6.5.G.
1Since WR N7109-MS-Q implemented procedure PM-3170-1-12, changes were required
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-to be reviewed by the Operation Committee (OC) per Technical Specification-6.5.G.
However, " pen and ink" changes to the procedure were not reviewed by
the 0C. The OC had delegated this review to a one person subcommittee, the.
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Work Request Authorization Coordinator (WRAC). The inspectors agreed with the-0C authorization to charter _a subcommittee to perform' reviews but didn't, agree the OC could delete the_ multi-discipline review provided by the Committee.
Failure of the OC to review changes to procedure PM-3170-1-12 as required by Technical Specification 6.5.G.3 is a violation of Technical Specification 6.5 (282/89029-03A; 306/89029-03A).
2.3.2.3 Ongoing Instrument and Control Maintenance The inspectors observed portions of four I&C maintenance activities as discussed j
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q WR N7835-MS Steam Dump Valves Calibration WR N7839-TG Turbine System Instrument Calibration i
WR N8466-CL Refurbish Foxboro Instrument Loops for CL System
SP 2035A Reactor Protection Logic Test at Power j
The inspectors concluded tnat I&C maintenance activities in the pertinent I
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areas described in. Section 2.3.2 were adequate and accomplished by skilled maintenance personnel. The maintenance personnel appeared knowledgeable and well trained for the work performed.
However, concerns with overly brief and sometimes inaccurate B0P procedures were. identified during the observation of
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the work.
WR N7835-MS - I&C-personnel performed positioner checks on steam dump-g valves 31085 and 31086 in reference to I&C procedure PM 1-340, " Steam
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-Dump Valves Calibration," Revision 4.
The calibration table indicated that the valves ~should be' opened 1.6 inches.at-15 psi with a tolerance of 0.2 inches. With'15 psi applied, valve 31085 would open only 1.3
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inches. There was no functional adjustment specified or available to the I&C' technicians to correct the discrepancy., _ Maintenance work history
records for this valve showed that similar problems were encountered
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during previous maintenance activities but the reduced valve travel had i
not been considered unacceptable.
An engineering evaluation was requested and determined the as found" results were unacceptable. A WR was written
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to make the necessary adjustments to the valve stem.
WR N7839-TG'- I&C personnel performed calibration and functional checks
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on temperature sensors and pressure controllers associated with the main I
steam turbine in reference to I&C'PM procedure 348-B, " Turbine System Instrument Calibration," Revision 3.
The procedure provided no specific instructions; therefore, work accomplished relied on good training and
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ingenuity of the technicians.
For example, the instruments to be calibrated or tested were only identified by number. The I&C technicians identified and located the instruments from past experience or referred to the master i
equipment list or the instrument calibration cards.
The procedure also
provided no information to correlate wire numbers to specific temperature
sensors even though, in the plant, the sensor wires were identified only by wire number. The I&C technicians traced conduits and opened the thermo-wells at the sensor head and identified the wires that served the specific temperature sensor.
The setpoint tolerance for the instruments was stated as 2% but did not indicate whether the temperature sensor tolerances were based on temperature or resistance. The technicians concluded that the tolerances were based on temperature and needed to'be translated into resistance
units. The technicians made the necessary interpolative calculations and
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verified that the. instruments were within the specified limits. The
inspectors concluded that calibrations of this magnitude should not be required of the I&C technicians.
Some numeric errors in the procedures were identified by the I&C
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technicians.
In one case, the I&C technicians knew that the control point listed on the worksheet for the generator hydrogen supply pressure switch-
- 16094 was in error because it conflicted with the calibration card for-this instrument. The I&C technicians stated that the information on the i
calibration cards was accepted in preference to the worksheets as a matter of standard practice.
However, when testing Gland Steam supply pressure controller, #26001, the wrong-test equipment was brought to the job because the technicians followed an incorrect calibration card instead of j
the correct procedure.
Outdated procedures and calibration cards contributed to the use of inaccurate information.
The problems associated with the overly brief and sometimes inaccurate procedures were observed in some PM procedures for nonsafety-related instrumentation. The problems were overcome by the outstanding I&C technicians-who were experienced and well trained for the work. There were no incidents observed in.which the-functional checks or calibrations were compromised by the inadequate procedures.
Maintenance work on safety-related instruments, by comparison, was observed to be conducted under mere rigid and precise procedures.
2.3.2.4 Ongoing Fire Protection Activities The inspectors observed portions of six fire protection surveillances as discussed below:
SP 1183 Annual Fire Extinguisher and Hose Station Inspection, Revision 9 SP 1189 Safety-Related Fire Detector Surveillance, Revision '
i SP 1203 Fire Hose Hydrostatic Surveillance, Revision 4 SP 1205 Emergency Lighting Quarterly and Semi-Annual Test, Revision 4 SP 1524 122 Diesel Fire Pump Weekly Test, Revision 11 i
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The Fire Protection and Industrial Safety Administrator's staff appeared to be knowledgeable and adequately trained in the work performed.
However, concerns
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with finding detectors in congested areas, obstruction of fire detectors, lack
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of acceptance criteria for the fire detector test results, and fire brigade timeliness and training were noted.
- SP 1189 - This surveillance tested the fire detector circuitry and
verified receipt of the annunciated fire detector in the control room. The l
following observations were made by the inspector: (1) Fire detectors were observed in certain plant ceiling areas which were congested.- The licensee marked ths floor with a red circle to easily locate individual fire detectors.
However, areas in the cable spreading / relay room needed l
further enhancement.s to mark fire detector areas, which the licensee
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acknowledged as necessary.
(2) Four detector locations, 28-14, 30-11, 50-3, and 50-4 were not marked on the floor below the area of the fire detectors.
Personnel who conducted the surveillance reported the discrepancies and corrective action was planned. (3) Fire detector 53-13 was obstructed by a unistrut assembly believed to be installed subsequent i
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to the installation of the fire detector.
Performance of the surveillance test was difficult. The licensee initiated a WR to move the fire detector for unobstructed access to the detector.
The inspectors requested the
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licensee to verify that no other fire detector locations existed with similar problems, (4) The inspector noted that surveillance procedure SP 1189 did not contain appropriate acceptance criteria specified by the
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vender for performing ionization and flame detector tests.
