IR 05000369/1989015
| ML20248B674 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 09/07/1989 |
| From: | Blake J, Crowley B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248B665 | List: |
| References | |
| 50-369-89-15, 50-370-89-15, NUDOCS 8910030262 | |
| Preceding documents: |
|
| Download: ML20248B674 (90) | |
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/p3 Heoq*o UNITED STATES NUCLEAR REGULATORY COMMISSION
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REGION il n
101 mar.lETTA STREET,N.W.
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' ATLANTA, GEORGIA 30323
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Report Nos.: -50-369/89-15'and 50-370/89-15 Licensee:
Duke Power Company.
422 South Church Street Charlotte. NC 28242 Docket Nos.:
50-369 and 50-370 License Nos.:
Facility Name: McGuire 1'and.2 l
' Inspection Condu'eted: June 5-9,' June 19-23, 'and July 28, 1989'
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h Inspectors:
B.
R., Crowley, Team Leader [
Date Signed Team Me,abers:
P. Fillion E. Girard M. Glasman G. Hallstrom M. Lauer M. Miller
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. Wh ta Approved by:
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f J/J Blate, Chief Dite Signed
~ t rials and Processes Section-
/>DivisionofReactorSafety n ineering Branch SUMMARY Scope:
This special, announced inspection' consisted of an indepth-team inspection of the maintenance program and 'its implementation.
NRC Temporary Instruction 2515/97 issued November 3, 1988, was used as guidance for this inspection.
Results:
Overall, the maintenance program was judged to be. GOOD with G']OD implementation.
Areas of strength and weakness are highlighted in the Executive Summary, with details provided in the report.
8910030262 890922 FDR ADOCK 05000369 O
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TABLE OF CONTENTS Page Executive Summary....................................................
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I n s pe c ti o n. De ta i l s...............................................
a.
Nuclear. Service Water System...............................
b.
Aux i l i a ry Fe edwa te r Sy s tem...................................
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Medi um-Vol tage Swi tchgea r and Motors........... -............
12'
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125 Volt DC Power Systems - Safety-Related.................
14:
e.
600 Volt AC' Distribution System............................
f.
Instrument Air System.....................................
17-g.
Ma i n te nan ce Wo r k Ob s e rv at ' on s...........................'... - 19 h.
Material Control............................................ -24 1.
-Health Physics'..............................................
25.
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Work Management............................................
27-k.
= Engineering Support For Maintenance.............._.........
1.
QA/QC Involvement in Maintenance............................
m.
Historic Data Related to Maintenance........................
n.
Response to Industry Issues.....................a...........
o.
Backlog Control..............................................
p.
Post-Maintenance Testing...................................
q.
Maintenance Trending....................................... '36 r.
Ma i n t e n a n c e Fa c i l i t i e s......................................
s.
Instrument Calibration Program........................'.....
t.
Staffing Control, Personnel Training And The Qualification Process....................................................
u.
Acknowledgement of Risk Significance in Prioritizing Work..
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Issues Identified a.
Accuracy of Information Furnished to NRC..................
441 b.
Problems With Labeling Permanent Plant Equipment............
c.
Deficiency Tagging Problems.........,.......................... L48 d.
Root Cause Analysis........................................
e.
Preventive Maintenance For Molded Case Circuit Breakers -....
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A LA RA C o n c e r n s...............................................
g.
Drawing Discrepancies......................................
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Work Requests Discrepancies....................................
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600 Volt AC Rating.for CBs................................ -58'
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' Housekeepi ng and Materi al Condition........................ L 59 o
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Evaluation of Plant Maintenance a.
Overall Plant Performance Related to Maintenance - Direct Measures....................................................
b.
Management Support of Maintenance..........................
(1) Management Commitment and Involvement...
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(2) Management Organization and Administration............ 63 (3) Technical Support.................................... 64 c.
Maintenance Implementation..................................
(1) Work Control.........................................
(2) Plant Maintenance Organization........................
(3) Maintenance Facilities, Equipment, and Materials Control...........
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(4) Personnel Contro
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Followup on Previous Inspection Findings........................
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Exit Interview..................................................
APPENDICES Appendix 1 - Persons Contacted Appendix 2 - Acronyms and Initialisms Appendix 3 - Procedures Reviewed Appendix 4 - Maintenance Work Requests Reviewed FIGURE 1 - Maintenance Inspection Tree
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EXECUTIVE SUMMARY Background The Nuclear Regulatory Commission (NRC) con:;iders effective maintenance of equipment and components a major aspect of. ensuring safe nuclear plant operation and has made this' area one' of the NRC's highest priorities. In this regard, the Commission issued.a Policy Statement dated March 23, 1988, that states, "it is the objective of the Commission that all components, ' systems, and structures of nuclear power plants be maintained so that plant equipment l
will perform its intended function ' when required.
To accomplish this objective, each licensee should' develop and implement a maintenance program which. provides for the periodic evaluation, 'and prompt repair of plant :
components, systems, and structures to ensure their availability."
To ensure effective implementation of the Commission's maintenance policy, the NRC staff is undertaking a major program to inspect and ' evaluate the effective--
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ness of licensee maintenance activities. As part of this inspection activity, q
the McGuire inspection was performed in accordance with guidance provided-in NRC Temporary Instruction. (TI) 2515/97, Maintenance Inspection, dated November 3, 1988.
The TI includes a " Maintenance Inspection Tree" that-identifies the major elements associated with effective maintenance. The' tree
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was designed to ensure that all factors related to maintenance are evaluated.
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Conduct of Inspection
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The maintenance inspection at the McCuire Nuclear Plant was initiated with a site meeting on May 16-17, 1989, where the inspection scope was discussed. In addition, a comprehensive package of material, as requested by NRC letter dated April 27, 1989, was provided for inspection preparation.
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The inspection was conducted by a team consisting of a team leader and eight inspectors.
The team spent two weeks, June 5-9 and 19-23, 1989, on site conducting the inspection.
l The inspection was performance based and directed toward evaluation of equip-l.
ment conditions; observation of in process maintenance activities; review
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of equipment histories and records; and evaluation'of performance indicators, maintenance control procedures, and the overall maintenance program. The team selected six systems and directed the' inspection toward determining whether these systems were being properly maintained. The systems selected were, j
i Service Water (RN)
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. Auxiliary Feedwater (CA)
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Medium Voltage Switchgear and Motors
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125 Volt DC Systems - Safety-Related
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600 Volt AC Distribution Systems-
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Instrument Air (VI)
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(letters in parenthesis tre licensee identification for system)
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Results The inspection results are presented in Figure 1 as the completed inspection tree.
As indicated in the tree, three major areas of the licensee's maintenance program were evaluated:.(1) Overall Plant Performance Related to i
Maintenance, (2) Management. Support of. Maintenance, and. (3) Maintenance Implementation. Under each major area, a number of elements were evaluated, rated, and colored using the following guidelines:
" GOOD" Performance (Green)
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Overall, better than adequate; shows more than minimal effort; can have a few minor.
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areas that need improvement
" SATISFACTORY" Performance
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Adequate, weaknesses may exist, cocid
(Yellow)
be strengthened
"P00R" Performance (Red)
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Inadequate or missing
(Blue)
Not evaluated
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In general, the top half of the box (element) was rated depending on whether-the element was in place and the bottom half was rated depending on how. well the element was being implemented. As noted in the tree, overall, the McGuire program for establishing ar.d implementing an effective maintenance program was rated " GOOD" both in program and implementation.
For the ' three major areas:
(1) Overall Plant Performance was rated " SATISFACTORY," (2) Management Support j
was rated " GOOD" for - program and implementation, and (3) Maintenance Implementation was rated " GOOD" for program and implementation.
These ratings were based on :pecific strengths and weaknesses identified in the.
report details.
The following are the nore significant strengths and weaknesses identified by the team:
Strengths The Maintenance staff was considered to be a strength.
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Staffing levels, experience. levels; of-management. and i
crafts, qualified personnel, good.. supervisor. to craft ratio, and an enthusiastic attitude combined to provide an overall strong organization.
Maintenance facilities and equipment were good..All shops j
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were orderly and well laid out with good equipment. Tool i
rooms (contaminated and non-contaminated) were clea'n and orderly.
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The material control program was good.
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strong point was the Bar Code system used for the control l
of material issue.
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J The training and qualification program was strong.
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Employee Training and Qualification System (ETQS) program provides very detailed requirements. One area identified l
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for improvement was the_need.to assure that the Transmis-L stons Department receives training and qualification equivalent to site requirements -since Transmissions works-on safety-related equipment.
The QA/QC Department was considered to be a strength. The
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organization was well: staffed with qualified personnel;.
heavily involved in the maintenance process; and appeared to contribute to the success of the maintenance program.
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The maintenance data base and equipment records systems
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were.very good.
Records were readily retrievable and'
provided useful :information in evaluating equipment _past history for maintenance purposes.
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Engineering Support was strong. Although the system expert-program has been in effect a relatively short time, and some ' personnel appeared less-' familiar. with'their: systems than desired, the system appeared' to work well and should contribute to a better maintenance program.
There was good interface and communications between the
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maintenance staff and other. organizations.
Weaknesses Some weaknesses were identified in the: quality of completed-
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WRs.
Most of the discrepancies related to identification of the cause of the problem (including the lack of use of cause codes) as required by procedures.
Others.were inattention to detail in. assuring.that WR information was complete and correctly entered.
Weaknesses were identified in the PM program relative-to
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not testing _ the functional ' operability of' molded case circuit breakers and failure - to include some GL 88-14'
accident mitigation valves in the PM program.
The maintenance program could - be strengthened by -
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incorporation of some aspects of. PRA into the maintenance process.
Weaknesses were. identified in ~ the - deficiency tagging-
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program.- Tags had not been removed from equipment when.
repairs had been completed, tags were illegible, ' tags had :
been - on some equipment for-long periods of time, and a significant number.of minor equipment deficiencies ' were identified. by the - team that had not been identified and tagged by_the licensee.
Some minor' procedure weaknesses were. identified.
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included ' a general lack of implementation of procedure MMp 1.0 requirements to enter. cause. codes; on' WRs, an
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i out-of-date (1981) Station ' Directive (3.3.4) which did not include the latest guidelines for exception from code hydrostatic test requirements, and a PM procedure for
switchgear which did not include inspection of the wiring 1'
and bus compartments.
Some of the above weaknesses were known to the licensee prior to the inspec-
tion. The licensee had previously-conducted a Maintenance Self Assessment and I
had instituted corrective action on resultant recommendations.
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Inspection Details a.
Nuclear Service Water System The Nuclear Serv _ ice Water.(RN) System provides cooling water to various heat exchangers (HXs) required 'for safe operation and shut-down during normal and accident conditions.
Examples of, HXs and other _ loads supplied by the RN System include the Component Cooling Water (KC) HXs, Containment Spray HXs, Diesel Generator Cooling Water HXs, Engineered. Safety. Feature room air handling fan coil units, Auxiliary Feedwater (CA) Pump motor coolers, CA supply, and Fuel Pool makeup.
The water sources. and returns. for the.RN System are Lake Norman. and
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the Standby Nuclear Service Water' Pond (SNSWP). 'The system's principal components consist of two 100 percent capacity strainers and pumps per unit and the ~ piping and valves necessary to control flow.
The team's inspection of the RN System included a walkdown inspectica of the system, review of. maintenance procedures, review of mainte-nance records, review of HX performance monitoring and' observation of maintenance in progress on two valves.
I Walkdown Inspection f
The team performed a walkdown inspection of the' RN system to assess the conditions of the RN components and the areas'in which they were located, as an indication of the adequacy of' maintenance performed.
Generally,,the team observed 9000 housekeeping and material condi-tions, though sonie deficiencies were noted.as listed below.
i In several locations (e.g., near the strainers and. KC HXs),
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significant puddles of water had accumulated as.a' consequence of
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condensation dripping from uninsulated components. Such water could result in spreading of contamination, obscuring true leaks.
and/or increasing corrosion or rusting of exposed surfaces.
Some evidence of rusting from the condensation was observed on.
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l Valve IRNB79 in a bypass-line around the discharse check valve I
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for RN pump 1B had no identification label. The _ team reported l
the missing label to the licensee on June 7 and was informed-
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that a replacement tag.was installed later that day.
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Licensee Drawing No. MC-1574-1.1, Revision 13, " Flow Diagram of
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Nuclear Service Water System", showed a six inchL branch line.
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coming off the eighteen inch piping between the RN IB pump and its discharge check valve.
The. team observed the line was not i
present'and so informed'the licensee.
In response to the team's
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observation, the licensee determined the actual location of.
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l the branch line and stated that the drawing would be corrected.
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The difference between the actual location (identified by the licensee) and.the location indicated on the drawing did not
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The licensee contended that the drawing error was an isolated.
incident.
However, the team did find other. drawing errors and..-
this issue is described further'in paragraph 2.g below.
Deficiency tagging to identify, hardware deficiencies did ~not
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appear properly, controlled for two. examples checked.
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No.12479 on-HX 1RNHX0018 was for a deficiency. determined-invalid (for which Work' Request (WR) 135847 had been written and subsequently voided-in 1988),-but the tag'had not been_ removed.'
Tag No.14011 ~ observed at valve 2RN25B was. faded such that it; contained no legible information other than the tag number. The team was informed that this was an "old style" tag that had not-been in use for many months.
Current. tags were designed. to preclude - fading and loss of legibility. The only incomplete work intended for 2RN25B was described on WR 138844 which was-recently initiated (May 30, 1989) and should have resulted :in attachment of a "new style" tag on 2RN25B.
Concerns regarding the licensee's tagging are discussed in detail in Section 2.c'of this report.
Although some discrepancies were observed in i the : walkdown, the team considered them to be generally minor. and' concluded ' that the appearance of the system indicated generally good maintenance.
Review of Procedures Ten procedures utilized in performance of RN System maintenance were reviewed by the team and are identified in Appendix 3.
The team did not identify any technical errors,.but identified the following human factor weaknesses:
Individual procedure. steps were not required 'to be signed or l
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possibility of missing steps.
Figures were placed at the end of the procedures only. It would
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be helpful to have them near steps within the procedure where they could more easily be referred to.
Data entries and verifications were not made at the step where.
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they were specified, but rather in separate sheets at the end of.
the report.
This increases the likelihood of missing steps.
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Some steps were too long and contained too many verbs, increas-
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Although legibility was generally good in the procedures
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reviewed, the figures in IP/0/A/3066/01 were an exception as portions could only be read with difficulty.
The team considered the procedures to be adequate with some weak-nesses in human factors.
Review of Maintenance Records The team reviewed 35 completed RN System WR packages which are listed in Appendix 4.
Those WRs were selected from a licensee computerized database listing of RN System WRs initiated in the past two years.
Twelve of L the selected WRs were clearly identified as preventive maintenance (PM), and they were only reviewed for on-time completion.
The remaining 23 of the 35 WRs were reviewed in greater detail for proper entries of the data required on the WR - such as priorities, l
authorizations, work descriptions, failure and cause, inspections, tests, etc.
The team determined that the WR records were readily retrievable
and provided evidence that maintenance activities were properly
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performed.
The PM WRs were judged to have been completed without excessive delays. For the other WRs reviewed, application of proper priorities, work sequencing, authorizations and QC inspections were noted. Post maintenance testing appeared generally adequate, though l
some areas of concern were identified. Data and information entered l
on the WRs was usually sufficiently complete and detailed to be useful in identifying the cause of repeated equipment failures and for developing appropriate preventive and/or corrective actions.
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However, some entry deficiencies were found which might' inhibit l
l recognition and analysis of important trends. These deficiencies are described in Section 2.h below.
Review of Heat Exchanger Performance Monitoring The team reviewed and assessed actions taken by the licensee to assure that HXs in the RN System were maintained operable.
Concerns have been expressed in the past regarding nuclear plant service water system HX degradation, with McGuire cited as an example (see NRC Case Study Report AEOD/C801 dated August 1988).
The team conducted its review through discussions with responsible licensee personnel, observation of HX monitoring, review of 1988 and 1989 HX performance trends, review of the basis for the differential pressure (dP) acceptance criteria set for HX performance monitoring, and review of examples of HX maintenance WRs.
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1 The team found that the. major RN HXs.were being monitored for-satisfactory performance at least quarterly. The Containment ' Spray.
HX was monitored using heat transfer measurements while differential pressure (dP) across the HXs was measured.for the others.. The -team determined that dP.. HX acceptance criteria developed by the licensee 1 Design Engineering Department appeared conservatively ~ based. :TrendL
data. indicated periods ; of. rapid degradation of. the performance of..
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some of the HXs that occurred seasonally due to '.' lake' turnover.".The trend-data generally indicated prompt maintenance actions by.the licensee when unsatisfactory HX performance was noted.. Maintenance d
to-reve_rse unsatisf actory performance involved mechanically cleaning the HX tubes.
The team judged: the licensee to be undertaking 1a
. good program for. maintaining.their HXs capability to meet. design requirements.
Observation of Maintenance in Progress Maintenance was observed in progress on valves ORN151 and 1RN190 (first ' number is~ unit, 0. indicates a component common to both units).