Subsequently,
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the licensee revised SP 1189 and incorporated acceptance criteria for i
testing ionization and flame detectors.
Lack of appropriate acceptance criteria for determining that important activities have been satisfactorily accomplished is considered an example of a violation of 10 CFR 50, Appendix B, Criterion V (282/89029-01B; 306/89029-01B).
SP 1183 - The inspectors observed that the licensee did not mark the fire I
hose being tested for coupling slippage.
National Fire Protection Association Standard (NFPA) No. 1962, 1979 Edition, Section 8-4.2.6, i
specified that after filling the hose, each coupling shall be marked at i
each end at the back of the couplings to determine whether the coupling slips during the test.
The Fire Protection and Industrial Safety
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Administrator indicated that this surveillance test procedure was scheduled for revision and the NFPA specification would be considered.
The inspectors-also witnessed an unannounced fire drill to determine whether fire brigade personnel were properly trained and ready for fire suppression activities, and if adequate fire fighting equipment was available.
The drill simulated a fire / smoke condition that occurred due to a tipped over
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55 gallon barrel of oil assumed to be contaminated.
The inspector observed the actions of control room operators upon the receipt of the activated fire detector. The licensee conducted the unannounced fire brigade drill while the inspector observed the firefighting actions taken by shift personnel during the postulated fire incident, observed the interface between the fire brigade
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leader and the radiation protection personnel, and determined overall e'ffectiveness during fire emergency situations involving potential radiation hazards.
The inspectors. evaluated the following fire brigade and support personnel actions: (1) fire brigade members' conformance with established plant firefighting procedures; (2) the fire brigade leader's direction of the firefighting efforts; (3) donning and simulated use of self contained breathing apparatus (SCBA); (4) donning of protective clothing; (5) simulated use of fire hose stations; (6) use of portable radio communication equipment; (7) brigade timeliness in response and numbers of personnel responding with proper
- firefighting equipment, and (8) brigade leader interaction with Radiation
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Control Technicians (RCT) and other support personnel such as security.
The inspector concluded that the fire drill was satisfactorily performed.
The inspector noted that: fire brigade and radiation control technician staffing 'and equipment.were adequate, and open, beneficial communication took place during the post-fire drill critique. However, the fire brigade response was not timely from the assembly area to 'the alarmed area, and training appeared weak l
in fire tactics for the best approach to attack a fire..During the post-fire l
critique, the Fire Protection and Industrial Safety Administrator agreed that
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these areas needed improvement.
j 2.3.3 Radiological Controls j
i Maintenance work was observed in contaminated and radiation areas as were l
movements of tools and equipment to and from these areas; interactions of I
workers with radiological protection personnel were also observed.
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Radiological controls, posting and labeling were good.
From a radiological I
standpoint, cleanliness and housekeeping were very good for the extensive outage conditions.
Radiation protection job coverage and As Low As is Reasonably Achievable (ALARA) support was good.
Through,the observation of work in progress and discussions with licensee l
. personnel, the inspector determined that~ radiological controls were integrated l
into the maintenance, process.
l The ALARA staff implemented effective ALARA oversight of maintenance activities.
Communications and working relationships between radiation protection and i
maintenance were good.
In most cases, there appeared to be sufficient lead time
to perform ALARA reviews.
RWP issuance, RWP job coverage, and use of dosimetry appeared to be good and well monitored.
An experienced radiation protection person attended planning meetings, reviewed modification work packages, reviewed maintenance work packages that involved
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dose producing jobs, determined shielding requirements, conducted pre and post i
job-surveys, and wrote RWPs.
Proposed facility changes are reviewed by the l
Radiation Protection Supervisor or the Health Physicist.
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QA audits of the radiation program, including ALARA program, were performed and any findings were addressed.
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The inspectors noted a minor weakness in RWP dose control:
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NRC inspectors entered on " inspection only". general RWP No.1001, without a high-range (1000 mR) self reading dosimeter (SRD) because of inaccurate
information from the radiation specialist at the access control desk.
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The inspectors did not go into any high radiation areas where a high range SRD was needed. Discussions with radiation protection personnel at the access control desk determined that high range SRDs were always required when entering:on RWP No. 1001 and the direction given'the NRC inspectors-was incorrect. The RWP dose control weakness was corrected by the licensee the same day.
2.3.4 Maintenance Facilities, Material Control and Control of Tools and.
j Measuring Equipment l
l 2.3.4.1 Maintenance Facilities
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The electrical maintenance workshop area was located in the service building and appeared to be somewhat small for the 11 electricians. The licensee planned to expand the electrical shop into an unused part of the mechanical workshop located adjacent to the electrical workshop. The electrical maintenance supervisor's office and tool room were located near the shop area.
The mechanical maintenance workshop area was located in the service building next to the electrical shop and had an adequate work bench area for the 40 mechanics with sufficient equipment that supported mechanical maintenance activities. The mechanical shop area contained a weld shop and a tool room.
Mechanical maintenance supervision was located adjacent to the shop area.
The I&C maintenance workshop area was located in the auxiliary building next to
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the control room and was considered too small for the 17 I&C technicians.
The
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-licensee planned to move the I&C shop to the fifth floor of the present l
administration building in the spring of this year.
Supervision was near the
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shop area.
Several maintenance facilities such as a hot decontamination shop, a clean area: tool crib, a shop for welding, and an I&C hot shop were located in the auxiliary building.
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A trairiing room for mechanics and electricians was located adjacent to the
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mechanical shop with several mock-ups of plant equipment available for training maintenance personnel.
Examples included electrical circuit breakers, steam
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generators, MOV operators, and reactor coolant pump seals.
2.3.4.2 Material Control The inspectors reviewed the methods used by maintenance and supporting organizations to control replacement parts and materials.
This review included-the review of replacement parts and materials used during observed maintenance activities as well as a review of the parts storage methods and areas.
In addition, the inspectors made observations in the warehouses and material storage areas. Warehouses were clean and well kept with controlled access.
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Parts and materials were stored neatly and, in most cases, were properly identified with the part number as well as the purchase order number. A large quantity of unidentified cleaning and insulating material was stored in two separate areas in warehouse number one for use in the main generator repair scheduled for the current Unit 1 outage.
Safety-related and nonsafety-related materials were stored in the same warehouse area but were positively identified and were not intermixed in the same bin.