The maintenance activities observed by the team were as follows:
Valve ORN151 Removal of the installed Limitorque operator preliminary to its
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overhaul (essentially preventive maintenance) per WR 68901 Resetting the torque switch.to new values per WR 96606
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Examination for ' defective Melamine insulated-torque switch
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( repo.rt ed defective in 10CFR Part 21 ' report letter from-Limitorque dated 11/3/88) per WR 96606 Valve IRN190 Inspection for connection air leakage following replacement of
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metal flex hose on air actuator per WR 69249 i
In addition to observing the above activities, the. team reviewed entries in the involved WRs and procedures and discussed the work with the personne1Linvolved.
The following matters of concern were identified by the ' team from their observations, reviews and discussions-1 Personnel who removed the ORN151 actuator carried it manually -
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from its location and walked.through a cable tray located on i
the floor in doing so.
Craft personnel who were carrying the.
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actuator were questioned by the team-regarding this practice
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when it occurred and.' indicated no knowledge of requirements against such action.
However, licensee. management stated that l
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they considered using cable trays as a pathway unacceptable and they indicated.that personnel would be cautioned against this practice and that current procedures on erection of scaffolding included precautions to ensure protection.of cables from damage.
It is not' clear to the team that. precautions in scaffolding procedures would assure against ' personnel using cable trays as a '.. pathway, as scaffolding use may not be 'specified for many maintenance jobs. The team considers the incident they observed to have been primarily a weakness in planning. Region II will review'this matter further in a subsequent inspection.
It is identified as Inspector Followup Item 369,370/89-15-01, '_ Walking in Cable Trays.
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In two. instances when the team was contacted to observe work on WR 68901 the work was delayed due to' the need to accomplish l
unforeseen work - in the first it was due.to the need to gag a
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valve to preclude excessive valve leakage and in the other-a pipe support prevented. craft already at the valve (in a radiation area) from removing the actuator.
Both instances appeared to represent inadequacies.in job planning.
It should be noted, however, that the team did not find any other concerns regarding the planning for the RN System work observed and the planning appeared generally satisfactory.
L The team found that the RN System work they observed.in progress was l
generally properly authorized, performed and documented.in accordance i
with the controlling work requests and that the personnel involved appeared knowledgeable and qualified. The only concerns identified appeared to stem.from weak.nesses in planning.
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Auxiliary Feedwater System The Auxiliary Feedwater (CA) System consists of two motor driven pumps, one turbine driven pump,- and associated piping, valves, and controls for each unit.
The motor driven CA pumps each supply feedwater to two steam generators and the turbine driven CA pump -is capable of supplying feedwater to all four steam generators.
The preferred sources of condensate quality water 'are the upper surge tank, CA condensate storage tank, and condenser hotwell. The assured.
source of water-to the'CA pumps is the safety-related portion of the
- Nuclear Service Water (RN) System.
The team evaluated maintenance on.the CA. System by performing-walkdown inspections, personnel interviews', work observations, and document reviews.
The walkdown inspections were conducted of'the CA System for both Units 1 and 2.
The inspection covered the entire system, except for the Unit 1 exterior doghouse and the reactor building portion of the system.
In addition to housekeeping examinations throughout the various equipment areas, the general
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equipment condition was. inspected.
The pumps,; motors, valves,.
piping, hangers, and other support structures were inspected for cleanliness, leaks.(water, oil, and grease), proper identification, and general ; condition..The interviews were conducted with selected system personnel from the maintenance, : performance, operations, projects',~ and design engineering organizations. Observations were-made of in process preventive maintenance, pump testing, and modifications.
The team observed the following. in process maintenance for th'e CA System:
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WR 01100A, Perform PM 3676, vibration readings'taken on turbine driven CA pump (MP/0A/7300/01).
PT 1/A/4252/01, Pump performance surveillance test on turbine :
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driven CA pump WR 953540, Install motor driven CA pump IB recirculation valve
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test connections across valve ICA-32B (ME-VN-1860)
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WR 500286, Remove packing, clean stem and stuffing box, and repack valve 2CA-25 with latty graphite packing and perform -
functional leak test
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WR 138971, Investigate and repair control circuit. for valve 2CA-15A.
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For the above in process maintenance, the team examined procedural f
and drawing compliance, maintenance personnel knowledge.-and
qualifications, operations and verification controls, maintenance and test equipment calibration, and material controls. The work requests associated with the maintenance and testing that.had been ' observed were reviewed upon completion for adherence.to established controls,.
performance of actual maintenance activities,- and effectiveness of process implementation.
The team also reviewed the CA system maintenance history files. and randomly selected completed work requests for further review. The'
following completed work requests were reviewed in detail..for' problem identification, maintenance. action, and appropriate documentation..
'WR 96539 j
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The' team's inspections, observations, and record reviews resulted in i
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Generally, housekeeping and cleanliness. was-average.
Poor.
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housekeeping ~. was identified in one area, the Unit 2 turbine driven - (TD) CA Pump area.
The walls and various aquipment
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effort had been left-in obscure places around the. area.'.There were - full. trash bags and miscellaneous debris, such as empty paint cans, rags, brushes, hoses, and plastic covers found..in.
corners and behind the TD.CA pump housing.. Oil was also' found on the floor behind the' TD CA pump.
These housekeeping issues were discussed with the licensee.and corrected during the course of the inspection. - Additionally, scaffolds were'. observed in-work areas months after the associated work activity-had been completed.
The general ' equipment condition was. considered average. During
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the walkdown inspections the following conditions were observed:
(1) Valve 2CA-116B vias leaking (2) Valve RN-482 was leaking (3) Valve 2RN-69A was identified as deficient because-of a.
packing leak, WR 88765 (4) Handle fell off fire door 601D' when leaving Unit '2' TD CA pump room.
Two of the three valves with apparent leaks were not-tagged as deficiencies. ' Based on the total-number of valves observed during' the walkdown, the three leaking ' valves were not con-sidered to indicate a significant problem. The. handle on fire door 601D was repaired during - the inspection.. The team-did note that the 1icensee had developed _ a system toi measure the leakage from the larger valves-to determine the sev'erity of the
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leak and prioritize valve repairs.
Most of. the in process. maintenance ths.t was observed was
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performed in phases; therefore, only portions of the work '
activities were actually observed. One in process activity was observed through completion,. PT 1/A/4252/01,. a performance
surveillance test for the TD CA pump. The. Performance Group was l
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responsible for coordinating the pump test. The group consisted
of one performance technician stationed 'in the control room. and.
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two performance technicians and the performance. engineer-j stationed locally in the Unit 1 TD CA pump-room.. The, test also
required operations support for system alignment and operational-readiness of the TD pump. The pump performance test (PT) was a:
monthly surveillance (Technical Specification) performed by operating-the pump on full recirculation flow to the Upper Surge
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1 The appropriate test instrumentation was installed locally at-the pump.
Calibration information for, instruments used to perform the above PT was verified by the team.
The test coordinator was well organized' and ' knowledgeable of. possible problens, completion schedule, and ' procedure sequencing.
The Performance Group: effectively ; coordinated the necessary interfaces between Operationsiand Maintenance.
Completed work requests- (WRs) were reviewed for adherence 'to
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controlling procedures, use of appropriate procedures, documen-
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tation of work activity, and_ process adequacy. For the WRs that the. team reviewed, it appeared that the licensee has a good maintenance work request program. The. team noted one area.of concern regarding the WR process, the lack of a Lformal method for voiding WRs. This is further discussed in paragraph 1.j.
c.
Medium-Voltage Switchgear and Motors The Auxiliary Electric Distribution System utilizes 13.8 kV, 6.9 kV and 4.16 kV -switchgear for switching motor and transformer ~ loads.
Approximately 117 circuit breakers - are needed to perform this function at the dual unit site. Medium-voltage switchgear and-motors were chosen for inspection because they perform critical' safety-related functions; are fairly complex from the maintenance viewpoint;
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and would be representative of the licensee's maintenance ' program in the electrical area.
In preparing for the inspection, a computer printout of work requests for the 4.16 kV saiety-related switchgear was reviewede ~The printout showed that only eleven work requests for repair work were initiated-between June 1987 and the time of this inspection; nearly all of these were to correct problemt' of a minor nature not af fecting the ability of the switchgear to perform its' function.
This record-(
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indicates that repetitive failures have not been a problem with the j
switchgear at the site.
The on-site phase of the inspection began 'with a walkdown of six-I switchgear rooms in the turbine and auxiliary buildings which house i
all the 6.9 kV and 4.16 kV switchgear. As far as could be determined from a walkdown type inspection, the condition of'the switchgear was.
good. The rooms were' clean, well illuminated, and large enough.to facilitate breaker maintenance.
Af ter the walkdown, the NRC team questioned! he Transmission Depart-t ment Station Support Engineer and his assistant about the maintenance organization and details of the maintenance performed on the switch-gear and motors.
Maintenance of switchgear 600 volts and above, i
motors 2000 volts and above, as well as other electrical equipment
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is the responsibility of the corporate Transmission Department. Two engineers (the ones interviewed)- from that department work at the site on a full-time basis to coordinate all Transmission Department i
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activities with the Nuclear Production Department. Work crews are furnished by the Transmission Department during refueling mutages to perform preplanned preventive maintenance work or corrective maintenance if necessary. The crews are composed of specialists who
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I have long-term experience with ~one particular type of-equipment.
There is a switchgear crew, a Doble test crew, a motor crew, etc.
Historically, MNP has had 14-month fuel cycles. Each circuit breaker receives a PM and a Doble test every third refueling outage and each motor receives a PM every second refueling outage.
Individual procedure steps were discussed with.the foreman of the.
switchgear crew who came to the site to meet with the NRC team. The program described for the breakers was consistent.with good industry practice, however, the control wiring compartments and the bus:
compartments in the switchgear were not being inspected.. The Nuclear Production Department agreed to include a check of the control wiring compartment in theit program.
The Transmission Department was developing a procedure for inspection of switchgear buses and evaluating additions to the PM program.
The NRC team found the motor PM program acceptable.
It. includes periodic overvoltage testing which is very useful in determining the status of the motor insulation. The overvoltage test being conducted.
is a DC test at 1.7 times rated motor voltage between windings applied for ten minutes.
Representative records, including procedures and data sheets, were reviewed to confirm the above statements, and demonstrated that auditable records have been maintained.
The final step of the inspection -was to discuss the switchgear _ PM program with the Quality Control Supervisor for Electrical-and Civil Work. He stated that all safety-related circuit breakers are checked by a quality control inspector concomitant with : PM work.using a 20-point check list, which was presented to the team for review.
The NRC team concluded that the medium-voltage circuit breakers were well maintained.
This conclusion is supported by the'following:
Specialized crews perform virtually all PM steps considered good
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industry practice.
Breaker failures and problems have been nil.
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Quality control personnel check each circuit breaker.
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Failure to perform inspections of the bus compartments and control wiring within the breaker cubicles was a gap in the program that the licensee was preparing to address. Although the work history for motors wa_s not studied by the team, the motor PM program appears acceptable based on the procedure steps and maintenance interval.
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d.
125 Volt DC Power Systems - Safety-Related The safety-related 125 volt DC power systems consist of the 125 Volt DC and 120 Volt AC Vital Instrumentation and: Control Power System (125 volt DC/120 Volt AC vital I&C power).and four 125 Volt DC diesel generator cortrol power systems.
(Separate non-safety-related 125 volt DC and 250 volt DC systems are used for direct current loads required for power generation.)
Each of. the four emergency diesel generators has' its own ' safety-related 125 Volt DC Control Power System (125 Volt DC DG). The. loads furnished by the 125 Volt DC DG power system. are:
all control relays, starting air solenoid valves, control air solenoid valves, fuel oil booster pump, and initial field voltage (flashing) for the generator.
Each 125 Volt DC DG power system consists of a-battery charger and a
.125 volt. DC nickel cadmium battery.
The battery floats on the bus fully charged and is capable of supplying emergency power for starting the diesel generator.
The 125 Volt DC/120 Volt AC vital I&C Power System is located in the auxiliary building. The system consists of five. battery chargers, four 125 Volt DC batteries, four main distribution centers, molded case circuit breakers, and eight separate panel boards. The-125 Volt DC portion of the system is divided into four independent and redundant load groups (trains).
The 120 Volt AC portion of the system consists of four independent and redundant channels for each unit. Each channel has a 120 Volt AC inverter and associated panel
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boards.
Eech 125 Volt DC train feeds two' channels of 120 Volt AC, o
one to each unit.
Auxiliary Building 125 Volt DC/120 Volt AC Vital I&C Power
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System The team performed a walkdown 'to examine alllthe components for the 125-Volt DC/120 Volt AC Vital I&C Power System. During the walkdown, the team noted that none. of the. molded' case circuit -
breakers had. calibration stickers.
The licensee informed the -
team that the circuit breakers were not being calibrated or tested to verify that the. magnetic' and/or thermal trip units
inside the breaker meet their intended. function. ' ~ (This may be determined by tripping the circuit. breaker to the. open position-l during a fault current.) For.each 125 Volt DC train,! the team
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identified that the Westinghouse type 2A molded case circuit-I breakers. in compartments 1A, 2A, 18.. and ' 2B in distribution I
centers EVDA, EVDB, EVDC and EVDD had an adjustable magnetic-l trip unit and the breakers were hardwired in the compartment.
i (not removable for testing in the shop). The lack of calibra--
tion.or testing of molded case circuit breakers is discussed l
further in paragraph 2.e.
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15 During the-inspection of the 120 Volt AC inverters,1EV1B and 1EVIC, three lock washers were'. found missing from the power connection terminations near the transformer.
Secure termina-tions are required since the inverters (transformers) vibrate at 60 hertz. The licensee initiated work requests (WRs) to perform corrective maintenance for replacing the missing lock washers.
-The-WRs were scheduled to be performed September-23,1989, for IEV1B and August 21, 1989, for IEVIC'during required PM.
The team reviewed the battery testing procedures and observed the performance'of battery testing. During the battery testing,
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the team determined that.the... Instrument and Electrical (IAE)-
technicians' performing the work were very. knowledgeable and had extensive experience with batteries. The. team requested that additional specific gravity tests ~be _taken on randomly selected cells during the weekly. test.
All additional specific. gravity
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readings on all.four batteries were found-to be.within specifi-cation. In addition, the. team reviewed the data from.the last.
quarterly battery tests and found it acceptaMe.
The team reviewed the maintenance work history and the WR list to determine if the licensee had any significant problems I
with the batteries, the chargers, ' the circuit breakers, and i
the 120 volt AC ' vital inverters.
Of the > 38 corrective WRs performed since 1987, no significant problems were identified.
However,120 volt AC inverter IEVIC was damaged when the output capacitors blew out.
This was identified on-WR 131886 dated December 7, 1987. The licensee now has.a PM program to periodi-cally replace these capacitors' for all inverters (and battery.
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chargers).
The team did not identify any weaknesses in the 125 volt DC/120 volt AC vital -.1&C power system except for a lack of testing of molded case circuit breakers.
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The team performed walkdowns for both Unit'_2 emergency diesel:
generator rooms. This inspection was performed to examine the condition of the 125 volt DC battery, battery charger, and the electrical control panel. During the walkdowns, the team did not identify any deficiencies with this equipment.
q The team reviewed the test procedures' for the battery and.
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battery charger and determined that they were satisfactory..The
maintenance work history was reviewed and no significant problems were identified. In regard.to the 125 volt DC battery, the licensee stated it would soon need to be replaced as its end l
of ~ cell life was approaching.
The team determined ~ that the i
licensee's program for the 125 volt - DC DG power system is
satisfactory.
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In general, the licensee has a good maintenance: program for the safety-related 125 volt DC power systems.
However, the failure to test the trip units in the molded: case breakers to verify that they will perform their intended function is considered a significant weakness. This is discussed further in paragraph 2.e.
e.
600. Volt AC Distribution System The-600 Volt-AC Distribution System consists of'.the 600 Volt AC'
Normal Auxiliary Power System and the 600 Volt AC Essential Auxiliary Power System. The 600 Volt AC Normal Auxiliary Power System on:each unit is supplied by twelve 600 Volt load centers.. Each load center-is fed by a 6900/600 Volt, 1500 kVA,. or 2000 kVA load center trans-former. Seven of the load centers on each unit are. assigned to loads-unique to that particular unit, whereas the other five load centers:
on each unit connect to loads common.to both units, such as the.
administration building or machine shop.
The team conducted a walkdown inspection. of: the 600 volt AC system.
An effort was made to examine all system transformers, load centers, and motor control centers for general cleanliness-and material condition. The team also randomly inspected numerous examples of circuit breakers, fuses, and wiring.
Specific equipment inspectec; included 17 motor. control centers, 20 load centers, 4 cabinets of 4160 Volt switchgear and 33 6.9 kV/600 Volt transformers.
In general, system housekeeping was found to be average. The system
. material. condition was considered sati sf actory, although. several minor deficiencies were noted with regard to inoperable indicating lights and improper. deficiency tagging (see paragraph 2.j, for details). Many of these minor deficiencies were corrected during the-inspection.
The material condition was. considered satisfactory to maintain operability of components at a level commensurate with the components' function.
The team conducted a review of system preventive maintenance (PM).
Overall, the PM procedures (PMPs) used were judged to be satisfac-tory. The PMPs were in accordance with general vendor recommenda -
tions for type of maintenance and frequency.
The. team noted that no maintenance requirements existed for testing the functional operability of system molded case circuit breakers except for those to loads inside containment.
This issue is discussed further. in.
paragraph 2.e.
In conjunction with the PM review, the. team conducted a-review'of the 600 Volt AC system component vendor documentation.
During this effort, it was determined that, by procedure, the maximum system-voltage may exceed the maximum rated voltage of-the system circuit breakers.
This item is discussed further in paragraph 2.1.
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The team conducted a review of modification and maintenance work
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histories by reviewing lists consisting of identification numbers and
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brief descriptions, and then performing a detailed review of nine j
modifications and thirty corrective /PM WR packages.
l The team determined that the packages included adequate QA involve-ment and appropriate post-maintenance testing. Release for work and work procedures appeared to be satisfactory.
In progress preventive maintenance on motor control center 2MXN was
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observed by the team.
This PM was performed in accordance with
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periodic test procedure PT 2A435009A.
This is a periodic test of the current overload trip on the circuit breakers for loads in the containment. The team examined procedure and drawing compliance, use i
of knowledgeable and qualified maintenance personnel, sign-offs, use of correct materials, use of calibrated tools, HP coverage, etc.,
and interviewed the personnel involved. The team concluded that the performance of system maintenance is effectively accomplished by skilled maintenance personnel, f.
Instrument Air System The McGuire Instrument Air (VI) System supplies dry, oil free, compressed air to all instrumentation, diaphragm valves, piston t>perated valves and any other equipment requiring it in both units.
The VI System is not safety-related.
However, all VI containment
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isolation valves are safety class 2E.
i Air is taken f rom intakes on the roof of the service building (with l
the exception of the in containment air compressor which recirculates
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containment atmosphere), passed through filters and into the inlet of any of four air compressors.
The air is compressed by a two-stage
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centrifugal air compressor (D) or in any one or more of the three available three-stage reciprocating air compressors (A, B, and C),
cooled,- and then held in three air receivers.
Air dryers are provided for removing moisture from the air.
Recirculated water cools both the compressor cylinder casing and air passing through the intercooler on compressors A, B and C.
On the
centrifugal air compressor D, the recirculated-water cools the
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built-in intercooler, the built-in aftercooler and the oil cooler.
Conventional low pressure service water is used to cool compressed air as it passes through the aftercoolers.
NOTE:
A station modification was being accomplished during this inspection to add two additional (E and F) centrifugal (CENTAC) air compressors with capacity equivalent with the D compressor (1500 scfm).
Prior to completion of this change, the D compressor has been utilized as the base load compressor.
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The A, B and C compressors have three modes of operation:
Base,
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Standby 1, and Standby 2.
.The Base and Standby 1 compressors run continuously while the Standby 2 compressor remains off until a low-low' air receiver pressure is reached.
Under normal operating conditions,.the compressor (s) running the Ba'se mode will handle the entire. plant needs. In periods of heavy demand, the Standby.1 compressor can be expected'to load. Operation. of a'
Standby 2 compressor signifies a system trouble that should be
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investigated.
Motor-operated valves are provided for containment isolation of instrument air ' lines.
Logic from the' Engineered Safety Features Actuation System closes the VI containment isolation valves following.
a LOCA.
There is a continuous release of instrument air into containment due to normal venting of air-operated equipment.
This results in required controlled releases of containment air in order to maintain proper containment pressure.
The compressor system installed in-containment recirculates the air' into the containment instrument air headers, thereby reducing the requirements for controlled releases.
However, the containment compressor system is considered-non-safety-related.
The containment compressor system is composed of a 10 HP compressor, receiver, aftercooler, separator, air dryer and coalescing filter.
Should this system be -insufficient to supply the air needs of
.i containment equipment, the Base instrument air system compressors a
will supplement'the containment instrument air as required.
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The team performed a general walkdown of selected portions of the VI system for both Units 1 and 2.
The major components. examined included the main station air compressors and various safety-related end-use devices (TD AFWP, steam atmospheric reliefs, SW flow control valves for CCW HX, etc.)
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The-team also reviewed documentation, held discussions with cognizant i
licensee personnel 'regarding work histories (especially regarding main station air compressors and dryers) and reviewed the licensee'.s
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May 8,1989, response to NRC Generic Letter (GL) 88-14 on instru-l ment air and the background documentation associated with Unit 1 l
LER 88-36.
The general condition of components examined was observed to be good.
However, the team noted the following:
Safety relief valve IVI-6 on Worthington-VI station compressor C l
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was missing a handla and assorted parts and. no discrepant condition tag was found on the valve.
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Pressure gages PG5070, 5060, and 5046 located between valves.
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IVI1248, 1249 and 1250 were incorrectly labeled and filter.
regulators were not. individually identified.
In addition, permanent " highly visible" labels. were affixed to. VI valves listed as Category A (accident mitigation) in the response to GL 88-14 without coordination with the present three phase McGuire Nuclear Station labeling program to upgrade plant labeling.
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Discrepancies were identified in design - drawings for-Air Operated Valves (A0Vs) INC-56 (master. valve lists indicate'
-MC 1553.20 when valve is actually listed on MC 1553.2.1),
2RN-216 and 2RN-213 (failure position not shown on MC 2574.3).
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Inaccuracies were identified in the licensee's May 5, 1989,-
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response to' GL 88-14 and corrective actions stated in Unit I LER 88-36 on the VI/VG cross tie station blackout header. The team's concern regarding accuracy 'of information furnished to the NRC is further discussed in paragraph 2.a.
The team's review of historical data (the last two years of WRs.
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on D VI compressor and A, B, C, and D VI dryers) indicated a problem with entering equipment failure cause codes in Section V of the work request.
Further discussion of this. matter is included in paragraph 2.d.
The team concluded that licensee actions regarding preventive 'and corrective maintenance on the VI System were. a. strength in the l
maintenance program and implementation.
However,.the team's consensus was that the concerns listed above, associated with the VI system, should be highlighted because of ' their potential ~ to.be generic.
g.
Maintenance Work Observations-i In addition to the work observations detailed in paragraphs 1.a.
through 1.f.
above, the team observed the following in process maintenance:
Instrumentation and Electrical PMs i
The team _ observed the following ongoing work:
WR No.
Description i
01452A PM - Test Circuitry of Steam Generator Sample Monitor
.099757 PM Test Reactor Protection System Channel.'4
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Functions, Unit 1 l
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WR No.
Description 099758 PM - Functional Test on SSPS Train B, Unit 2 095992 PM - Test Trip Functions of Circuit Breakers on Motor Control Center 2MXN 098085 PM - Test Diesel Generator Speed Switch The team observed portions of the work performed, examined the work package documentation, and interviewed the personnel involved.
Specific areas verified included authorizations received; documenta-tion issued and approved; following of procedures; use of qualified test equipment and tools; use of correct parts and materials; resolu-tion of discrepancies when encountered; adequacy of management oversight of the work; personnel qualifications; and ALARA work packages. The following observations were made:
o Work packages were complete and generally well organized.
o Procedures included step-by-step instruction to guide the workmen through the work package, and QC hold points for signatures.
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Drawings and Facility Change Requests were up to date.
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o Procedures used were controlled and held in the IAE shop libra ry.
Copies were obtained and verified for accuracy just prior to starting the job.
Work procedure instructions were augmented by QC hold points for o
tightening fasteners.
o Instruments and tools used were in good condition, readily available, and properly calibrated (if required).
o Personnel were familiar with the procedures and the systems being worked on. They generally understood the effect each step would have on the system.
Throughout the performance of these tasks, the team was favorably impressed by the morale and experience level displayed by the personnel involved.
There was good communication between the maintenance and operations group.
None of the jobs witnessed were delayed by problems of material availability, QC involvement, or conflicting activities. There were no problems identified during the observation of the above tasks.
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Test Connections for Unit 1 AFW Pump Recirculation Valves The team observed completion of fill pass welding on CA System weld CAIFW7-7 which was being performed as part of a minor piping modification specified by Station Variation No. ME-VN-1860. Work was controlled by procedures MP/0/A/7650/52, MD/D/B/7650/09 and welding procedure specification L-255-4.
The team observed that personnel were competent and qualified,' procedures were adequate and followed, and documentation was completed.
Replacement of Temperature Switches on Unit 2A Diesel Generator The team observed the replacement, calibration, and functional verification of diesel generator temperature switch 2KDTS5320 (outlet water low temperature alarm) in accordance with WR No. 96281.
Calibration was per procedure IP/0/B/321/06. The team observed that personnel were competent and qualified,. procedures were followed, and all necessary documentation was accurately completed.
Corrective Maintenance on Unit 2 Atmospheric Steam Dump Valve 2SV-40 The team observed completion of work associated with the installation of a new signal line for air-operated steam dump valve 2SV40. This was performed on WR 501186. The team observed that personnel were competent and qualified.
(One IAE technician was involved with on-the-job training (DJT) during this task. The other IAE technician was fully certified and providing the OJT.) Procedures were followed and documentation was accurately completed.
Corrective Maintenance on IC3 Heater Drain Tank Pump Impellers
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The licensee had completed corrective mainter,ance (replacement of rotating elements, i.e., pump shaft and eight stages of impellers)
under WR No. 502099.
WR 50215 was issued during this inspection for rebuilding (weld repair and machining) and rebalancing of the rotating clements (identified as DP-3) removed under WR 502099.
Rebalancing required fabrication and balancing of a special mandrel
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for the impellers involved.
Balancing operations are normally completed by highly skilled technicians using bench test equipment without formal procedures or instructions (except test bench vendor information).
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The team surveyed an overview demonstration of balancing activities associated with the eighth stage impell er..
Licensee personnel
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demonstrated that the mandrel was balanced to 0.5 mils and the
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mandrel / impeller combination exhibited a static unbalance at 1727 rpm of 0.704 mils at 178 on the exhaust side of the impeller and 0.704 mils at 337 - 340' on the inlet side. This unbalance indicated a need for removal of approximately 15 grams of impeller material from the inlet side by manually grinding with an objective of no more
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than 0.5 mils total vibration after balancing..The team noted that a high level of technical competence was demonstrated by the licensee's balancing technicians and there was no apparent need for a more formalized balancing procedure.
Further, accurate documentation was completed.
Corrective Maintenance on Unit 2 Steam Generator Wet Layup Motor-Operated Valve 2BW-13 The team observed activities associated with. completing a.new bonnet-to-body seal weld on the subject valve (WR 138442). This bi-metallic weld (stainless bonnet to carbon steel body) was completed by quali-fied personnel in conformance to welding procedure specification L-264-2 (manual gas tungsten arc) using ER309 (bare stainless steel)
filler metal.
During observation of the welding activities. the team noted one welding related discrepancy and two non-welding discrepancies as follows:
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Welding related - The team noted that a full size. compressed gas (argon) bottle being used for nearby welding activities was not " adequately secured" as required by the welding program manual and ANSI 249.1, Safety in Welding and Cutting. Welding management personnel took immediate action to. correct the discrepancy and prevent recurrence (June 23, 1989, internal McGuire memorandum from G. Holbrooks to R. Rider). NRC concern was minimized due to the team's general observations of an aggressive and competent safety organization as furt.her dis-cussed in paragraph 3.b.(3).
Non-welding related - The team also noted a missing pipe support (rod hanger) near safety injection valve 2NI-808. However, NRC concern was minimized since valve 2NI-808 isolates the safety injection system from the class H (non-safety related) 1/2 inch test header fill piping which the missing hanger supported. WR No. 502255 was issued to replace the missing hanger.
The final discrepancy noted by the team was a damaged needle on pressure gage 2MNVPG5490 -(mixed bed. demineralized upstream pressure). WR No. 502252 was issued to correct this problem.
Other discrepant equipment conditions identified by the team are further discussed in paragraph 2.J.
Valve Repacking Work Observation The team witnessed the repacking of two gate valves, 2CA-25 and 1RF-7, in the auxiliary feedwater system and the fire water system,'
respectively. Both jobs were completed to procedure MP/0/A/7600/13
"Aloyco and Walworth Gate Valves With Flanged Bonnet-Body Fi t,-
Corrective Maintenance."
The team. observed licensee maintenance personnel remove the valve actuators, remove the defective packing,
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and insert the new packing. The team concluded that the maintenance-personnel were well trained, competent, and knowledgeable.
Further, the team found that the procedure for repacking the subject valves was adhered to, adequate, and the required documentation was completed.
Vibration Measurement Work Observation The team witnes:ed vibration measurement work on diesel generator 2A fuel boost pump, fuel transfer pump, the diesel. engine itself, and -
its turbocharger.
This work was considered to be preventative maintenance, and was performed to procedure MP/0/A/7300/01 " Rotating ;
Equipment-Preventative Maintenance." _ Vibration measurements were taken at a number of locations on each piece of equipment, while the equipment was in normal operation.
The team determined that measurement equipment was in calibration, the personnel performing vibration measurements were qualified, the procedure was adequate,'
and the procedure was adhered to.
The team observed that a high level of expertise was shown by the technicians. and engineers involved in the vibration measurement program, and the excellent equipment provided for these measurements was. indicative of a strong commitment by the licensee to monitor and trend the condition of rotating equipment.
PM on Unit 2 Containment Hydrogen Analyzer System The team observed. routine preventive maintenance on the Unit 2 Containment Hydrogen Analyzer System, Train A.
Work was controlled by WR 01241A and Procedure IP/0/A/3250/39.
The functional test and
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I calibration on the WR was accomplished in about seven hours, which was close to the time estimated by the planners. Proper clearances'
were obtained from the Operations Department and the maintenance workers coordinated and communicated with control room personnel as required by the procedure.
Work ' progressed smoothly,. the system performed as expected and the recorded data was within the specified acceptance criteria. The team questioned why one of the data points did not have an associated acceptance criterion..The manufacturer's instruction book was obtained from the document control personnel, but it did not address the specific question.
The maintenance.
engineer contacted the equipment manufacturer who stated that the data point in question could be recorded for information only, and.
there was no associated acceptance criteria.
This evolution-demonstrated the.following:
(1) Manufacturer's instruction books are controlled and readily.
available, (2) The engineering support group fulfilled 'its role by quickly resolving a question that arose during ongoing maintenance work.
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i Finally, the qualification records of the lead worker was verified by j
the team.
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Material Control The team inspected the licensee's material control program and its
support of the maintenance process.
A general inspection of the l
warehouses, receiving and storage areas was conducted to evaluate the storage conditions and facilities. The overall condition of the warehouse areas was very gnod, except for some uncapped stainless steel pipe in the outside QA storage area-(Yard E).
The team reviewed the shelf life program. The program was estab-lished prior to plant licensing for items that were assumed to require a limited shelf life.
The Technical Support Groun was originally responsible for determining shelf life. The determination was based on engineering judgement and vendor interfaces; however, the evaluation was not documented. The team discussed this omission with the licensee and determined that the draft revision to the shelf life procedure, Material Handling Procedure MHP 3.2, Shelf Life Program, Revision 1, will require this documentation when imple-mented. The draft procedure incorporates a new industry initiative, EPRI NP-Q101-10 (NCIG-10), " Guidelines for Maximizing the Shelf Life Capability of Limited Life Items." The team did note that previous shelf life periods appeared conservative compared to the EPRI document. The shelf life program was implemented by the Planning Section (Material Group) who are responsible for tracking, updating, removing, and reordering limited life items.
The bar code issuing system, in conjunction with, the Materials General Supervisor monthly review of the "End of Life Report," were used to identify items approaching shelf life expiration.
The team also inspected the licensee's material control program with respect to commercial grade procurement.
The commercial grade evaluations for corresponding equipment were _ performed by Design Engineering (corporate) per request, " Commercial Grade Request", from site personnel-.
Technical evaluations were performed for each intended application of a new commercial grade item.
It appeared that commercial grade items are evaluated for their intended applica-tion prior to installation.
The licensee also stated that on-site certification (upgrading) is generally discouraged and only used as a final resort.
The team reviewed documentation for eleven commercial grade procurement transactions for technical adequacy, and
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appropriate qualification.
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For the documentation reviewed, the engineering basis for the i
procurement and intended end use application appeared to thoroughly address the commercial grade item's critical characteristics.
The
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commercial grade evaluations restricted usace for each item to one of the fcllowing category applications:
(1) CG 1 - Direct replacement spare parts only (2) CG 2 - General application / no restrictions (3) CG 3 - Must be evaluated for each application other than direct replacement (ie. NSM, modification)
(4) Nci commercial grade items only purchased from QA approved vendor (ststement used for items not approved as CGIs)
The team identified one programmatic weakness; the licensee does not verify that item critical characteristics are part of the item acceptance process.
The licensee stated that item acceptance consists of only receipt inspection (verification of the manufac-turer's part number).
Random reviews are also performed to compare new catalog descriptions and information to previous vendor infor-mation for commercial grade items.
The current program does not require the reviews to be documented or scheduled at any frequency.
However, the licensee has committed thru NUMARC, to modify the existing program by implementing EPRI NP-5652, " Guideline for the Utilization of Commercial Grade Items in Nuclear Safety Related Application," by January 1990.
This document provides considerable guidance for acceptance methods used to verify critical characteris-tics of commercial grade items.