Except for the main 5,enerator material previously noted, replacement parts and material appeared to be properly identified.
The inspector noted that, in some cases, the ends of electrical cable stored in reels in the warehouse were not taped or covered.
This did not seem to be a problem since the cable was stored inside. Limited life materials were stored throughout the warehouses with appropriate identification and limited life expiration dates.
No limited life material was noted that had exceeded the specified expiration date.
Control of materials in the fabrication shops was also reviewed and appeared to be acceptable.
Locked
" hold" areas were provided for nonconforming items and material.
A computerized system existed for parts inventory and location.
This system appeared to be functioning well; however, the inspector was told that a system
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for automatic reordering of stocked parts did not exist.
Although this did not appear to be a serious problem at this time, difficulty in maintaining an adequate inventory of replacement parts could later result.
Maintenance work on hold for parts did not appear to be excessive, but a system did not exist to track and control parts on order.
In some cases,-when parts were needed to complete scheduled work, parts were ordered and the WRs were closed.
The cognizant system engineer ordered the parts and initiated a WR to get the equipment repaired when the parts were received.
This practice had an effect on backlogged WRs wnich is discussed in Section 2.4.1.1.
Control of replacement parts and materials appeared.to be acceptable.
Except for the minor items described above, no other weaknesses or concerns were noted in this area.
2.3.4.3 Control and Calibration of Measuring and Test Equipment (M&TE)
Control of M&TE was satisfactory.
Defective or "t.alibration due" instruments were segregated from those in calibration and acceptable-for use.
Procedures were also developed and implemented for the issue, return, and recall of M&TE.
Issuance of M&TE was satisfactory. Technicians verified that test instrument calibrations were not past due and were trained on the proper use of the instruments.
Each calibration and test instrument was identified by a unique identifier.
The instrument files contained a record of the calibration dates, a record of the calibration process, traceability to national standards, and the individuals, organizations and companies who performed the calibration.
No calibration or test instruments available for use were found that were past due for calibration.
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The inspector. checked the calibration and/or traceability of EDC de voltage calibration standard 0-13; Fluke de voltage calibration standard 0-02; Fluke. digital voltmeters.3-9, 3-10, and 3-34; and Ronan calibrator 8-06.
The non portable Fluke de voltage standard did not have a calibration tag on the instrument, but the instrument was determined to be in calibration based on records and certificates in the instrument file.
No other problems were identified.
2.4 Review and Evaluation of Maintenance Accomplished 2.4.1 Backlog Assessment and Evaluation The inspectors reviewed the amount of work accomplished compared to the amount
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of work scheduled.
Emphasis was placed on work that could affect the operability of safety-related equipment or equipment important to safety, which included some 80P components. Maintenance work item backlogs were
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evaluated for cause and impact on safety.
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The backlog was divided between WRs issued to maintenance and those that were held by the cognizant system engineers for planning of the work. Although the actual number of WRs in the backlog could be determined, there was no method available to determine if backlogs could be completed within a reasonable -
period of time. The number of WRs completed each week or: month was not tracked and neither was the average man-hours required to complete a WR.
There was no method in place to track or control required maintenance on hold for parts, as discussed in Section 2.3.4.2.
The inspectors could not ascertain the exact number of such requests; however, such items appeared to be relatively low.
The inspectors determined that since the priority system was well controlled, k
the unconventional parts control method did not impact the safety of the plant.
~ The backlog,- consisting of cms, PMs, and WRs processed by system engineers, averaged 560 at the end of each month.
No adverse trends or unexpected fluctuations in the monthly totals were observed.
2.4.1.1 Corrective Maintenance Backlog The backlog of both outage and non-outage cms was maintained on a computer data base. Backlog information could be ascertained from the system; however,
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the time required for this eff,rt was sometimes lengthy.
Backlog status reports were issued monthly to management. The current as well as previous backlog totals were included in these reports so that increasing or
' decreasing trends could be readily determined. The backlog of non-outage cms averaged approximately 100 at the end of each month. The total backlog represented approximately two weeks of work, No adverse trends or unexplained fluctuations were observed.
The most important WRs were worked-immediately as planned.
The inspectors selected several open WRs and determined that the work had been properly prioritized and did not impact the safety of the plant.
The inspectors concluded that the licensee provided adequate resources ~ for satisfactory control of the.CM backlog.
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- 2.4'.1.2
- Preventive Maintenance Backlog h
The PM backlog'was also maintained on a computer database.
Similarly, it was
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difficult to determine what PMs were overdue.
This problem was. identified by the licensee in' Nonconforming Activity Report A272, dated September 12, 1989, which was still open at the time of this inspection. The licensee supplied
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- the inspectors with a current status of overdue PMs as well as the PM backlog history. As of December 13, 1989, three I&C PMs were past'due.
No electrical or mechanical PMs'were past due.
Incompletion of the past-due maintenance did
- not affect the operability'of safety related systems. The backlog of.
non-outage PMs averaged approximately 140 at the end of each month.
No adverse trends or unexplained fluctuations were observed.
The inspectors
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- concluded that the licensee used adequate resources to complete PMs as scheduled or provided a technical basis for deferral.
2.4.2 Review and Evaluation of Completed Maintenance
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The inspectors selected the equipment and systems identified in Section 2.1.2-of this report for further review. The purpose of this review was to determine if specified electrical, mechanical, and.I&C maintenance on those selected
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systems / components was accomplished as required. This review included:
Application of risk-based priority to the performance and intent of maintenance.
Evaluation of the extent that RCM was factored into the established
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mnintenance process.
Evaluation of the extent that vendor manual recommendations, IE Bulletins, (IEB), IE Notices (IEN), Service Information Letter (SIls), Significant
Operating Experience Record (SOERs), and other outside source information was utilized.
Evaluation of the extent that maintenance histories, NPROS information,.
LERs,. negative trends, rework, extended time for outage, frequency of maintenance, and results of diagnostic examinations were analyzed-for trends and root causes for modification of the PM process to preclude recurrence of equipment or component failures.
Evaluation of completed CM and PM for use of qualified personnel, proper f
prioritization, Quality Control (QC) involvement, quality of documentation for machinery history, description of problems and resolutions, and post
maintenance testing.