Adequate implementation of this acceptance methodology should address the team's concerns regarding this issue.
The licensee has established an effective and efficient material control system, with the exception of the shelf life evaluation concern rad the item acceptance weakness. The team was particularly
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impressed with the licensee's use of bar coding for issuing material
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and the movable storage tracks in Warehouse 3.
It.was evident that licensee management supports the material control program. -Based on the team's review, material control at McGuire was strong. program-
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matically, well implemented and a significant enhancement to the
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maintenance process.
I 1.
Health Physics The team assessed the extent to which radiological controls were j
integrated into the maintenance process. This included a review of procedures listed in Appendix 3; observation of work in progress; discussions with licensee personnel; and a review of documents used
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to support the program such as ALARA reports, radiatiri work permits
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(RWPs), personnel contamination reports, etc.
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Health Physics (HP) involvement in planning and preparation, as it relates to support of maintenance work was reviewed by the team and found to be adequate.
An HP. representative attended and was involved in planning meetings held twice weekly.
The team noted that the HP staff logged considerably more overtime than any other group onsite and approximately five times the overtime of maintenance for this quarter.
However, this was not currently impacting the availability or quality of radiation protection coverage for daily maintenance activities. Planned HP technician staff augmentation for the upcoming Unit 2 outage appeared adequate.
Aspects of the licensee's training program, specifically the General Employee Trainint (GET), was reviewed by the team. Through lesson plan reviews, trainer interviews, and observation of a training-video, GET was found to be above average. The GET trainer inter-viewed was enthusiastic and genuinely concerned with the quality of the program. Of special note was the use of a video entitled
"HP Moment" in which current radiological incidents in the industry were discussed along with tips to prevent the repetition of such incidents.
The team determined that a good line of communication existed between the training staff and plant HP.
Repetitive poor work practices identified by plant HP were routinely fed back to training personnel who then added emphasis'to the applicable area of the GET lesson plan.
Internal / external dose control activities associated with maintenance work within the radiation control area (RCA) were observed.
RWPs related to selected WRs listed in Appendix 4 were found to contain appropriate intenal and external dose control requirements for the job (s) being covered by the RWP.
Independent general area surveys by the teau verified that postings and access controls were commensurate with observed radiation levels.
The licensee recently installed a state-of-the art stand-up whole body " quick" counter.
Licensee representatives stated that a Technical Performance Test to assess performance criteria such as detection sensitivity and isotopic resolution, had been performed on an identical counter at a sister facility prior to use of the counter at McGuire.
The team reviewed results of periodic interstation cross-checks performed on the stand up counter using blind phantoms supplied by corporate HP.
Internal / external dose controls for daily maintenance activities were adequate.
The licensee's contamination control program was good as evidenced by the low square footage within the RCA which is controlled as contaminated. At the time of the inspection less than 7 percent of'
the 105,000 square feet within the RCA was considered contaminated.
Through review of personnel contamination data for 1989, the team determined that the number of maintenance workers involved in contamination events was appropriate considering the amount of work performed in the RCA.
During tours of the facility, the team observed tags associated with catch containments in use to control
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leaks on plant equipment and piping. Licensee representatives stated that installation and removal of catch - containments' are _ formally tracked to ensure that the containments are routinely checked at an appropriate frequency. The station also has an initiative to reduce the number of catch containments in use, with a goal of 115 active -
containments by-the end of 1989. As of the. end of April 1989, - the'
plant had'131' active catch containments compared to 250 for the same time last year.
Through independent smear surveys of numerous items stored in the hot tool room, the team verified that no tool surveyed contained smearable contamination. greater than the administrative guidelines for items in that area.
The licensee's program for maintaining exposures as low as reasonably achievable (ALARA) was reviewed.
The' program was found to contain-aspects for the identification of maintenance activities which contributed large fractions-to the station's collective dose.
For some of these identified activities, dose mitigation had = been implemented.
These included removal of resistance temperature detectors (RTD) manifolds, use of multi-stud tensioners on removal and replacement of S/G manways, and installation of additional lead shielding on the reactor head stand. Attempts to reduce. dose for high dose jobs is critical to an ALARA program; however, other dose-reduction techniques 'should also be utilized. During review of some
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of these other program aspects, weaknesses were identified and are discussed in paragraph 2.f.
Licensee representatives were informed of an NRC concern regarding the individuals allowed to exit the site after alarming the exit portal monitor on June 4,1989.
The alarms were' determined to be caused by electronic malfunctions.
Onsite followup of the incident by an NRC radiation specialist did notLidentify any public health and safety issues.
Possible compliance issues related to the incident will be detailed in a future NRC radiation protection inspection report. In the interim, NRC concern will be identified as Unresolved Item (URI) 50-369,370/89-15-02, Adequate Licensee - Response to Exit'
Portal Monitor Alarms.
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Work Management l
l The team examined the area of work management to assess the adequacy i
l and effectiveness of the licensee in controlling maintenance activi-i l
ties. Special emphasis was given to the areas of~ work order. control, i
job planning, and work scheduling.
The team reviewed the work order' control program to assure that all
relevant information was available and that adequate controls' were
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provided.
The inspectors reviewed procedures (see Appendix 3),.
conducted interviews _ with licensee personnel,' and reviewed work in progress (see paragraphs 1.a through 1.g).
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'28 The team found that the work order control' program was adequately proceduralized and implemented.
The McGuire. work request form allowed for - an adequate description of. the deficiency and for supporting information. The procedure.for processing emergency and non-emergency work requests allows for an appropriate amount of review prior to beginning work.-
Adequate control of equipment affecting operations is maintained._ Required technical reviews - of work performed are - being : accomplished in a' timely manner. However the team noted the lack of.a formal method for voiding WRs. Defi-ciency tags were found on equipm'ent components after' the referenced WR had been voided (not approved for work), and consequently did not exist. Therefore, new deficiencies. could go unreported because :the equipment was previously tagged as a deficiency, but the associating WR did not exist. The team considers this a weakness in the WR program.
In reviewing job planning, the team.found that'the work planners have primary responsibility for incorporating in the work request package-the information needed to do the job..While no formal training exists for the work planners, experienced : maintenance. personnel, including maintenance supervision, are normally used as planners.
Planners receive several months of on-the-job training prior to becoming a planner. The licensee is-developing a formal -procedure that will delineate how jobs are to be planned.
During the work planning process, planners are not required to visit
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the job site, although this is routinely done.
Also, planners will plan a job for inside the radiation controlled area only after Health Physics personnel have reviewed the work request for exposure controls..There is a planner on site at all times so.that emergency work requests will be properly planned and processed on an immediate basis. Two instances where job planning appeared to be inadequate are identified in paragraph 1 a.
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To determine the extent to which work scheduling enhan%s the main-tenance process, the team examined. work orders, schsdules, and work assignments.
Overall, the maintenance scheduling function appeared to be performed well.
The planning shif t ' schedulers have the
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responsibility for conducting the proposed shift schedule meetings on
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Tuesday and Friday.
The purpose of these meetings is to:
Make necessary changes to the existing schedule,
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i Develop the proposed schedule.
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Identify work requests for shift work.
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Prioritize the work requests placed on the shift schedule taking
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into account the completion date, availability of plant equip-ment, plant conditions, etc.
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These meetings are attended by planners and representatives from Operations, Health Physics, Chemistry, Quality Assurance, Instru-l
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mentation and Electrical, Mechanical Maintenance, and the Shift Engineer. Schedules are approved for the 7-day period from Wednesday to the. following Tuesday and Saturday to the following Friday.
Emergency work requests may be inserted onto the shift schedule by the Shift Engineer as they occur.
Planners originate the work schedule daily. They are also responsi-ble for tracking work status daily.
Planners review completed work request packages and determine the cause of delays for those work requests needing to be rescheduled.
In general, prioritization of work is satisfactory.
The team found no maintenance problems that directly resulted from a lack of proper prioritization.
However, the team considers that prioritization efforts could be improved for maintenance classified 'as " routine."
All maintenance work is prioritized either as emergency, routine, or outage. Within the " routine" classification, more specific formal requirements could be used to prioritize work. Risk significance in prioritizing work is further discussed in paragraph 1.u.
k.
Engineering Support for Maintenance-The licensee's principal sources of engineering support for mainte-nance lie in design expertise provided by their large off-site Design Engineering Department and in onsite System Experts (SEs).
The SE functions are very similar to System Engineering concepts specified by INPO. The SEs have individually assigned responsibilities for maximizing reliability, availability, and performance of designated
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system (s), component (s), or program. The majority of the SEs are
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assigned to the plant Maintenance Engineering Support organization j
that is part of the Maintenance organization.
However, there are also SEs in other plant organizations such as IAE and Operations and Performance.
The license has 31 SEs, Licensee personnel stated that the SE program had been in effect less than 6 months but that many of their functions were accomplished previously by the same individuals, who were then generally reporting to IAE or Mechanical Maintenance.
Other limited engineering support for maintenance is providrJ through a smali number of non-SE maintenance engineers and by Project Services engineers who coordinate some maintenance-related mod"fications.
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The team evaluated the licensee's engineering support for maintenance
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generally in their observations and reviews of maintenance.and by I
specifically assessing the adequacy of. support provided relative to three areas - RN HX performance, check valves and KC HX control valves RN89 and RN190.
With regard to the SEs, the team also discussed the SE program with the responsible coordinator and l
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reviewedi the associated.' Station Directive (SD 2.0.13), training.
materials (Orientation' Training _ dated May 1989) _and the First Quarter 1989 SE Program Status Report.
The team's assessment of engineering support provided 'to RN HXs, check valves and the KC HX control valves was as follows:
RN HX performance The team assessed the licensee's actions to assure satisfactory RN HX performance as described in 1.a above..In that assessment.
- the team ' interfaced with the RN SE in reviewing data obtained in monitoring HX performance and examined the' design engineering determination of HX performance acceptance criteria. The team found that good engineering support had been provided.
Check Valves Concerns regarding check valves in nuclear plants have been documented in' various industry and regulatory documents, princi-'
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pal 'of which are INP0 SOER (Significant Operating Event. Report)
86-03 (issued in 1986) and EPRI Report NP-5479 (issued January -
1988).
The team assessed both design engineering support and.
maintenance ' engineer / System Expert involvement.in. responding to these documents by discussions: with the involved engineering personnel; review of several related WRs on check valve pre-ventive maintenance' (e.g.,- WR 096323); review of modification requests for check valves (NSM MG-12182 Rev. O and -01743, Rev. 0); review of Station Problem Reports (MG-PR-0129 and 2318)
involving check valves and review of reports of McGuire Design-Study' (MGDS) - 0073 which responded to the' SOER and identified check valves with potential service problems.- The team found that design and maintenance engineering' support to address the check valve concerns was adequate and appropriate valve's were
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being identified' and corrected. The only apparent weaknesses noted were the absence of specific. inspection criteria:(e.g.,
dimensions to be measured and recorded) and a failure to compile quantified wear and degradation data to aide in' determinations of preventive maintenance frequency.
Current licensee plans-were for frequent reexamination of valves that had shown:
degradation.
KC HX Control Valves RN89 and RN190 l
In reviewing an. RN System WR' list for the past two years, the-l
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team noted a high frequency of repairs on the subject valves'.
'l Subsequent review of some' of the involved WRs found that the
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valves frequently would not close properly;- thereby making
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maintenance on: the associated HXs difficult.
Various other i
failures of the valves were also noted.
One of the more'
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significant was the failure of air lines to a valve actuator-making the Olve. inoperable - this was reported. in Licensee Event Report 38-043. dated January 17, 1989. The team concluded that good engineering support would have recognized and.
l addressed : the need for frequent repair of these valves. The team verified that the. problem had been' recognized and that replacement of.the' valves had been requested via Nuclear Station Modification Requests (Requests NSM MG-12243 Rev. O and - 22243 Rev. 0).
Replacement, if made, will not be completed for some.
i months or years. The team found that the licensee had increased,
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PM activities to assure these valves remained operable. The.
team witnessed a portion of one of these activities, replacement.
of air lines,. as described..in 2.a above.
Based on their discussions and review for this valve the team'found that recent engineering actions for. these valves appeared adequate. How-ever, discussions with cognizant licensee' personnel established that long-standing problems' have existed associated with the:
KC HX control valves.
In questioning as. to how the repeated.
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failure ' problem with these valves had been identified, the responsible maintenance enginee'r ~ informed the team that it had not been recognized through any engineering evaluation, but was rather. pointed ' out by maintenance technicians.
Therefore, it also appeared that there was a past weakness in engineering support, as the problems should have. been recognized - and corrected more promptly.
Overall, the team concluded that the licensee had a good program of engineering support for maintenance, and that current implementation appeared generally good, though improvement might be needed to aide in assurin.g prompt identification and correction of deficiencies evident from failure trends.
1.
QA/QC Involvement in Maintenance The team examined QA/QC involvement in r.Aintenance by observing QC involvement in maintenance activities detailed in paragraphs l'.a through 1.g above, reviewing completed WRs, reviewing completed QA surveillance and audits, interviewing QA/QC personnel, and reviewing control procedures.
Site QA/QC is headed by the QA Director - Operations,-who reports to the Corporate QA Manager. The site organization consists of 83 people, 30 in' QA and 53 in QC. The QA organization is divided.into Employee Relations, QA Verification, and Technical Support sections.
Relative.. to maintenance, QA. Technical Support' is ' responsible for the review of maintenance proceduresLfor hold' points; review of WRs to determine if QC 'is required; review of completed WPs; ' review and approval of material documentation; and coordination of receiving inspection (RI) including review and approval of RI documentation.
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The QA Verification section is responsible for performing surveil-lances or audits of maintenance activities.
All QA surveillance personnel have completed 37 weeks of Basic Nuclear Operations training and 9 weeks of Systems training. In addition to site audits (surveillance) performed by site QA, corporate QA also audits maintenance.
The QC organization is divided into NDE, Nuclear Welding / Receiving, Nuclear Mechat.ical, and Nuclear Civil / Electrical sections.
These sections provide QC coverage and inspection of maintenance activities.
The team reviewed the QA/QC procedures listed in Appendix 3.
These procedures provide comprehensive details of QA/QC requirements for audit, surveillance, ard inspection of maintenance activities.
In addition to the procedures listed, the licensee's QC and Nondestruc-tive Examination manuals contain numerous procedures for inspection of individual maintenance activities.
The following surveillance, tour surveillance, and audits were reviewed by the team:
Audit (Surveillance)
Number Date Subject MC-89-5 1/30 - 2/10/89 Preventive Maintenance MC-89-8 2/17 - 3/9/89 In-Process Activities MC-88-2 1/4 - 2/5/88 In-Process Activities MC-88-51 10/26 - 11/18/88 In-Process Activities MC-88-13 2/24 - 3/8/88 In-Process Activities T880914 9/14/88 IAE Activities T881114 11/14/88 IAE Activities MT880412 4/12/89 Feedwater Hanger Damage MT890425 4/25-26/89 Maintenance Activities NP-88-03(MC)
1/11 - 2/5/88 Maintenance and Onsite Trans-missions Activities NP-89-10(MC)
4/3-19/89 Maintenance and Onsite Trans-missions Activities i
The audits / surveillance appeared to be well planned and implemented with substantive findings indicating a strong well qualified audit organization.
Corrective action appe:ared to be appropriate and
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timely. The team did note that the response process for surveillance findings (unless escalated to PIR status) was rather informal and the i
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individual auditor must ensure that corrective actions are completed.
This did not appear to subtract from the' effectiveness of the surveillance.
The site QA organization has extensive computer j
programs for tracking findings and ensuring proper closecut.
No
problems were identified with lack of or untimely response to
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findings.
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The site QA/QC organization appeared to be adequately staffed and well trained. The organization was heavily involved in the mainte-nance process and appeared to contribute to the success. of plant maintenance.
Overall, QA/QC was considered a strength in the maintenance process.
m.
Historic Data Related To Maintenance The team examined historical data for indications of the adequacy of the licensee's maintenance and maintenance-related' activities. The data used included NRC Office of Analysis and Evaluation of Operating Data (AEOD) Performance Indicators published in NRC Report NUREG-1272 (June 1988), NRC internally distributed AEOD performance indicator data for 1988, and Licensed Operating Reactor Status Summary Report Data published in NRC Reports NUREG-0020 (January 1987, 1988 and 1989, and June 1989).
Overall, the team concluded that the his-torical data provided evidence that McGuire maintenance had been sufficient to support average operational performance.
Apparent areas of both strength and weakness were noted.
From a positive standpoint, McGuire showed better than (industry)
average availability and forced outage rates during 1987 and 1988 with an apparently improving trend.
In 1986, both their forced outage rate and their availability had been worse'than the industry average. Consistently worse than average performance was noted in safety system failures and collective radiation exposure. Taking all of the data into account, both negative and positive, the team judged
McGuire's overall performance was average, as stated previously.
ll n.
Response to Industry Issues The purpose of a " response to industry issues" program is to prevent or lessen the consequences of future incidents through an exchange of
operating experience information. The NRC, INPO, vendors, and member
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utilities distribute this information to identify problems, potential problems, and operating incidents that need to be evaluated for nuclear safety and reliability.