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Evaluation of work procedures for inclusion of QC hold points, acceptance
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criteria, ease of use, and general conformance to NUREG/CR-1369.
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Past Electrical Maintenance
.The inspectors reviewed twelve completed WRs for the attributes included in Section 2.4.2.-
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WR N0119-DC-Q Clear ground on #11 battery
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WR NO351-CC-Q Disassemble and clean #12 CCW pump WR NO399-EB-Q Repair of 480 volt breaker #H61521B-4 r
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WR N0483-EB-Q Repair 480 volt breaker #H61521B-4
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WR N0509-DC-Q.
Investigate ground on #12 battery charger WR N0911-DG-Q Inspect D2 switches on 0-1 panel
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WR N2000-IP-Q Repair #18 inverter lights WR N2t14-DG-Q Investigate / repair 01 DG governor ready light WR N2802-IP-Q Investigate and repair #22 inverter
WR N3558-AR Repair valve MV-32053 WR N3560-ZX
- 21 containment chiller trips on high pressure
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WR N4364-DG-Q Perform annual electrical PM on D2 DG The following concern with an-incomplete work package was identified.
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WR N4364-DG-Q - The responsible system engineer was unable to assess test
.d f a sheets-that contained irrelevant and confusing information with no acceptance criteria specified for some of the data. Additional test sheet, that contained clarifying information and acceptance criteria were missing from the package. The test sheets were added.
The inspectors reviewed the following procedures for adequacy of work irstructions, acceptance criteria', inclusion of QC hold points, post maintenance testing requirements, and ease of use:
5ALU 3.2, " Work Control", Revision 16 5ACD_3.8, " General Repair and Maintenance Activities", Revision 7 5ACD 3.10, " Equipment Control", Revision 9 5ACD 3.12, " Nuclear Power Plant Maintenance", Revision 10 SAWI 3.2.4, " Conduct of Work", Revision 0 EP17-41, " Maintenance of Prairie Island Allis Chalmers 480 Volt Breakers LA-600 Manually Operated Breaker 144", Revision 7
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EP17-42, " Maintenance of Prairie Island Allis Chalmers 480 Volt Breakers
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LA-1600'and LA-3000 Electrically Operated Breaker #15M", Revision 9
EP17-76,'" Prairie Island Nuclear Plant #D2 Emergency Generator Electrical Maintenance", Revision 5
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PI 8H13 EM10. " Repair of SH13", Revision 1 j
PM 3119-1-11, "Il Component Cooling Pump Annual Inspection", Revision 3 12, " Preventive Maintenance - Electrical", Revision 1
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The procedures reviewed were generally satisfactory. A concern was identified with " pen and ink" changes-made to procedures without the required reviews.
- Procedure EP17-76'- The inspectors noted " pen and ink" changes to steps 12.2.5, 12.4.1, 12.4.2, 12.4.3, 12.4.4, 12.10.3, 12.11.1, and 12.11.2.
All of these changes,.except'the changes to steps 12.2.5, 12.4.4 and 12.10.3, contained the initials of one individual and were dated prior to the issue date of the applicable WR (N4364-DG-Q). -Steps 12.2.5, 12.4.4, and 12.10.3 were dated after the issue date of the WR and these steps were initia11ed and dated by two individuals.
The cover sheet of the procedure contained.the approval of the plant OC.
There was no objective evidence-that the changes had been reviewed and approved by the OC.
One member of
.the OC had initialed the changes and a review by the full committee was not performed. Section 6.5.G of the Prairie Island Technical Specifications states " Temporary changes to Operations Committee reviewed procedures,,. may be made with the concurrence of two members of the
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unit management staff, at least one of whom holds a Senior Reactor Operator License.
Such changes shall be documented, reviewed by the Operations Committee, and approved by a member of-plant management.
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'within one month." Contrary to the above, the changes to procedure EP17-76 were not approved by the OC as required and changes to steps
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12.2.5, 12.4.4 and 12.10.3 were not concurred in by two staff members.
The failure to comply with Technical Specification requirements in approving temporary procedure changes is a violation of Section 6.5.G of the i
Technical Specifications (282/89029-03B; 306/89029-03B).
2.4.2.2 Past Mechanical Maintenance The inspectors reviewed eight completed WRs for the attributes included in Section 2.4.2, WR M0100-SI-Q Repair internal motor splices of reactor vessel loop A isolation valve MV-32172 WR M0847-SI-Q Install SCC covers on MV 32182 and 32183 WR M1487-SI-Q Repack SI-13-2, SI pump discharge valve WR M4321-DG-Q Perform Diesel Generator Three Month Inspection
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t WR M6855-DG-Q Perform Diesel Generator Three Month Inspection WR N1468-SI-Q Tape over nylon joints for dual. voltage motors for MV-32172 WR N3037-MS-Q Weld disc nut to disc on-reverse flow Main Steam
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isolation check valve, RS-19-4 WR N4331-DG-W Replace D2 Air Start Motor Work Request The procedures were generally satisfar: tory.
Concerns were identified with a modification performed without the proper modification process and a discrepancy in the material used for the modification.
WR N3037-MS-Q - The inspectors reviewed the WR and identified that a vendor recommendation of a disc to disc nut seal weld was implemented
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without a processed modification as specified in procedure NIAWI 5.1.2,
" Modification Initiation", Revision 3. - Also, vendor manual / drawings had not been revised to reflect the seal weld.
Failure to accomplish activities in accordance with the above prescribed procedure is an example of a violation of 10 CFR 50, Appendix B, criterion V (282/89029-01C;
-306/89029-01C).
The inspectors reviewed the purchase orders (P0) for the modification and noted that the disc nut was not referenced on the purchase order. The system engineer stated that the nut was part of the disc assembly'and warehouse records showed an item was taken from the assembly for this WR.
The vendor drawings / manual specified a stainless steel A194 Grade 7 nut, s
'The licensee had no evidence that this type of nut was used in the
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sy s_ tem..The pin referenced on the PO was for an anti-rotational pin and not the pin specified by vendor manual / drawings. The system engineer
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issued a NAR-to address the problems.
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Similar to WR N7133-MS-Q, discussed in Section 2.3.2.2, discrepancies
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in the disc nut material were noted between the weld control' record I
and.the seal weld procedure provided by the vendor recommendations.
l 2.4.2.3-Past Instrumentation and Control Maintenance
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I&C maintenance philosophy included the concept of RCM in the form of a surveillance-program for the detection and prevention of instrumentation
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deterioration.
The inspectors evaluated the extent that vendor recommendations, IEBs, IENs, SILs and other outside source information was utilized in I&C
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maintenance. The component selected for evaluation was the Rosemont, Inc.
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pressure transmitters.
The inspectors reviewed the following documentation:
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10 CFR 21 Report from Rosemont, Inc., dated February 9, 1989 IEN 89-42, " Failure of Rosemont Models 1153 and 1154 Transmitters" SP 1223A, " Calibration and Inspection Procedure for Event Monitoring Transmitters," Revision 4.
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The inspectors verified that the vendor recommended or required actions.were i'ncluded or adequately addressed in the appropriate maintenance procedures or L
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e adequate evaluations for deviations had been made.
The inspectors reviewed the component failure history for selected I&C components to determine whether methods had been established and implemented for_ detecting repetitive failures and adverse trends.
The primary method for identifying repetitive I&C component failures was the routine review of
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instrument calibration cards, which reflected every action taken on an instrument.
Repetitive failures of some components had been identified by this review; however, this method only indicated failure patterns for a particular instrument. The computerized master equipment list had search modes that=
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.provided a listing of actions taken on a family of instruments; however, the manual search appeared to be rather complicated and not commonly used.
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The inspectors reviewed seven completed CM and PM WRs for the attributes described in Section 2.4.2.
WR N0025-RD-Q Repair R-25 SFP Radiation Monitor WR N4562-C0 Recalibrate 12 CC heat exchanger flowmeter
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WR N4737-CL-Q Replace pressure line on pressure gauge WR N5379-CC Calibrate 11 & 12 RCP CC outlet temperature WR N5380-CC PM calibration of 21 & 22 RCP CC outlet flow WR N6272-CC Refurbish Foxboro transmitter in CC system WR N6619-SI-Q Recalibrate flow transmitter, IFT-924 No concerns were noted with this review.
The inspectors reviewed the fn11owing procei>*es for adequacy of work
instructions, acceptance critaria and inclusim of QC hold points.
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PM 1-333, "Feedwater Pump Instrument Calibration", Revision 9 i
PM 1-348, " Turbine System Instrument Calibration", Revision 3 PM' X1-014, " Diesel Generator Annual Inspe>: tion", Revision 9
SP-1002A, " Calibration of Analog Protectfon System", Revision 12
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SP-1002B, " Calibration / Inspection Procedure, Protection and Control
Transmitters", Revision 12 j
SP-1003, " Analog Protection Functional Test", Revision 20 l
SP-1029, " Boric Acid Makeup Flow Channel Calibration", Revision 9
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SP-1223A, " Surveillance Calibration / Inspection Procedure for Event
' Monitoring Transmitters (Auxiliary & Turbine Buildings)",- Revision 4'
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SP-1642, " Surveillance Calibration Procedure, Component Cooling Pump Low Pressure / Auto Start Pressure Switches", Revision 2 SP-2035A, " Surveillance Test Procedure, Reactor Protection Logic Test at Power", Revision 16 The procedures reviewed for safety-related maintenance work were generally satisfactory.
Concerns were identified with incorrect and non-detailed I
instructions with non-safety related PM procedures-as discussed in detail in Section 2.3.2.2.
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'The-inspectors reviewed the current backlog of open WRs for the EDG, SI and i
CCW systems.
The inspectors determined that maintenance was adequately accomplished and there was no backlog that could immediately affect operability of these systems.
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Based on the review of completed CM snd PM backlogs, and work' history of PRA~ selected components, maintenance procedures, and the licensee's action
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in source documents, such as IENs, the inspectors concluded that past performed I&C maintenance had been accomplished in a satisfactory. manner.
2.5 Fire Protection Controls
.l The inspectors evaluated the extent that IENs were utilized in fire orotection i
activities by review of the following:
IEN 84-16 Failure of Automatic Sprinkler System Valves to Operate l
IEN'86-17 Update of IEN 84-16 l
IEN 88-05 Fire In Annunciator Control Cabinets IEN 89-47 Potential Problems with Worn or Distorted Hose Clamps on SCBA
.The inspector's reviewed the listed documents and verified that the licensee had adequately addressed the potential problems.
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The inspectors reviewed five procedures for adequacy of instructions,
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which included fire discovery and control room operator and fire brigade
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actions during fire conditions.
l SACD 3.13, " Fire Preventive Practices", Revision 10
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i SACD 8.5, " Housekeeping", Revision 3
FS, " Fire Fighting", Revision 5 SP 1188, " Fire Protection-Carbon Dioxide System", Revision 5 SP 1194, "Cardox CO System Test", Revision 2
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The inspectors determined that the procedures were generally well written and were ' intended to minimize the amount of combustibles in a safety-related and safe shutdown area, or provided fire strategies regarding safe shutdown equipment, fire equipment, and personnel hazards. However, a concern was noted with the lack of calibration of CO level instruments.
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- SP 1188,(SP 1194 - pressure and level instrumentation in the carbon installatiob)systemhadnotbeeninacelibrationprogramsince dioxide C0 (approximately1974). This low pressure C03 system provided fire protection to the cable spreading / relay room and mohitored Technical Specification parameters. The licensee had satisfied Technical Specification C0,3 system surveillance testing as required; however, to ensure that the pressure and level instrumentation was functioning correctly in fulfilling Technical Specification requirements, the licensee was requested to determine an acceptable method for calibrating the CO
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system instrumentation, j
2.6 Maintenance Work Co,ntrol l
The inspectors reviewed several maintenance activities to evaluate the effectiveness of the maintenance work control process to assure that plant safety, operability, and reliability were maintained. Areas evaluated were i
control of maintenance work requests, equipment maintenance records, job
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planning, prioritization and scheduling of work, control of maintenance backlog, l
maintenance procedures, post maintenance testing, completed documentation, and
review of work'in progress..
The inspectors reviewed the area of maintenance planning to determine if
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maintenance work activities were adequately controlled. The system engineers
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processed all work requests, planned the work, and scheduled the work. The
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engineers sequenced CM, PM, and surveillance activities to coincide with
equipment evolutions on a daily basis. The inspectors observed the daily
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meetings when all new corrective work requests were reviewed by the' Shift Manager and the General Superintendent of Maintenance.