The team. inspected the licensee's response to industry issues through a review of related programmatic
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requirements described in Directive No. 4.8.1(s), Operating Experi-i ence Program (OEP) Description; in addition, NRC Information Notices (ins), vendor information letters (VILs), and the licensee response to an INPO report were examined.
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The team inspected the licensee's computer tracking system for operating experience actions to determine the versatility, informa-tion contained, and how well the program worked to perform its I
intended function.
The licensee was requested to provide the following DEP lists for the team's review:
i NRC ins (open and closed) since October 1988. Total of 103.
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NRC ins. (closed) from October 1987 to October 1988.
Total of 49.
VILs (open and closed) since October 1988.
Total of 76.
VILs (closed) from October 1987 to October 1988. Total of 52.
VILs (closed) prior to October 1987.
Total of 107.
Comprehensive list of the last 100 open items including ins, VILs, PIRs, SERs, reports, etc.
The comprehensive list of the last 100 open items contained 10 items that were past due for the 15-day grace period.
In addition, eight items were overdue and required escalation letters.
One. NRC IN, 89-21, was not in the tracking system. However, the team determined the licensee's tracking system works very well and performs its intended function.
The team examined OEP work packages for five VILs, one IN and one 10 CFR 21 notification and determined they were satisfactorily implemented in a timely manner.
The team concluded that the licensee had a good program.
The computer tracking system worked well. The implementation of reviewed documentation was satisfactory.
The licensee responded to most industry issues; however, not all items were performed in a timely manner.
o.
Backlog Control The team reviewed licensee records, work requests (WRs), schedules, and plans, and held discussions with the maintenance m: nager to determine the extent and control of the maintenance oacklog.
Specific areas examined included deferred plant maintenance, priori-tization, measuring of backlog, balance of plant concerns, and present backlog.
The team found that the licensee had a large number of non outage
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work requests more than 3 months old. This backlog totaled about 934-jobs.
There were efforts to monitor and reduce this number, but no controls existed to assure timely resolution of delay-causing problems.
For example, at the time of the inspection, 5 percent of the overall maintenance non-outage WRs were waiting for part order requisitions to be written. Almost half of these had been waiting for more than 30 days. Prompt writing of requisitions would aid in minimizing the time that a WR would wait due to lack of parts. This is one area where increased emphasis on timely action (i.e., writing part order requisitions) would have a positive effect on reducing the maintenance work backlog.
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The licensee set a year-end goal of a maximum of 400 WRs on plant-related equipment that are more than 3 months old, of which no more than 50 will be more than 1 year old.
At the time of the inspection, approximately 606 non-outage corrective WRs on plant-related equipment were outstanding for more than 3 months and approximately-193 - had been ' outstanding for. more than l year.
A special project had been initiated to make personnel-aware of the need to reduce the: number of WRs that were more than one year old.
One planning coordinator and two engir,eers had been made responsible for reviewing these WRs to -determine how delays can be reduced. for each item. The tecm found that there appeared to have been only limited progress. Many of the outstanding WRs more than one year old were for work on safety-related systems such. as. component _ cooling water, diesel generator starting air, diesel generator fuel oil, chilled water, and control room HVAC.
The team noted that several reports were generated to monitor the WR backlog. The licensee has established a monthly. report with defined goals and graphical representation of the status of goal achievement.
Another report showed specific data on outage, non-outage, correc-tive, and preventive maintenance backlogs. There also were reports that list the WRs ' awaiting parts on order, awaiting part order requisitions to be written, and awaiting critical parts on order (for equipment that affects plant production). ' The-team noted that -
"Pending" memoranda are sent biweekly to personnel responsible for-
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some action to assist in eliminating the delay of each outstanding-WR. However, no guidance is given - as to when the action should be completed.
The licensee has established an adequate program to identify and monitor the maintenance work backlog.
Based on the size of the-current backlog and on the slow. downward trend over the past 12 months in the size of the backlog, the ongoing efforts to reduce the
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backlog should receive special-attention by-plant management..These efforts will need to be significantly intensified to attain the stated year-end goal.
p.
Post-Maintenance Testing The post-maintenance _ testing program at McGuire consists of a-functional verification program and a retest' program. ~ The functional j
verification program is described in Maintenance Management Procedure (MMP) 1.6, Maintenance Activities Associated With Functional Verifi-cation.
MMP 1.6. describes the Maintenance Group's role in the Functional Verification ' Program.
It.does not address the retest
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program which is described in Station Directive 3.2.2, Identifying and Performing Plant Retesting.
MMP 1.6.. defines functional-verifi-cation as
"a. check to ensure that the requested maintenance was i
performed and that the subject equipment performs all of its intended functions and/or has been properly returned to service"; and retest
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as " formal performance of all or portions of Preoperational or Periodic Tests to verify the component or system meets applicable acceptance criteria and/or Technical Specification. requirements."-
MMP 1.6 gives guidance to be used by maintenance planners in determining appropriate post-maintenance functional testing.
Station Directive 3.2.2 establishes retest requirements. It includes a listing of necessary post-maintenance retests which components must receive per Technical Specifications, Codes, NRC commitments,'etc.
The team's examination of post-maintenance testing included a review of controlling procedures and analysis of post-maintenance test data included in the WRs listed in Appendix 4.
The team's general consensus was that post-maintenance testing was a well documented, proceduralized and controlled program (see paragraph 3.c.(1)).
However, during review of completed WRs the team did identify some deficiencies in this area as further discussed in paragraph 2.h.
The team also examined some aspects of post-maintenance testing associated with the replacement / repair of ASME Code components.
The team noted that an out of-date (1981) revision of Station Directive 3.3.4 had not been revised to include the licensee's latest philosophy regarding exemption from code ' hydrostatic test require-ments as exhibited by the November 30, 1988, issue (Revision 0) of the Duke Power Company ASME Section XI Manual.
Cognizant licensee personnel informed the team that Station Directive 3.3.4 was one of several which were presently under consideration for removal from the Station Directives Manual to the Maintenance Manual.
In any case, the guidance included in the ASME Section XI Manual will be incorporated.
q.
Maintenance Trending l
Previous to this inspection, the team reviewed NRC Report 369,370/88-31
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and noted concern regarding the lack of an integrated program to i
trend equipment problems or failures (IFI 369,370/88-31-10). A major corrective action by the licensee in response to those concerns was the recent implementation of MMP 3.3, Equipment Trending and Failure Analysis Program.
This program is used to detect equipment failure trends and to'
evaluate historical maintenance data based on these trends for J
effecting changes in maintenance activities and changes in plant l
equipment applications.
Anticipated corrections include either improvements in maintenance practices or replacement of equipment or both. This includes modification of PM frequencies or procedures',
addition or deletion of equipment from the PM program, or identifica-tion of training deficiencies.
Improper equipment application or design may also be identified during the review process.
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A manual review of equipment history is completed to accurately determine the appropriate action after a trend of abnormal failures on work requests is detected.
The equipment trending and failure analysis program is composed of six basic steps as follows:
(1) WRs of equipment in the program are coded to indicate type of work performed and whether equipment failure is involved.
Entries are also made giving a failure code and description and root cause of failure.
(2) Semiannually, the equipment history files are searched for equipment with an abnormal number of work-type / failure ratios.
(3) A list of the WRs identified per. the semiannual search is reviewed by the Planning Staff.
Equipment with an abnormal number in each category-is selected for further investigation if not previously investigated.
This selection is' based on the staff's knowledge of required testing, investigations already underway on the equipment, NSMs outstanding on the equipment, and other sources of information. Normally six to ten pieces of equipment will be selected for detailed study. A complete work request history of the equipment is generated by the Planning Section on the selected equipment.
(4) Hard copies or informational printouts of WRs relating to the selected equipment are gathered and reviewed by the Planning Support Staff.
Recommended actions (or no action) are documented with the package.
(5) The packages are sent to the appropriate Technical Support Staff or MM or IAE. The recommendations and packages are reviewed and appropriate action initiated.
(6) A documented statement of action taken - (or no action) is returned to the Planning Section for filing.
Since the implementation of MMP 3.3, the semiannual reports referred i
to in steps (2) through (6) above have been completed only once I
and were not considered indicative by the team.
However, the team was aware of recent changes to PM requirements due to recognized
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equipment problems, particularly in relation to VI problems
)
referenced in the licensee's response to GL 88-14 as further dis-cussed in paragraph 2.a.
The team was also able to assess responses to equipment failure histories during the review of WRs listed in Appendix 4 and as further discussed in paragraph 1.k.
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The team's consensus was that maintenance trending'was proceduralized and being implemented.
The team concluded that NRC concernE refer-enced'in 369,370/IFI 88-31-11 was satisfied and this. item was closed.
However, the team identified a concern regarding a general lack of.
conformance with requirements to enter the failure cause codes on the WRs reviewed. This is - further discussed.in paragraphs 1.a.
1.f...
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and 2.h.
This' concern was. identified to-the licensee as an issue and-resolution.is detailed in paragraph 2.d.
r.
Maintenance Facilities The team' conducted a walkdown inspection of the licensee's clean and-hot maintenance machine shops', and the. fabrication shop to. observe general conditions and specific activities The_ team found that;the shops were' laid out well,. and spac-for work activity was adequate'.
The. clean.and hot' shops had adequate lighting, tool storage for each mechanic, and both shops were equipped with a variety of lathes,
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milling ' machines, grinders, and drilling ~ equipment of adequate capacity to ' handle most machining requirements. The team found that the machine tools.were of high quality and' in excellent condition.
The clean machine shop tis. located inside the protected area, :Just-inside the turbine building, and convenient to the plant.
The hot-shop, inside the RCA, is directly adjacent to aL decontamination facility.
In addition, within the. hot shop, was an enclosure for<
performance of work on-highly contaminated equipment..This enclosure-had clear plexiglass ' walls and -its own ventilati.ons system. ' Access was strictly within the -control of HP.
The licensee's fabrication shop was located outside the protected area. This : shop is equipped to handle major shearing, press-brake, welding, and-pinch rolling work.
The team found all of the ' facilities to be in excellent condition, with adequate ' space for the type of. fabrication work performed on the site.
Based on the above observations, the team considered the maintenance facilities to be-a strength ~ in the maintenance program.
s.
Instrument Calibration Program The calibration program for plant-installed instrumentation is the responsibility of the IAE group ~ in the Maintenance Department. The calibration program and its implementation is primarily controlled by Maintenance Management - Procedure 4.0, Station Directives 2.3.0. and '
3.2.0, and the Administrative Procedure Manual.
These procedures and directives were reviewed to determine if the.
calibration program meets NRC requirements and the licensee's program is adequate. The calibration program was only examined relative to work performed by the IAE group in the Maintenance Department and measuring and test equipment' controls used for mechanical maintenance -
tool _ - _ _ -
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The periodic tests and calibration tasks are divided into ' three -
areas:
pts These are items which are required by any document
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which legally binds the - plant operation.
Instruments are tested and' calibrated by surveillance and periodic tests.
These are non-regulatory items which the licensee has PMs
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committed to.
Test Equipment -
Calibration. of rneasuring and test equipment-in the calibration laboratory.
The planning group in the Maintenance Department is responsible _for
- scheduling all instrumentation maintenance, including PMs, for the IAE group.
The following' types of computer generatei lists'were reviewed by the team to determine if the licensee has an effective.' tracking and scheduling' program.
(
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PM/PT Task List Periodic Test Report Index PM Task List Test Equipment Calibration Schedule Daily Maintenance Schedule Weekly Maintenance Schedule Control Room Deficiency Work WR Closed Items WR Open Items The PM/PT task list was reviewed by the team to determine if the associated tasks were being completed in a-timely manner. The team found that of 4246 total tasks on the list, only 2 were late.
Neither of these was for safety-related equipment.
The team conducted walkdowns and observed scheduled PM/PT tasks being-performed. While observing this work, the team reviewed the - work
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request, the calibration procedure, _ the data being' taken, and
- discussed the - work. with -- the IAE technicians performing the calibrations.
The~ instrument calibrations, work requests, and procedures observed and reviewed are as follows:
Work Request Procedure and Work Equipment 01645A IP/0/A/3000/18 and 19 2E1ACA9220 Verify and scale items'in. computer ICCM-85 I
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l Work Request Procedure and Work Equipment-01458A'
IP/0/B/3214/01A
- 2MRNFT5371 Calibrate flow transmitter 01450A IP/0/B/3006/09.
1 EMF 34(L)
Radiation monitoring.RP-30A-loop calibration 01519A PT/1/A/4601/03 RPS Channel 3 i
Functional test for protective system channel III 301221 IP/0/A/3219/04 Valve MV.0015 Corrective maintenance and setup of Fisher type'667 actuator 43107 IP/0/B/3006/07 D-CON 1. EMF 32 Radiation monitoring system liquid monitor transfer ~
calibration 501186 IP/0/8/3250/49 Valve ~25V-40 IP/0/B/3203/03 IP/0/A/3219/03 IP/0/A/3090/02:
Repair, adjust and calibrate instrumentation for atmospheric dump valve In all of the above examples, the instrumentation work was performed as required -by the WRs, the procedures were followed, and the. IAE-technicians were knowledgeable and acted in a professional mann'er.
However, the team identified deficiencies at the Unit 2 atmospheric dump valve structure. The copper air tubing was not secure.
In addition, the tubing for valves was. damaged and! needed to be replaced.
The licensee initiated WR 69372.to ' repair ~ these deficiencies and installed deficiency tag 001012 on the structure.
The team performed a. walkdown in the control room to examine the instrumentation and control room defi cient. l e s.
All equipment cabinets and panels were examined. The following deficiencies were noted:
]
HVAC panel had'four fuses not identified.
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Reactor coolant pump panel Unit 1 vibration monitoring panel
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contained miscellaneous material and housekeeping. was unsatisfactory. There was a lifted' wire marked " Bad Wire."
Auxiliary relay. cabinet' Unit 2 had two lifted wires' for a -
modification not completed.
The licensee made provisions to take the necessary corrective action relative to the above by initiating WRs. The safety related cabinets for the reactor protection' system and engineered safeguards equipment were found in excellent condition.
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j The control room had 102 licensee identified deficiencies for the instrumentation. Control room deficiencies have been identified as a problem area in previous NRC inspections and by INPO.
The licensee agreed this was a problem area and had taken measures to correct these problems.
The IAE group formed a committee including 12 members from various sections such as planning and operations to resolve this issue. In addition, IAE has assigned a full-time crew and supervisor to work on control room deficiencies. Of the 102 deficiencies, 24 were associated with safety-related equipment and 78 with non-safety-related equipment. Many of these deficiencies were for instruments located inside containment which are unavailable for maintenance until an outage.
Cognizant licensee personnel informed the team that consistent progress in reducing these deficiencies has not been made in spite of efforts by IAE.
At the present time, it appears only the deficiencies are identified and not the root cause.
The team believes more emphasis on root cause analysis is needed to resolve this problem.
As previously indicated, the team also examined the licensee's cali-bration practices for mechanical measuring and test equipment. The licensee stores and issues this equipment for use in maintenance from two tool cribs; one for work on non-contaminated equipment, and a
" hot" tool crib for contaminated work. There are also corresponding facilities for calibration and maintenance of tools for regular and contaminated work.
Tool calibration is conducted.in special enclosures which are temperature and humidity controlled. The team conducted a walkdown inspection of the licensee's tool ~ crib and calibration facilities, including the hot tool crib and calibration enclosures, to determine if the licensee provides the proper measur-ing tools for maintenance work, and if these tools were properly maintained and calibrated.
The team randomly selected various measuring tools in the tool crib and hot tool crib and checked their general condition, the level of storage, whether the calibration interval was clearly indicated, and the documentation associated with
the tool was available and properly completed.
Further, the team
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conducted interviews with personnel responsible for issuing and calibrating tools.
The tools selected included six outside micrometers, four dial calipers, five dial indicators and two torque
wrenches.
l All of the tools examined were found to be within their stated calibration interval, and in good condition, with the exception of a 0-6" dial caliper, identified as MCMNT 26059 which had badly worn jaws.
The condition of the caliper was brought to the attention of the personnel responsible for calibration of this item, and it was pulled from inventory.
Further, documentation for each tool listed above was 2 /ailable, and properly completed.
The tool cribs were well-organized, neat, and clean. Other items examined by the team included winches, slings, wrenches, portable hand tools and the like.
All appeared to be in excellent condition.
The calibration rooms
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were neat, clean, and contained the tools and parts required for calibration of measuring tools. Personnel contacted by the team were knowledgeable individuals relative to the care ' and maintenance of special measuring tools examined by the team. Based on the overall results of this inspection, the mechanical tool issue and calibration program is well-implemented and contributes to the strength of the maintenance program.
The team's consensus was that the licensee has a good instruments-tion maintenance program.
The calibration laboratory was found acceptable.
The licensee is improving his procedures.
The PM calibration task backlog is almost nonexistent. The IAE supervisors and technicians were found to be knowledgeable and acted in a professional manner.
However, inconsistent progress in reduction of control room deficiencies is considered a weakness associated with a need for more attention to root cause in this area rather than an IAE problem t.
Staffing Control, Personnel Training and the Qualification Process Training of McGuire maintenance personnel was provided at another licensee plant during' the first years of McGuire commercial opera-tion. In about 1980, the licensee completed their Technical Training Center (TTC) located adjacent to MNP. The team visited the TTC and observed that it is an excellent facility containing classrooms, work shops, laboratories, and offices.