The purpose of this meeting was to assure proper prioritization and availability of necessary
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resources for important, Priority 1, work. The inspectors concluded that this was an effective nethod of management oversight of emergent work.
The inspectors determined that post maintenance test requirements were also determined by system engineers to assure that maintenance was effective and operability restored. The selection of testing appeared to be based on the
' scope of the completed maintenance, any applicable codes, standards, technical specifications, or vendor recommendations, and acceptance criteria for system conditions and component / system performance.
2.7 Engineering and Technical, Support The inspectors reviewed the activities of the engineering organizations related to the field activities of modification installation and testing, maintenance i
support, and material qualification. The organization involved was System Engineering.
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'The inspectors evaluated the extent that engineering principles and
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t evaluations were integrated into the maintenance process.
This was accomplished by review of maintenance work orders, activities associated with failure
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analyses, and other maintenance activities to evaluate the effectiveness of engineering support. Areas-reviewed were engineering support to PM, material qualifications, compliance.with codes and regulations, system engineering
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concepts, industry initiatives and post maintenance testing.
2.7.1-System Engineering
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The system engineering concept had been implemented at Prairie Island for several years and was considered a significant strength. The fo. mal basis for the concept had not been proceduralized but was contained in a memo issued by the General' Superintendent of Engineering and Radiation Protection (GSERP).
The system engineer (also called the Responsible Individual) was accountable-for the reliability and availability of assigned systems and was the focal point for all activities related to those systems.
These activities included WR planning, scheduling, and verifying parts availability to accomplish maintenance.
'The inspectors performed waldowns with the cognizant system engineers.
The system engineers had excellent technical and administrative knowledge.
System assignments considered the complexity and importance of the system to safe, reliable operation of the plant consistent with the level of experience of the individual.
Discussions with approximately 33% of the system engineers found-two instances of where lack of knowledge existed but was considered.of minor significance.
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System engineers performed failure analysis, determined root cause, and identified adverse trends to monitor system performance. _The inspectors determined that there was a conscious = effort to look at previous work history when processing: corrective work requests.
However, this review was typically limited to the component in question and relied on system engineer memory to
' detect generic equipment failures in assigned systems. ' Because of the lack of a formal WR trending program, repetitive equipment failures, adverse trends, and appropriate corrective actions were not identified.
For example, the #22 rod control motor generator failed eight times on reverse overcurrent trips since January 1986. Two Unit 2 reactor trips in December 1989, were exacerbated by the adverse condition.
The emergency lighting battery low electrolyte level discussed in Section 2.3.2.1 was also considered an adverse trend that resulted in untimely corrective action.
Even though the system engineers were doing an-excellent job, there was no formal mechanism that detected generic plant-wide failures except for specific types of equipment, such as MOVs.
The licensee recognized this shortcoming and agreed that programs were needed to provide methods to detect generic equipment problems and provide guidance on the selection and method of trending important equipment parameters.
The inspectors identified the following concern with untimely response and
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action to industry and NRC notices.
The inspectors reviewed the licensee's Operating Experience Log, dated L
January 3, 1990, which listed the status of NRC and vendor information p
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-e notices.. The inspectors noted a 10 CFR 21 report issued by Limitorque on
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November 3, 1988, that had not been responded to in a timely manner,
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since the log. indicated a response from Technical Engineering was due by January 10, 1989, but was still outstanding at the time of this inspection.
The Technical Engineering section was unaware of the assignment.
The report pertained to common failure of melamine torque switches of specific Limitorque motor-operated valve (MOV) model types and serial numbers.
The cause of failure of the melamine torque switch was identified by the vendor as post _ mold shrinkage, which was affected by temperature and age.
The inspectors requested the status of the MOVs affected by the report that had not yet been inspected.
Information requested included:
(1) Environmentally Qualified (EQ) valves, (2) safety-related valves, (3)
MOVs that required repositioning to perform their safety function (active), and (4) MOVs that functioned as containment isolation valves.
Information was furnished the next day and identified 18 safety-related.
i valves for Unit 1 (8 of which were EQ), and approximately 18 safety related valves for Unit 2 (1 was EQ) that were known to contain melamine torque switches.
Further discussions with the licensee determined that Generic Letter 88-07, " Modified Enforcement Policy Relating to 10 CFR 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants", applied and a written " Justification for Continued Operation" (JCO) was warranted for the EQ identified valves.
The licensee provided the inspectors with a JC0 on January 15, 1990.
The inspectors were informed that torque switches on all but one Unit 2 EQ
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valve had been replaced due to other anomalies associated with the torque switches and the same changes were scheduled for Unit 1 EQ MOVs.
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The licensee changed the torque switch on the EQ Unit 2 MOV on January 15,
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1990, and planned on replacing the 18 safety-related torque switches as plant conditions allowed and during the Fall Unit 2 refueling outage.
Torque switches on all of the affected MOVs on Unit I were replaced during the January-February 1990 refueling outage.
No operational concerns were noted with the JC0 or the replacement schedule.
The inspectors noted several other outstanding items listed on the i
Operational Experience Log that were not addressed in a timely manner.
Procedure SACD 3.7, " Operating Experience Assessment", Revision 5, required that all items be assessed for plant applicability within approximately 90 days after the receipt of the document. A quarterly report that listed I
all open items showed 55 out of 89 items had been open more than six i
months. ' Thirty-nine of these had been open more than one year, and eight
had been open more than three years.
Because of the inspectors' concerns,
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the licensee conducted an assessment of the open items and, besides the Limitorque Part 21 report, identified that the outstanding items did not
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affect plant operability. The inspectors were still concerned since this
"first look" review identified corrective action needed such as changes in i
l procedures, PM requirements, pH schedules, and equipment inspection; however, the licensee did not give a time frame when the corrective action was to be completed.
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An inspection conducted by the NRR Vendor Inspection Branch in
October-November 1988, identified a similar finding in the failure to perform and assess 17 vendor information letters.
The licensee's action to timely assess information notices in the Operational Experience Assessment program was ineffective as indicated by the 55 notices older than six months.
The failure to take timely corrective action in the assessment of Operational Experience items is an example of a violation of 10 CFR 50, Appendix B, Criterion XVI (282/89029-02B; 306/89029-02B).
- i The apparent root cause of the untimely assessment was that system engineers had too many' responsibilities and this assessment was considered
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" low priority." The licensee was aware of the heavy system engineer work load and had planned to correct the situation. The Operational Assessment Group was initiated to perform-initial screening of the items and closely-track the assessment progress, 2.8 Maintenance and Support Personnel' Control The inspectors reviewed the licensee's staffing control and staffing needs.
Inspection activities included interviews with plant personnel, training facility observations, in plant observations, and review of documentation.
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A comprehensive plan had been developed for personnel control, which was nroceduralized and-implemented into the maintenance process. The organization chart was available and generally up to date.
Selected personnel at various
. management levels were interviewed and were found to be knowledgeable of responsibilities and accountability, The staffing requirements for the mechanical, electrical, and I&C departments appeared to be adequate for non-outage work. These departments were supplemented with contractor services during heavy workloads during outages.
The licensee also utilized " traveling" maintenance personnel from other NSP plant facilities during outages. The majority of. these workers were very experienced from working previous Prairie Island. outages. Their knowledge of the plant, procedures, and nuclear work practices was very good.
The licensee had a good program for the control of traveling maintenance personnel and was described in an instruction, entitled i
" Indoctrination For General Work Rules at Prairie Island".
The instruction r
required 'special. training for several work activities and provided other plant specific information.
Training and qualification records were reviewed for maintenance personnel that participated in maintenance activities witnessed by the inspectors.
-The inspectors determined that personnel were trained and qualified to perform-the assigned maintenance activities.
'2.9 Review of Licensee's Assessment of Maintenance The inspectors evaluated the licensee's quality verification process in the maintenance area by the review of audit reports, surveillance reports, nonconforming activity reports and QC inspections. The documents were reviewed to assess technical adequacy, root cause analysis, timeliness of corrective action and justification for close out of corrective action documents.
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2,. 9.1 Audit and Surveillance Reports i
The inspectors reviewed the results of Audits AG-88-02, AG-88-30 and AG-89-11
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that were performed on maintenance activities during the periods January-February 1988, August 1988, and March-May 1989, respectively. Two
of the three (88-02, 89-11) were done during outages in. conjunction with audits
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of other functional areas and were primarily performance based. Maintenance i
activities were witnessed and problems assessed for root cause and possible maintenance program weaknesses. Audit AG-89-11 determined that certain ongoing work constituted modifications and not maintenance.
Similar problems were
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identified by the MTI inspectors as discussed in Section 2.4.2.2.
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AG-88-02 was compliance based and concentrated on PM procedures, with emphasis
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on verification of revision control, and the PM schedule.
The audit was extensive; however, too narrowly scoped to adequately assess the licensee's PM program.
For example, procedures were not sampled to verify that vendor recommendations were evaluated and incorporated consistent with those evaluations, nor were field observations included to determine the adequacy and accuracy of procedures during implementation.
2.9.2 Review of Maintenance Self-Assessment j
The inspectors reviewed the results of Audit AG-89-36 performed in June and
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August 1989. This audit evaluated the licensee's programs using the framework i
of the 1988 NRC Policy on Maintenance-Based on the results of the MTI, the inspectors concluded that the licensee's self-assessment was accurate.
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example, the audit detected shortcomings in predictive maintenance and equipment
history trending, both of which the MTI identified as discussed in Sections 2.2
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and 2.7.1.
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2.9.3 Documentation of Nonconformances i
During the review of maintenance work activities, the inspectors noted that i
most equipment failures were not documented on nonconformance reports.
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documents used for this purpose were the Nonconforming Item Report (NIR) for hardware items and the Nonconforming Action Report (NAR) for personnel errors.
The inspectors reviewed procedures SACD 2.4, " Nonconforming Activities",
Revision 3, and 5ACD 8.4, " Nonconforming Items", Revision 5.
The following concerns were noted:
Paragraph 3.0 of SACD 8.4 required that the procedure be applied to QA related activities.
"QA related" was defined as any item, activity or service that performed or provided information that was important to the safe and reliable operation of the plant.
This definition was interpreted by plant personnel as safety-related items only and did not include B0P items important to safety.
B0P items, which are important to safety, appeared to meet the definition in the procedure.
Because B0P items were not considered for this program, corrective action, root cause analysis, common mode failure and program weaknesses would not be trended.
Paragraph 3.0 of SACD 8.4 required that a NIR be written for equipment failures that did not result from normal wear.
In most cases, NIRs were written on items found unacceptable at receipt inspection but not on failures that occurred to plant equipment in service.
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licensee personnel interviewed indicated that QA and QC had the sole
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responsibility for initiation of these forms. Procedure SACD 8.4 stated that personnel who identified nonconforming items were responsible for initiating.an NIR. The inspectors found numerous examples of items and actions that met the requirements of an NAR or NIR but were not identified by am plant personnel.
Examples included: bus bar corrosion on the IM
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transformer and 4.16 kV Bus 11 and 12, a December 1989 failure of #22 turbine driven auxiliary feedwater pump (TDAFWP) surveillance, due to a defective TDAFWP governor that was installed, and a vendor modification on -
MS isolation check valve RS-19-4, that was performed without using the modification process. The failure to document equipment failures on NARs and NIRs as required by procedures is an example of a violation of 10 CFR-50, Appendix B, Criterion V (282/89029-010; 306/89029-010).
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2.9.4 Effectiveness of Correc_tive Action While a' process for identifying and dispositioning nonconformances existed, its-effectiveness was not always evident. As previously discussed, -the inspector-identified modification that was worked as maintenance was determined to be indicative of an unresolved programctic problem of determining what
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constituted a modification.
The inspectors found similar examples documented by the licensee in Audits AG-88-31, 89-3, 89-9, and 89-11 as well as NARs A243, A252 and A259.
Closure of the these NARs, as well as the applicable part of AG-89-11, indicated that root cause evaluations were not performed.
Typically, the corrective actions were narrow in scope and only addressed the individual nonconformances.
No corrective actions were taken to prevent recurrence.