The facility demonstrates a commitment by licensee management to provide quality maintenance training. Once the TTC was operational, a twenty-week basic curricu-lum became mandatory for new employees in the Maintenance Department.
Maintenance personnel hired before 1980 were required to 'take a
"by pass" test and refresher training in any weak areas. At present, the TTC '.s used for the Instrumentation and Electrical Basic Course.
Another licensee training facility, located at Mt. Holly, North Carolina is utilized for the mechanical basic course.
i MNP received INP0 accreditation for its maintenance training program
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in March 1987. The Vice President of Production Support provides oversight and manages resources for the training program. The team found that the program was well documented in the Administrative Policy. Station Directives and Employee Training and Qualifications System (ETQS) Manuals.
The ETQS Manual is a set of 75 standards, covering basic training, on-the-job training, task qualification, specialized training, continuing education, vendor supplied training e
and pre-outage training.
The corporate wide Production Training
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Services group employs about 223 people.
I The team examined the complete training and experience record for
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three individuals in the Maintenance Department and found their i
training more than satisfactory.
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MNP's qualific tion process is essentially one whereby craftpersons strive to become formally qualified to independently perform a number of tasks related to their assignment in the Maintenance Department.
Qualification is accomplished through on-the-job training, and then, demonstrating ability before a designated " qualifier." Each step is properly documented, and qualification status for each individual is input into a computer program. The program has the capability to printout a matrix of individuals and tasks for each work crew. Work Orders indicate the relevant procedures and sequence of steps.
The qualification matrix, the Work Order itself, and a document which correlates procedure numbers and ' task numbers provide supervisors with all the information needed to assign qualified persons to each step of a Work Order.
The NRC team reviewed about a dozen Work Orders vis-a-vis worker qualification.
It became apparent from this review that workers are frequently assigned to perform a Work Order step who are technically not qualified to perform that step.
Procedural requirements for such cases are that the workers must be closely supervised by a supervisor or engineer.
However, the procedures do not call for documenting (in the Work Order package)
that the required supervision was done.
The team discussed with cognizant personnel the need for each work order, to include worker.
qualifications traceable to source documents, or, alternatively if close supervision is utilized, the qualifications of the supervisor should be traceable to source documents Based on their observations and review, the NRC team considered that the licensee had sufficient personnel resources for accomplishing all maintenance-related activities.
Work was accomplished without reliance on excessive overtime.
Craftpersons, engineers, technicians, and support personnel are organized in a logical manner.
MNP's system of permanent day crews and rotating shift crews was observed to work well.
The worker / supervisor ratio appeared appropriate.
The experience level of the majority of personnel was found to be high.
Many had worked at MNP for more than 15 years.
The policy on disciplinary actions was discussed with managers in the
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Maintenance Department. The discipline policy is described in the Management Procedures.
There appeared to have been few disciplinary
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actions and those taken appeared to have been fair.
Detailed written job descriptions and accountabilities were in the i
possession of managers for their own positions.
In summary, the NRC team performed a critical evaluation of the licensee's program for staffing control, personnel training and the
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qualification process; and the day-to-day implementation of that l
program. The team concluded that a comprehensive program is in place l
l and effectively implemented.
Besides the documentation problem l
l discussed in the previous paragraph, the team identified a minor weakness in the program which was discussed with the-licensee. A i
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significant portion of the electrical maintenance work is performed by the Transmission Department. The team's concern-is that a formal study. has not been performed by Production Training Services to determine whether. or not the Transmission Department's training and.
qualification system is equivalent to that described herein for the Nuclear Production Department.
The team was informed that such a
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study is in progress.
u.
Acknowledgement of Risk Significance in Prioritizing Work The-team ' discussed the use of PRA and risk significance in the maintenance process with maintenance management and design engineer-ing personnel.
These discussions revealed the following:
PRA is not being used 'specifically in the maintenance process.
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However, the licensee's methods of prioritizing work necessarily places emphasis on some of the same systems and equipment-that PRA would identify as important.
McGuire has a PRA, which was originally issued in 1984.
An
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update revision was started in early 1988 and is scheduled for issue in the near future.
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McGuire continues to study and use. unavailability data for.each major piece of equipment to augment.the maintenance process.
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The Reliability Centered Maintenance (RCM) study (Draft April-1989) for the emergency diesel generators was based on PRA concepts.
The licens'ee's methods of prioritizing work, consider risk signifi-cance.
To-enhance the use of risk ' significance in prioritizing work, the licensee is studying ways in which PRA information can-be incorporated into the maintenance process.
2.
Issues Identified a.
Accuracy of Information Furnished to NRC As previously discussed in paragraph 1.f., the team's' examination of licensee activities associated with NRC GL 88-14 on instrument air-revealed inaccuracies within the licensee's May 5, 1989, response to i
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NRC.
Inaccuracies were also identified' with regard.to corrective l
action detailed within Unit 1. Licensee Event Report (LER) 88-36 on the VI/VG (Instrument Air / Diesel Generator Starting and Control Air)
cross-tie station blackout header.
These inaccuracies required considerable licensee and team resources' to' obtain clarification-and allow an accurate assessment by the team of the licensee activities
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involved.
In some cases, they indicated equipment inadequacies that did not exist. Details regarding the inaccuracies are as follows:
Response to GL 88-14, dated May 5,1989
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Attachment 1 Attachment 1 provided details on air-quality testing.- The statement is made that air quality testing is performed per a "recently written performance test procedure." Testing was instead done to special test procedure TT/0/A/9100/294 and the performance test procedure was not written' as of this inspection since potential acceptance criteria was not finalized until May 23, 1989
Attachment 2 Attachment 2 provided details on preventative: maintenance of VI components associated with the Generic Letter.
Statements were that a preventative. maintenance program was' being established for. critical instrument air demand equipment, and that a list of approximately 56 critical-to-operation, air operated valves (A0VS) had been identified to have associated air regulator. filters replaced. It also stated that these filters were replaced. during the _ last -
Unit I and Unit 2 outages and :that PM. work requests were '
being written to change out these filters every two years.
These statements implied that the above " critical" A0Vs
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are part of those valves. listed.-in Attachment A of the response, as valves which required. and received design verification of failure position ~ as accident mitigation devices.
Instead, the 56 critical.. valves were selected from operability considerations and have no accident safety.
i significance similar to the Attachment A valves.
Further, i
no clarification' is included that regularly scheduled
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filter-regulator PMs were not in place' as' of this inspec-
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tion for all valves ' listed in Attachment A.
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l Attachment 3 j
u Attachment 3 provides details regarding design verifica-
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L tion.
Statements-indicating discrepancies regarding
verification of_ correctly sized filters for existing and
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anticipated future' compressor capacity are as follows:
Maximum anticipated (future) base load is stated as.
1400 to 1500-scfm.
System Description MCSD-0024-01 dated January.21, 1986, notes: base load at that' time
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to be 2806 scfm under normal periods of heavy demand.
(This could increase to 3000 scfm under normal operation of two of'the three new CENTAC compressors.)
Total dryer capacity is stated to be 2100 scfm (3 9 700 scfm) when capacity is actually 3200 scfm (4 0 700 plus 2 9 200).
Total filter capacity.is stated to be 2400..scfm (2 0 1200)
when capacity is actually 4800 scfm (2 9 2400).
Specifics are included regarding the review of instrument details to ensure that air-operated active accident mitigation valves fail in their intended positions on' loss.of air.'
The statement is made that "also, all air-operated valves on Attachment A are verified by test to go to their fail-safe
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position on a periodic basis with exception of. several'. YC (control room chilled water) valves." Actually, no loss-of-air testing has occurred for' Units 1 and 2 Main Steam Isolation Valves (MSIVs) SM 1, 3, 5,
and 7 since reoperation tests Additionally, no testing of MSIV accumulator check valves was completed or planned. The licensee had identified the need.for such tests and they were later done.
Emergency Procedures
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Credit is taken (Attachment 2) for review of McGuire abnormal procedures for loss of instrument air. Thr 'icensee deemed the McGuire loss of instrument air procedure adequate to' cope with anticipated loss of instrument air events.'
Further, th'at
"because of our experience with losses' of air. the procedure in effect has been validated."
No clarification-is-included regarding January 20, 1989, revisions to the procedure (AP/1 and 2/A/5500/22) due ' to problems associated with the VI/VG i
station blackout header (LER 369/88-36).
(LER 369/88-36 was
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issued due to the licensee's discovery of the potential for loss of emergency diesels due to potential low control air pressure during use of the VI/VG ' cross-tie header, i.e.,. VG. compressors -
are unable to maintain VG pressure and simultaneously, supply air. to the VI system at the cross-tie header flow capacity.)
The. latest revisions of AP/1 and 2/A/5500/22 have not-been used and are subject to 'further change due-to the present design
,l study to provide a long-term resolution' for the VI/VG interface '
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design problem.
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LER 369/88-36:
Corrective action 3) states that "0PS personnel I
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changed procedures AP/1 and 2/A/5500/22, Loss of Instrument Air, to instruct the operator to open valves... while ensuring that VG control air pressure remains at acceptable level to
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ensure DG operability (greater than 125 psig)."
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The January 20, 1989, revision of AP/1 and 2/A/5500/22 step 6, responses 2. A.3) for A train and 2.B.3) for B train state I
" dispatch operator to locally open valves... while ensuring D/G l
control air pressure stays greater than 105 psig."
(Clarification was required as to what VG pressure is required to maintain DG operability and whether operator actions could be taken in sufficient time with VG pressure at 105 psig and falling to prevent automatic shutdown of the diesels due to low control air pressure.)
The team was able to ascertain that no technical discrepancies were indicated by the inaccuracies detailed above by a review of design documentation and discussions with cognizant lica see personnel.
However, the team identified a concern to cognizant licensee personnel relative to furnishing complete and accurate information to the NRC.
The licensee agreed and issued corrections associated with GL 88-14 on June 15, 1989. The team's consensus was that licensee actions taken and planned in response to GL 88-14 and LER 369/88-36 were appropriate, decisive, and sufficient to remove any technical concern.
b.
Problems With Labeling Permanent Plant Equipment Control of labeling of permanent plant equipment is specified by Station Directive 3.1.35.
This directive describes plant labels (size, color, type material, style, etc.), as well as requirements for replacing missing or damaged labels.
During this inspection, the team identified various problems with labeling of permanent plant equipment.
A representative list of those problems is as follows:
q ID tag missing for valve IRN-879
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Unidentified leaking valve upstream of 1YC-859 (i.e., unmarked
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valve near valve 2VI-27)
Gages between valves IVI-1248, 1249, and 1250 mis-identified as
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OM VS PG5070, 5060, and 5048.
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Unidentified valve in Fire Protection high point vent line from Component Cooling System (KC) pump header
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Refueling Water Storage Tank (RWST) not identified.
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Unidentified valve with broken handle near VGTK0038 i
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Valve 1AS-20 not identified on PVC pipe on chain as required by
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Station Directive 3.1.35
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Special "high visibility" plant labels on Category A valves
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associated with GL 88-14 (accident mitigation valves) not in conformance with Station Directive 3.1.35.
The licensee corrected all of the problems listed above during this inspection with the exception of the "high visibility" labels for GL 88-14 Category A valves.
The team expressed concern regarding the above problems. Cognizant licensee personnel stated that a labeling upgrade program was being undertaken and described its status to the team.
The team's concern was minimized due to current licensee efforts.
However, the team concluded that additional improvements in the program's implementation were advisable.
c.
Deficiency Tagging Problems Plant deficiency tags are used to indicate equipment problems, such as packing leaks, loose fasteners, etc., and their use is described in procedure MMP 1.10.
The plant deficiency tag is filled out when a deficiency is discovered, and lists the WR number, the equipment ID number, and a brief description of the problem. When the work is completed, or the WR is voided, the deficiency tag must' be removed.
In tours of plant equipment areas, the team sampled plant deficiency tags currently affixed to equipment.
It was noted that there were two types of tags in service; an orange paper tag, and a green laminated tag which is much more resistant to fading. and damage by water, grease, etc. Duke Power is in the process of switching to the green laminated tag because writing on the orange paper tags can fade and become illegible from exposure to the plant environment. The team observed the deficiency tags listed below attached to plant equipment and which were traced through the maintenance planning system to determine the status of the WR listed on each tag:
WR Number Equipment ID Remarks 68906 1RN 86A Rebuild or swap Limitorque
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actuator during RF0 6 (4/90)
l Tag is valid
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43110 2 EMF-44 Flow switch sticking.
Work in progress. Tag is valid.
134942 CA Pump 2B Tag not legible. No apparent problem at time of inspec-tion.
68420 ECB-2 Work completed, tag still on equipment.
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WR Number Equipment ID Remarks 138687 KC Pump 2A1 Tag - dated 6/1/89 for oil leaks.
At time of inspec-tion, no leaks apparent. to..
operations.
138824 IRN 89A WR for leaking voided.
Tag not removed.
New WR opened, also for' leaking, new tag not on valve.
135533-Diesel 2B-Work completed, tag not Governor removed. (Identified by DPC.)
135847 1RN HX0018 WR voided in 1988. Tag not removed.
138844 2RN 25B-Old style tag - not' legible because of' fading.
135534
_2CASV200 Filter.
WR voided.
WR's 135439, 69349, 74881, 69114 written to repair. Was scheduled for-
-6/23/89'
Of the ten examples -of deficiency tags observed by :the team, six
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were outdated, illegible, ' or had not been removed' following work completion. This contributes to confusion regarding the status of maintenance work, or the condition of a piece 'of equipment.
In addition to the above examples of missapplied' tags,;the team found a number of equipment deficiencies that had not been identified and tagged by the licensee. These are discussed in paragraph 2.J.. Based i
on these observations, implementation of the defi::iency tag program
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needs improvement. In addition, communications between planning, and
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maintenance could be improved, especially in light of 'the number of completed or voided WR's that still have outstanding tagr. on equip-ment. Though ' of limited - safety significance, this was considered -a weakness in the maintenance program.
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d.
Root Cause. Analysis As d.iscussed in paragraph 1.g.,
the team was aware ~ of NRC concern
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(IFI-369,370/88-31-10) prior to this inspection regarding an~
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apparently weak. root cause program.
A ma.ior. licensee corrective action in response to that concern was the September 1988 implemen-l-
tation of MMP 3.3, Equipment. Trending.and Failure Analysis-Program.
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However, as further detailed in paragraphs 1.a.,L 1.f., and 2.h., the
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team identified a general lack of conformance to MMP-1.0 requirements l
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to enter the cause code data in WR's ' reviewed.
This constituted obviation of step 1 of the equipment trending and failure analysis.
program as included in MMP'3.3.
The resultant NRC' concern was
^ discussed with cognizant licensee. personnel.
' Cognizant l'icensee personnel. stated that lack of the' cause code entries had not been. considered a problem since the descriptive-entries regarding the failures had been included. These descriptive.
entries' had been extensively reviewed by the systems expert personnel prior to final sign-off on the WRs.
Further, the. licensee stated that root - cause: analyses were also triggered - by other' avenues including failed-surveillance tests as required by MMP 3.5'(a' major
. source of root cause.. analyses associated with IAE failures),
engineering ~ Problem -Investigation Reports. (PIRs), McGuire Action Directory.(MAD) commitments, and initiation by-systems experts on their own cognizance.
The team-examined procedural controls fore conducting root - cause failure analyses as included in MMP 3.6 and a representative sample of completed root cause analyses completed since.the program's 1988 implementation.
(Some of the ' root cause' analyses reviewed-were associated with problems occurring before-1988.). A summary list is as follows:
Mechanical Root Cause Analyses
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(1) Failure of Main Feedwater lube oil pump motors IAl and 1A2 (2) Failure of actuator for air-operated Chemical and. Volume centrol system valve INV-2 I
(3) Broken threaded rod on spring can - hanger IMCA-NV-H304'
(hanger is on a 4-inch Chemical and Volume Control borated water line)
(4) Expansion joint failure on Service Water pump 1MRN-PU-0004.
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IAE Root Cause Analyses
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(1) Failure of both trains of Unit 1 Hydrogen Mitigation system
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(2) Failure of nuclear printed circuit board (NCB)' card 283A30 i
l due.to failure of power supply circuit (August;19, :1988, j
failure created fire on 7300 power supply cabinet)
l (3) Failure of positioner for steam generator 2C main feedwate'r.
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regulating valve-(caused Unit 2 trip on April 6,;1989, due to low-low steam generator level)!
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(4) Failed high voltage circuit in RP2C high radiation monitor-ing system module (this 1987 failure caused Hi-Hi spurious alarms and was determined to be generic to RP2C modules)
(5) Setpoint drift failures of United Electric model J302-552 pressure switches (30" HVG to 20 psig)
(6) Out-of-calibration drifts on.Solon pressure switches model 7PSIADW (7)
Failure of 7300 type : lead-lag card (NLL)' used for level lag-function on Unit 28 steam generator.
The team concluded that the root cause analyses - reviewed - were thorough, of high quality and complete (including engineering analyses, computer analyses and metallurgical test and analyses where necessary). Further, the root cause program was-being. accomplished -
in conformance with MMP 3.6.. However, that potential existed for missed signals in need for root cause analysis due to ' lack of cause'
code entries on corrective maintenance WRs.
Cognizant L licensee personnel agreed to revise MMP 3.6 to better define initiators of root cause evaluations.
The team informed cognizant licensee-personnel.that the above actions were sufficient and IFI 369,370/88-31-10 would be, considered closed.
e.
Preventive Maintenance for Molded Case-Circuit Breakers.
The team performed walkdowns in the auxiliary building' to. examine the safety-related 125 VDC and 120 VAC__ vital-instrumentation and control-power system. During inspection of the 125 VDC instrumentation and control distribution centers EVDA, EVDB, EVDC, and EVDD, the team did not find calibration stickers on any of the molded case circuit breakers.. Each center has four Westinghouse type LA-circuit-breakers -
which have adjustable magnetic trip units and are hard wired in their compartment. The output feeder breakers are the. Westinghouse type-HFB which have sealed thermal and magnetic trip units.
The team found that - the licensee did not have. PM procedures for the circuit breakers in distribution centers EVDA, EVDB, EVDC, and EVDD, and the licensee confirmed that these circuit breakers were not being calibrated or. tested to verify the operability of.the trip function.
The licensee was asked to respond to'two questions:
(1).Why are the 125 VDC and 600 VAC safety-related - distribution center feeder breakers not periodically checked or calibrated?
Vendor literature (Nelson Electric letter dated June 27, 1980, states that NEMA publication AB2-1976 be used to determine
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condition and capabilities for verifying performance of molded case circuit breakers.
NEMA Publication AB2-1976 states
" Breaker should be exercised periodically to assure - that-it is functioning."
(2) Were the breakers tested during pre-op testing?
The licensee's response was:
(1) Duke Power Company, Nuclear. Production Department will evaluate.
the need to perform periodic trip function (thermal and mag-netic) testing on molded case breakers-in feeder applications.
This will be' addressed at the department level for all three nuclear sites.
Existing PM programs on power distribution systems will be adjusted as necessary at the completion of.this evaluation.
(2) Molded case feeder breakers were not tested for thermal. and '
magnetic trip function operability during pre-op testing.
Regulatory Guide 1.68 (November 1973) requires testing-the correct and. reliable function of.the breakers, which is usually sufficient to confirm proper operation. Further evaluation will be performed at the department level to determine:if Regulatory Guide 1.68 should be interpreted to include thermal and magnetic-trip function testing of molded case cir;uit breakers 'used in feeder applications.
With regard to the licensee's response to question 2,. Regulatory Guide 1.68 (November 1973) states in paragraph 6.,
Electrical Systems, the following:
(a) Normal Distribution Test.
Tests to ensure continuity, circuit
~
integrity, and the correct and reliable functioning of transformer, breakers, motors,....
(b) D-C System Tests.
Check and calibrate relays,. instruments, breakers, interlocks and other components.
In FSAR Chapter 14.0, Initial Tests and Operation, the licensee:
states "The' objectives.of, and methods of achieving, an acceptable initial. testing and operation program, as stated herein, are in agreement with the objective and methods as outlined - in the-
-~
following:
-(a) Regulatory Guide 1.68 "..." " November 1973."
ll
- Also in the FSAR in Chapter 8, Electrical Power, Table 8.3.2-4,.
single failure analysis of the 125 VDC vital instrumentation and control power system, parts 2, 3, 7, 8, and 9, take credit for faults and shorts being cleared by the isolating circuit breaker.
__-. _ -.
.
.
.53-The licensee's administrative Policy Manual for Nuclear Stations in-Section 3.2, Testing, Section.3.3,. Maintenance,. and Section 4.2, Administrative, Instructions for Permanent Station Procedures, discuss the purpose, requirements and: methods that are applicable; to QA condition 1 (safety-related) structures, systems, and components.
The team noted in. paragraph 1.e,.~ relative to testing of' circuit breakers, that ne maintenance requirement-existed for testing functional operability after a trip due to fault current.
The Westinghouse type.LA 'and HFB series,. circuit breakers n.ay no -longer conform' to manufacturer's.. specifications 'af ter interrupting an excessive fault current. Thus, their intended protective function may not perform as required..The licensee could not provide any information to indicate how the circuit breaker would function after i
l-interrupting a fault' current.
The - team recognizes that the' requirements documents.for. testing electrical systems may not definitively specify testing molded. case
~
circuit breakers pre-operational, periodic or after trip due to fault current.
This matter is considered arguable; however, when the general high reliability of molded case circuit breakers is weighed '
against the long-term reliability needs of the involved nuclear plant electrical systems for a planned 40 year plant life, the team believes that an appropriate, conservative approach includes. elanned testing of these devices, and that-the licensee's lack of testing-represents a weaktoss. The licensee-indicated they will-re-examine the need for testing of molded case circuit breakers. Pending review of their actions in a subsequent inspection, the matter will be identified as Inspector Followup' Item 369,370/89-15-03, Molded Case Circuit Breaker Testing and Maintenance.
f.
ALARA Concerns The licensee's program to -maintain worker's-; doses. as. low. as reasonably achievable (ALARA) was reviewed and found to contain some weaknesses. The station's -1987. collective dose was: 521 man-rem / unit relative to a 1987 national average of. 371 man-rem / unit.
This
- '
distinguished McGuire as one of the. ten highest expo'sure facilities in the nation for: PWRs. In 1988, the' licensee accumulated approxi-mately 552 man-rem / unit.
The national average for 1988 was. 346 man-rem / unit.
i During informal discussions with. worker level maintenance and HP personnel, some. negative comments concerning -job planning were-l-
received. A review of RCA entry data (via RWP review) indicated that
some planners appeared,to be infrequent visitors to the RCA.
The-l review included January 1 through June 6,.1989.
During this time
,
period, some planners were recorded as signed in on-an.RWP only-two-
l or three times.
It is recognized this-data may not accurately
!
reflect RCA entry since the data may not-always.be retained if no j
dose is received. ' Also, as a group, in 1987, the planners accumulated j
0.380 man-rem while the plant as a whole received 1105 man-rem.
'
j
__
l
.
.
These data suggest-that some planners may not be performing pre-planning job site visits for jobs in which a job site visit could. aid
- the planning process. It is accepted in the industry that good job planning can reduce collective dose.
Through interviews with first line maintenance. supervisors,.the team determined that thorough knowledge. of the station's. ALARA program-was weak. Many were unfamiliar.with dose. goal. setting or past and-
~
present plant performance in achieving thosa. goals.
The supervisors were not cognizant of their worker's current doses, either as;a group or individually.
This is partially due to the. fact. that periodic.-
exposure reports convey exposure by. RWP not by work groups. However,-
licensee representatives stated that supervisors have been offered an opportunity to be trained on a plant-wide computer system which would
-
have allowed them to review exposure data by work gro'up but no first-line supervisor responded.
The team ' reviewed exposure goal formulation' at the plant.
Part of
- this process requires the craft groups to develop " action plans" which describe how they will_ complete planned major jobs and still achieve the dose goal set by the corporate office. These ' " action plans" are then used by site HP to develop ALARA dose goals for: the RWPs controlling.those jobs. At the time of the NRC maintenance inspection, June 1989, the RWP dose goals for.1989 had not been set.
Reasons for this were unclear-.
Site HP stated.that' maintenance had still not returned some " action plans" requested -in March 1989 However, timeliness of HP in issuing. the requests.may -have also affected " action plan" completion. Impact of the incomplete." action plans" on collective dose may be minimal since most.of the jobs covered by. the plans had not yet started. However, considering the station's high collective doses, the licensee should assess the priority level given to ALARA activities by mid and upper level'
managers.
g.
Drawing Discrepancies The team identified the - following drawing ' discrepancies to the.
- licensee:
.The master valve list indicates that A0V INC-56 is on drawing MC 1553.2.0 when the valve is actually on_1553.2.1.
- As previously noted in paragraph 1.a, MC-1574-1.1,- Revision 13, Flow Diagram of Nuclear Service Water System, showed a six inch
.
branch line coming off the-18 inch piping between the RN IB_ pump.
l-and its discharge check valve, but the team observed that the-line was not present.
,
__.-_m.__
_._.._._
____,_m___.
_ _ _ _ _ _.. -. _ _ _ - - _ _. - - _. _. -
i l
.
l l
l The. above discrepancies do not reflect adversely on maintenance,'as I
they appear to stem from errors made. at the time of plant construc-tion.
None of the discrepancies were of major significance and the licensee took prompt action for their correction.
To assure the matter has been satisfactorily resolved, it will be examined further in a subsequent NRC ' inspection to confirm that no generic problems exist.
It is ' identified as Inspector Followup Item 369,370/89-15-04, Drawing Errors.
h.
Work Request Discrepancies As noted in paragraph 1.a, the team identified discrepancies-. in a detailed review of a sample of RN System WRs.
These discrepancies and explanations provided by the licensee are described below:
Mechanical Maintenance Procedure (MMP)
1.0, Section 2.15,
-
l-required the planner to enter whether or not the equipment to be worked on was in the Equipment Qualification (EQ) program.
It also specified that craft supervisors update the EQ determina-tion, if required, prior to performing any maintenance.
The team found that for two of 16 WRs checked there was no entry.
The two WRs were 138483 and 500872. The licensee acknowledged that the entries were missed by the planners but did not state why craft supervisors failed to make the entries.
The licensee also stated that database sheets specified whether or not the equipment was EQ related. The team could not verify the data-base sheets as they were not required to be retained with the WR-records. The te. 1 saw such database sheets with WRs in progress during their inspection and agrees that EQ applicability could be easily determined from them.
There ~1s 'still concern, however, that a specific procedural requirement :is ignored on occasion - the requirement for the EQ entry.
MMP 1.0, Section 2.16, required the Planning clerical staff to
-
enter whether or not tho work (except emergency work) is report-able to the industry-wide Nuclear Plant Reliability Data System
)
(NPRDS).
Review personnel had final responsibility to update the. entry.
The team found no entries for' 11 of 21 WRs.
The
!
eleven were 88530, 138483, 138403, 136955, ~ 136402, 136451, 88604, 88591, 500872, 88095 and 135814. The licensee responded
!
that every WR is evaluated by the Planning staff for NPRDS deportability after WR closure and-that in the future NPRDS deportability would be entered then.
MMP 1.0. Section' 1.12, required the WR originator to enter the
-
failure description to maintain data.for failure analysis, trend
,
forecasting and cost analysis.
The team found that two of 16 l
l WRs checked did not have this properly entered.
The. licensee
{
did not provide a response to the specific WRs, but stated that l
in some cases the exact failure description might not be known i
l
<
,
i
,
l
G--______._
. _ _. _. _ _ -.---
]
.
...
by the originator.
The team ccnsiders that, for the WRs they identified, the originator could have easily obtained and
!
provided a better explanation.
In one instance. (WR 138483)
the failure description was " handwheel broke".
There was no explanation of how this breakage was detected, how it failed or the status of the system at the time.
For the other WR (500872), there was no entry.
The work requested was' adjust-ment of travel stops indicating the originator knew sufficient
.
' details of the failure to. specify how correction should be accomplished, but that he failed to enter the' details.
-
MMP 1.0, Section 5.1, required entry of the "Cause of Equipment Failure". For six of the fourteen WRs, cause was not entered or was entered incorrectly. These six were WRs - 501365, 136451, 88604, 135139, 500872, and 134533. The licensee's response to these was that they represented " supervisor error." MMP-1,0, Section 5.5, required entry of the " Equipment Failure Code".
The team found no entries of failure codes in any WRs they reviewed.
The licensee responded -that this was originally intended for entry of NPRDS codes by all three of their nuclear stations, that it was no longer used at McGuire because of changes in NPRDS reporting, but.that.this part of the WR had ict been eliminated at McGuire because the form and entries were still used at their other nuclear plants.
They stated that MMP 1.0 was being revised to reflect that McGuire no longer used this entry. It was not clear to the team why this change had not been made previously as WRs they reviewed, which had been completed over 15 months previously, had no code entries.
-
The licensee divided post maintenance testing ;into. retests and functional verifications.
Retesting appeared to be essentially testing to verify that normal periodically required testing requirements ueld be met, while functional verification was a check to insure that the involved equipment would perform all functions necessary for service. Refer to paragraph I'.p of this report for additional discussion of post - maintenance testing.
MMP 1.0, Section,8.8 provides for functional. verification to be documented in the WR. The team found that there appeared to be deficiencies for functional " verifications in five of 17 WRs reviewed:
!
WR 138483 involved a repair to the mechanism on a motor
.]
operated valve that permitted it to be operated manually j
through a handwheel..The functional verification sheet
.
(from procedure MMP 1.6) included with the WR was not initialed to indicate the valve had been cycled manually following maintenance, as specified by the planner, to verify the handwheal would perform its function.
When questioned by the team regarding this, the licensee j
responded that t',e technician who' performed the work stated l
he had engagrd and cycled the. valve partially through l
b
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._. -
- - _
.:_
- _ _ -. _ - - ~ -._
- - _ - - - - - - _ - _ _.. _ _
________
,
.
.
its stroke to verify handwheel operation. They noted that the lack _of signoff was an error by the-technician and.the supervisor.
WRs 135139 and 134533 both involved repairs to valves ~toL
correct through valve (seat) leakage. In neither case.were there functional verification ~ entries which indicated performance of checks to verify correction-or improvement of through valve ' leakage.
The licensee respondedL that through-valve -leakage. correction would have been verified by Operations performance, when 'the system permitted, and would not - be ' recorded on the WR.
They also noted that:
.
another WR would be written if ~ the leakage. was still too high such that the inadequate correction would be noted.
!
The significance of the through valve :1eakage -is limited, as leak tightness is not required to ensure a plant safety; but is rather a problem in isolating components for maintenance such as.HX cleaning.
However, for the instances referred to by the team,- it appears: that-Operations could have easily determined if leakage had been.
j corrected before the WRs were closed and that it was
'
appropriate to do so.
- WRs 134315 and 88095 involved manual drain'and vent valves i
respectively. The drain' valve was removed to permit access for an internal pipe inspection and after,the inspection it was reattached.
The vent valve' was removed because-of -
~
inoperability and replaced with a new valve which had-to De j
.
disassembled before installation. The team found that.the licensee did not stoke eitherT valve. after installation to functionally verify its ' operability.. In response to the
{
team's finding the licensee identified both instances as
'l supervisor error.
!
!
The above verifications were for components or component func-j tions with limited safety significance. ' The team _ did not identify any _ instances where the licensee failed 1 to ' assure adequate function for safety.
.,
l l
The detailed record of maintenance performance for eachlWR is.
'I
'
-
entered in the " Action Taken"'section by personnel-. involved in
-
work performance for -each. planned ' step of. the maintenance job
-
sequence. - MMP 1.0, Section 5.2... covers these' entries..The.
,
l
. team found that, while the person who entered the " Action-Taken"
!
'
usually entered his name and the date of.his entry, this was_not l
required by the MMP..The team considers that such signature and-l date entries are necessary to make the person entering the data:
!
accountable for his. entry and to identify him as ' a source of;
!
nitrification ifl needed in subsequent reviews and work.
In response to questioning on this matter,_the. licensee stated that they would review adding such a requirement to MMP 1.0.
The i
team determined that the entries of " Action Taken" were overall'
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _
- _ _ _ _ - _ - - _ _ - _ _ _ _ _ _ _ - -
. - _ _ __
.:
...
'
good in : providing needed historical information, though they would need to be' converted into:more concise data to be suitable for affective use in a computerized database.
In addition to' the WR discrepancies referred ' to above,. the team
~
observed one additional-WR: related discrepancy described inn paragraph 1.b.
This was the failure ~of the-licensee to havr a formal-method for voiding discrepancies which provided-for removat of tags -
from' equipment when a WR was voided. Tne absence of. such a p' ocess r
permits deficiency tags to be left on equipment when they do not apply.
The team concluded that the above discrepancies principally indicated weaknesses in recording information for use in licensee trending and-identification of equipment and maintenance work deficiencies, especially with regarded to failure ' description.-and cause.
Lesser weaknesses were noted in performance of functional verifications and-in the lack of a procedural requirement for personnel entering descriptions of maintenance work to also enter their name. and the date and the lack of WR voiding requirements which assure removal of.
deficiency tags.
Pending additional review in a future inspection,
.
NRC concern will be identified as Inspector Followup Item 369,370/89-15-05, Work Request Discrepancies.
1.
600 Volt AC Rating for CBs During review of the 600 Volt 'st system vendor c' documentation, the team noted that the system bret ers, Westinghouse HFB type, are rated for 600 Volts. McGuire pM/PT 44350/03A is performed to verify' that -
system voltage at the traorormer is maintained between 540 and 660 Volts AC.
The team questioned whether the 660 Volt. maximum system voltage was consistent with the 600 Volt breaker rating and-the possibility the breakers would not perform.their protective-function at the higher system voltage.
At the conclusion of the-inspection, the licensee was still evaluating this. condition and -
attempting to. verify that the breakers were satisfactory up - to
-
660 Volts.
Through subsequent telephone calls - (O. Mustian, Site Maintenance Support Engineer, and W. Matthews, Design-. Engineering, to-NRC, B. Crowley) (T. McConnel, Station Manager' to B. Crowley) - the licensee furnished the following information:
.