The inspectors -interviewed system engineers who were the primary source of engineering support =to the maintenance process. The inspectors determined.that.
not all engineers understood the concept of alteration or modification and its importance in the configuration control process. The failure to take adequate o
corrective action to preclude performing uncontrolled modifications.is a
. violation of 10 CFR 50, Appendix B, Criterion XVI (282/89029-02C; 306/89029-02C).
3.0.
Synopsis
This synopsis highlights the inspection findings in terms that are meant to be representative of the presentation tree that is attached to this report. A (+) means that the area is good or has the potential to be so; a (-) means that the area is weak or not fully developed.
3.1 Overall Plant performance 3.1.1-Historic Data (+) The-three year equivalent-availability was accomplished for both units; there were zero unplanned safety system actuations for 1988 and 1989; none of the reactor trips appeared to be maintenance related; safety system availability goals were reasonable and were achieved and well within the plant goals.
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(-) Two reactor trips necurred on Unit 2 in December 1989, which was responsible for exceeding the forced outage tate and reactor trip goals for Unit 2.
3.1.2 Plant Walkdowns (+) Plant management conducted plant walkdowns that included work in progress and effective followup that corrected deficiencies identified.
(+) Material condition was good for a unit in operation and a unit in a refueling outage; no steam or water leaks were found on the floor, with measures in place to control any leakage from sampling lines; deficiencies were identified and tagged.
(-) Cumulative waste debris, such as combustible paper and plastic, oil soaked absorbant material and wooden carts, showed a breakdown in the control of combustibles.
3.2 Management Support of Maintenance
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3.2.1 Management Commitment and Involvement (+) The system engineering concept had been implemented and effective for several years and was considered a significant strength; system assignments considered the complexity of the system with the level of experience of the individual.
(+) The 1989 self assessment was performance based and effective in identifying maintenance problems and concerns.
(-) Excessive backlog of items in the Operational Experience Assessment program resulted in untimely assessment of industry and NRC notices and untimely corrective action on a Limitorque Part 21 report that affected more than 25 MOVs; system engineers were given too many responsibilities to adequately assess items.
3.2.2 Management Organization and Administration (+) A comprehensive maintenance plan included milestones and completion dates for improvement programs and goals.
(-) The predictive maintenance program had not been fully implemented and was not considered to be at a level commensurate with the rest of the industry; of the four programs identified, only the MOV program was considered effective.
(-) Modifications / alterations were not implemented as defined by Prairie Island's modification program.
3.2.3 Technical Support (+) Prairie Island's collective radiation exposure was considerably below the industry average; radiation protection job coverage and ALARA support for maintenance activities were considered streng+.ns.
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(+) System engineers had excellent knowledge of systems and were considered the focal point of the maintenance process; engineering support in the areas
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of post maintenance testing was also a strength.
.(-) " Pen and ink" changes to maintenance procedures were made by system engineers without the proper Technical Specification requirements and made WRs difficult to follow.
(-) Previous examples of performing modifications without using the r
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modification process were identified by QC; however, corrective action was
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narrow in scope and ineffective to prevent recurrence.
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3.3 Implementation of Maintenance 3.3.1 Work Control l
(+) The maintenance backlog was very low; priority system was well
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controlled.
L (-) Nonconforming action and item reports (NAR/NIRs) were not written for BOP i
items.
L (-) Backlogged CM and PMs were not tracked in such a way to easily determine WRs on hold for parts, average man-hours required to complete a WR, and the
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composition of backlogged WRs assigned to system engineers.
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_(-) Maintenance procedures generally lacked detail; " pen and ink" changes made procedures confusing and difficult to follow; outdated I&C procedures and calibration cards contributed to inaccurate information; no acceptance criteria were noted for some_ fire protection and I&C procedures.
3.3.2 P1_ ant Maintenance Organization
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(+) The experienced, highly skilled and dedicated maintenance staff was considered to be Prairie Island's most significant strength; I&C technician skills overcame procedure deficiencies; excellent communications existed between engineering and maintenance support staffs, (-) Nonconforming actions and items were not documented as required, appeared to be the sole responsibility of the quality organization, and were not
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written for BOP items.
3.3.3 Maintenance Facilities. Equipment, and Material Control (+) Control of M&TE was satisfactory, defective tools were segregated from those in calibration.
-(-) Material for the Main Steam check valve modification was not traceable to the warehouse.
3.3.4 Personnel Control l
(+) _The established training program for maintenance personnel was considered a strength; very experienced " traveling" workers were used for outages, i
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4.0.
Exit Meeting The inspectors met with licensee representatives (denoted in Paragraph 1) on February 23, 1990, at Prairie Island Nuclear Generating Plant and summarized the purpose, scope, and findings of the inspection. The inspectors 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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APPENDIX A ACRONYMS ALARA As Low As Reasonably Achievable ASME American Society of Mechanical Engineers BOP Balance of Plant CCW Component Cooling Water (System)
CM Corrective Maintenance CRD Control Rod Drive (System)
EDG Emergency Diesel Generator (System)
EQ Environmental Qualification ESF Engineered Safety Feature GSERP General Superintendent of Engineering and Radiation Protection HP Health Physics I&C Instrume.'. & Control IEB NRC Bullviins IEN NRC Notices INPO Institute for Nuclear Power Operations IST Inservice Testing JC0 Justification for Continued Operation kV Kilo Volt LER Licensee Event Reports LCO Limiting Condition of Operation M&TE Measuring and Test Equipment MOV Motor Operated Valve MSIV Main Steam Isolation Valve NAR Nonconforming Action Report NFPA National Fire Protection Association NIR Nonconforming Item Report
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NPRDS Nuclear Plant Reliability Data System NRC Nuclear Regulatory Commission NSP Northern States Power OC Operations Committee PM Preventive Maintenance P0 Purchase Order PRA Probabilistic Risk Assessment QA Quality Assurance QC Quality Control RCA Radiological Controlled Area RCM Reliability Centered Maintenance RCT Radiation Control Technicians RRP Reactor Recirculation Pump RWP Radiation Work Permit SALP Systematic Assessment of Licensee Performance SCBA Self Contained Breathing Apparatus SI Safety Injection (System)
SOER Significant Operating Experience Report SRD Self Reading Dosimeter TDAFWP Turbine Driven Auxiliary Feedwater Pump TS Technical Specification WR Work Request WRAC Work Request Authorization Coordinator
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