-
Procurement records for the MCCs which included the breakers, indicate that the equipment was procured to.600 plus or minus 60 Volts in accordance with NEMA standards.-
Typically, system voltage is 575 to 610 with below 600 more
-
common. Current veltage measurements for Unit 2, which is in an outage and would have reduced loads and higher voltages, showed system voltages between 575 and 605.
_ _ _ _ _ _ _ = _ _ _ _ _ _ - _ _
-
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- _ _ = _ _ _
.
l'
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- A review of past data showed voltages normally range from 575 to
-
605.
The highest recorded voltage was 644, during pre-op testing of Unit 2 under essentially no-load conditions (when voltage would be the highest).
On July. 28, 1989, at the time of the exit interview, the licensee provided additional -information taken from Unit 2 load centers indicating that' voltages are above 630 (some 650 - 660) with the unit in Mode 6 or no load conditions.
The licensee further pointed out that these higher voltages in no load conditions are.necessary to ensure that voltages are not too low for motor operation during load conditions..The. licensee was still in the process of resolving this issue at the time of the exit interview.
The team determined that the breaker rating question was not'related to maintenance and identified Unresolved Item 369,370/89-15-06',
600 Volt AC Circuit Breaker Rating', to review requirements. relative to this question in more detail in a future inspection.
J.
Housekeeping and Material Condition During the inspection, detailed in paragraph 1 above, the team identified several housekeeping and material condition discrepancies.
Immediate corrective action was taken. by ' the licensee 'for the problems identified.
Discrepancies identified were as follows.
i (1) Housekeeping Numerous examples of water on the: floor in the auxiliary
-
and turbine buildings. Most of the water was from conden-sation and roof leaks.
A few valve leaks were noted but'
l they were not significant. contributors to.the water'
i observed. The licensee-pointed out that the condensation
was worse this time of year as cold water being taken from l
Lake Norman cooled components--in contact with high humidity j
air. Work is planned to. repair roof leaks. The team noted
-
y that no radioactive water leaks were identified.
Numerous examples of tape (electrical, teflon and duct)
!
-
abandoned at various locations in turbine ; and auxiliary
!
buildings-
-I i
Cable draped over pipe in turbine building near ' column
-
IB-2B.
,
i Miscellaneous material inside Unit I reactor coolant pump-
-
vibration. monitoring panel.
Scrap wire near ceiling' of QAPFT-P. at 767' elevation in
-
auxiliary building.
Also, scrap electrical wire at end of-electrical conduit near column HH-59.
i
_ - _ _ _ _ _ _ _ - _ _ - _
.
.
Abandoned can of cutting fluid on' pipe next to valve
-
.Two pieces of weld material and loose needle valve in 2A-
-
motor driven auxiliary feedwater pump room.-
Oil on floor and miscellaneous debris (paint brushes, rags,
-
trash. bags, empty paint cans, etc.), on floor behind Unit'2 turbine driven auxiliary feedwater pump.
-
HVAC instrument'.line leaking approximately I gpm on floor
-
(WR 138660).
-]
- .,
(2) Material condition
)
Loose support clanp on line to instrument OYC PG5500.
-
-
Lock washers missing on inverters IEVIB and IEVIC.
!
I Corrosion and broken door latch on power distribution i
-
cabinets near Unit 1 RWST.
J Leak on Unit I high pressure turbine.
--
Safety relief valve IVI-6 missing-handle and assorted i
-
'
parts.
Broken handle' and excessive corrosion on motor control
'
-
center 2MXMA compartment 2E.
' unidentified fuses in control room HVAC panel (Units 1 I
U
-
and 2).
Control room RCP (Unit 1) vibration monitoring panel had
-
miscellaneous debris inside and a lifted lead unidentified-except as " Bad Wire."
j Control room auxiliary relay cabinet, (Unit 2) had two
-
lifted leads.
-
Valve ICM-976 had drip collection funnel with loose hose.
-
Excessively loose valve handle for valve 2WN-18.
,
Valve 2CA-116B leaking.
-
Valve 2RV-482 leaking.
-
Page horn taped over near entrance to room 805 above
-
monitor EMF-438.
_ --
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._ _ _ _ _ _
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_
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61
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Indicating lights lit,. missing covers or broken sockets -
-
transformers 2ELXA, 2SLXC, 2LXE, XLA, IXLE and control panel No. 2 of AHU-1A8-B.
.
-
Excessive span (25 feet) of 3/4 inch VI header without.
support near valve 2VI-146.
Loose column support for gage 0YC PG5360.
-
Loose conduit clamp near column HH-59.
-
Leaking unidentified valve near valve 2VI-27.
-
Broken handle on unidentified valve near VGTK 0038.
-
-
Missing handles.for valves 1YC61 and 1YC68.
-
Door for Unit 1 Air Handling Unit OMVCAH003 missing two dogs.
-
Flexible conduit broken on motor' driven auxiliary feedwater pump motor cooler 2B 2RNLS6296.
Damaged and unsecured airline tubing at atmospheric steam
-
dump valves.
-
Missing glass on pressure. gage for VI supply to Woodward governor on Unit 2 turbine driven auxiliary feedwater pump.
Bent needle on pressure gage 2NVPG5490.
-
-
Steam dump valves 2SV32 ' and. 2SV44 - filter regulator pressure gages unreadable due to scratched covers. Also missing glass on cylinder pressure gage.
Missing hanger near valve 2NI-808.
-
The team consensus was'that overall housekeeping was average. Many' areas of the plant were above average, however, the amount of water on the-floor and scattered loose tape, detracted from the overall housekeeping.
The material condition was considered average.
Most of the material condition deficiencies listed above had not been identified by the -
,
licensee. Although a significant number of.' discrepancies were identified, the discrepancies were generally minor and did. not-demonstrate any d
.in ication of operability problems.
The team concluded that although no. major housekeeping or material condition deficiencies were identified, the number' of. minor deficiencies
- indicated the need for improvemen.
!
3.
Evaluation of Plant Maintenance a
Overall Plant Performance Related to Maintenance - Direct Measures Rating: SATISFACTORY Findings / Observations:
- The rating of this section was based on the findings of the team in the areas of historical data and walkdown inspections. Deficiencies
' identified during walkdown inspections, availability, forced outage rate, safety system failures and. radiation exposure hi story. were
~ major influences on rating this section.
The: plant availability and. forced outage rate were generally above average when compared to industry averages (detailed in paragraph 1.m)..However, this is offset by a radiation exposure-which has been. significantly higher than industry average. and by a
_
high number of safety systems failures (1.1. and-1.m.).
Also, a significant number of housekeeping. and material conditions were identified (2.j.).
b.
Management Support of Maintenance Rating:
Program: GOOD Implementation:
GOOD Management support of maintenance was examined by reviewing and evaluating (1) management commitment to and involvement' in mainte-nance; (2) management organization and. administration for both the corporate and plant level; and (3) technical support provided to-the maintenance organization.
(1) Management Commitment and Involvement Rating:
Program:. GOOD Implementation: GOOD
!
Findings / Observations:
j
The rating of this section was based on application ~of industry
initiatives and management's commitment to improvement of
!
maintenance performance..
l
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- _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ -
--
.
%
,
.
'
Evaluation of the licensee's application of industry initiatives-indicated the following: MNP participates in the NPRDS program; good response to EPRI guidelines'and INPO SOER-on check valves-(l'.k);_ good' program and response to industry _ issues ~(1.n); the
-
Licensee does have - a systems expert -(systems engineering)
program -(1.k); the licensee has-an INPO accredited' training
'
program (1.t) and MNP actionsfin response GL 88-14 on instrument-air were decisive and adequate (1.f and'2.a).
In evaluating management vigor and example, the team.noted the-following positive ~ indicators: - The ' licensee performed.an adequate ' sel f-assessment'; management' supports the training
. program (1.t); management.' demonstrated a ' strong. interest. in maintenance; management provides or has. provided outstanding _
maintenance facilities ( 1. r.),
high' quality and adequate engineering support (1.k), adequate maintenance staff and continuing assessment of maintenance through use of performance indicators.
(2) Management Organization and Adminstration Rating:
Program:
GOOD.
Implementation: GOOD Findings /0 observations:
Inspection in this area wasTaccomplished by ' the review of -
procedures included in Appendix 3.of this report;. interviews with all levels of management; sampling of selected systems and comb;.nent WRs' and observation' of maintenance meetings and.
ins Ihce acvGities between Maintenance and -Technical Support groups.
The sampled WRs are listed in Appendix 4._ of this report.
Maintenance staffing level seemed adequate,' including the amount and quality of.. technical support provided;- no significant indicators of meterials problems were found in the WR' review;
_
maintenance work is seldom delayed due to inadequate maintenance support; QA/QC was adequate and heavily involved in the mainte-nance process'(1.1).
Review of the licensee's specifications of _ maintenance require-ments revealed:
The maintenance program. implements EQ, preventive andf predictive maintenance, ISI requirements, surveillance testing and diagnostic examination requirements; PM program for molded case circuit breakers does. not address.
periodic verification of trip function (2.e).
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - -. - - - _ - - _ - - _ _ - - - - - _ _ _ - - - - - - _ - - - _
.
.
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Review of the licensee use of maintenance performance measure-ment indicatt.i the followingi root cause analysis is effective (2.d), maintenance performance ~ trends are: established and implemented (1.q), and performance measurements (e.g., backlogs, pm/ corrective ratios, etc.) are defined and implemented.
The licensee has established and implemented a document control-system for maintenance. Documents were retrievable and identi-fiable (3) Technical' Support Rating:
Program: GOOD Implementation: GOOD The purpose of this inspection was to-evaluate the technical support -received by : the Maintenance organization from other plant organizations such as Engineering. Health Physics, Quality control, Regulatory Compliance, and Onsite Nuclear Safety. Also l
of interest in this area was the'1evel of communications between various organizations.
.I Findings / Observations:
Evaluation of the licensee's ' technical support' indicated.the following:
the licensee has' developed and ' implemented an -
adequate program for monitoring heat exchanger and check valve performance (1.k) developed and implement _ed a program.~ for vibration monitoring of equipment outside of the ' envelope-of.
ASME B&PV Section XI;. deve' loped and implemented an -in-house balancing program (1.g) for rotating elements; the licensee has--
..
developed a satisfactory systems expert (systems-engineering).
!
program (1.k); and the licensee has established a methodology to j
assure that industry initiatives are Ladequately addressed and
!
work in:this area is of. good quality (1.n)..The team. observed
adequate. engineering support from both maintenance and design engineers.~ However, the team noted examples of inaccurate technical information to the'NRC (2.a).
Examination of QC revealed that:
criteria for inspection' and
!
audit are established and implemented,. inspection / verification j
is scheduled and accomplished, and corrective actions are taken-
!
- .
as necessary.
The Team noted. that plant. QC inspectors. were
present auring the performance of maintenance and that - WRs
'
'
specified holdpoints for QC checks (1.1).
Radiological controls were examined and ALARA concerns identi-fied (1.1.and 2.f).
.]
.__:___ _
_ _ _ _ _ _
-_
+
.
Examination of '. maintenance safety revealed; no lost. time accident; procedures for hazardous materials, electrical safety,:
fire protection and confined spaces;. tracking of performance indicators related to-safety; and an aggressive safety depart-ment (1.g).
,
c.
Maintenance. Implementation Rating:
Program: GOOD Implementation: GOOD The purpose of this part, of' the inspection was to determi.. the quality of - the established controls and, more importantly, the implementation of these controls.
the four areas evaluated ara (1)
work control, (2) plant maintenance organization, (3) maintenance facilities,. equipment, and materials, and (4) personnel control.
(1) Work Control Rating:
Program: GOOD Implementation:
SATISFACTORY Findings / Observations:
Inspection in this area was accomplished by review of proce-dures included in Appendix 3; observation of the maintenance activities in progress and review of-work orders ~ included in Appendix 4.
Observation of maintenance in progress revealed.the following:
~
appropriate authorizations were received;. proper documentation,
was issued; foremen observe the. work in progress; personnel
_
appear competent and properly _ qualified; procedures.were-followed; and no major problems were' identified during the-observation of work. ' However, a concern was identified -
regarding walking in cable trays (1.a)'
-
.
l Review of the licensee's-work-order control' system indicated:
l
- it provides for ' identification _ of. work; required. reviews and.
)
approvals; tracking of status of work in progress; and ensures'
i work on equipment affecting operations. However, concerns were
.
identified-regarding lack of use of. failure cause codes (1.a.
I 1.f. and 2.h), a formal method for voiding WRs (1.j), and WR
!
discrepancies (2.h).
!
i i
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,
'
l i
Examination of equipment histories indicated the following:
Equipment history records are maintained, easily accessible, kept current, and document repair time. Equipment history data is reported to NPRDS, and NPRDS data is used. Equipment history records are used to support maintenance trending.(1.q).
Review of the conduct of job planning. revealed a dedicated and
)
generally well trained planning staff.
However, examples ~ of j
.
inadequated job planning were identified (1.a) as. well as planning concerns associated with ALARA (1.1 and 2.f).
Examination of the licensee's work prioritization controls revealed that safety sig'nificance e.nd the effect of safety -by BOP is considered and no safety significant items were found that were not included in the work schedule.
However, prioritization efforts could be ~ improved for " routine" work (1.j) and risk significance should receive more consideration in prioritizing work (1.u).
Examination of work scheduling revealed the following:
preventive, corrective, predictive maintenance and surveillance activities are scheduled and controlled; potential conflicts are considered in the scheduling; and activities are scheduled to assure appropriate supervision.
The licensee's establishment of backlog controls was reviewed and it was determined that; backlogs are measured and trended, but backlog controls do not ensure timely resolution of delay-causing problems. Backlogs should receive additional attention from plant management since they are considerably greater' than stated licensee goals (1.0).
An examination of maintenance procedures revealed that proce-dures are generally well conceived, thorough and technically adequate. However, some procedure problems were noted regarding
a PM switchgear procedure which did. not include inspection of-the wiring and bus compartments = (1.c), human factors concerns
)
(1.a), an out-of-date station directive on hydrostatic testing (1.p), a general lack of entering cause codes on WRs (1.a),
and lack of requirements for testing the functional operability of molded case circuit breakers (2.e). MNP has implemented a procedure upgrade program which should assure necessary improve--
ments.
-
An examination of post-maintenance. testing revealed that post-maintenance testing criteria have been established, documented and implemented.
However, examples 'of deficiencies in functional verification' were identified in some WRs reviewed (1.p and 2.h).
n
_
+
.
-67-The team reviewed a sample of completed ' work control documenta-tion as'. listed in - Appendix 4.
This examination established.
-that a document review methodology is implemented and performed in a timely manner.. No major anomolies/ discrepancies were identified.
- However,-
some-discrepancies ~ associated with
~
inattention to detail were noted (2.h).
- (2) Plant Maintenance Organization Rating:
Program: GOOD Implementation':
GOOD Finding / Observations Inspection in.this area was accomplished by observation _ of licensee's plant maintenance organization ~ and how it respo'nds to unusual events; how it supports maintenance. activities; how it controls and implements maintenance. activities; how-it controls personnel; how it established documentation; and how it develops-lines of communication between plant management and craft personnel.
Inspection in this area included review of procedures included in Appendix 3 and. review of WRs. included in Appendix 4.
Review of control of plant. maintenance activities. indicated:
vendor technical manuals are controlled and. updated; the maintenance organization has established methodology to identify maintenance.needs, ensure plant configuration control,- control materials, control tools, and accountability of work perform '
ance; general positive conditions included-PMs according to schedule, use of appropriate procedures, acceptable equipment condition and well~ trained personnel.
The licensee's. deficiency identification'2and control system was reviewed.
During plant.walkdown inspections, only. minor deficiencies were found (2.j) 'which. 'were not 'previously identified in a WR.
In general, the maintenance organization -
has an effective process for the. identification' and control of deficiencies; however,. concerns were identified due to the-number of deficiencies identified (2.j) and problems with deficiency tags (2.c).
Review of the licensee's maintenance trending indicated:
the-maintenance organization trends indicators required by ASME B&PV.
Code Section.XI; the licensee trends maintenance performance indicators; and a program to trend equipment problems has been developed and implemented (1.q).
- _ - _ _ _ _ _ _ _ - = _ _ _ _ _ _ _ - _ -
_
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_
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=__.:
_-
.
.
.The maintenance organization appears to have effective-communication / interface.with other organizations on and offsite; (3) Maintenance Facilities, Equipment and Materials. Control Rating:
Program:
GOOD Implementation: GOOD Findings / Observations:
'The inspection in the area ~ was accomplished by. general inspec-tions within : the maintenance - shops, tool rooms, and training areas.
A' general inspection was made of warehouse storage conditions and specific details associated with procurement, shelf life and certification of commercial grade spare parts.
Examination revealed that:
maintenance facilities are considered a programmatic' strength (1.r); an effective materials control system has been established and implemented (1.h);
the licensee has ' effective programs for tool, equipment. and measuring and test equipment control; and instrument' calibration is a programmatic strength (1.s).
(4) Personnel Control Rating:
Program: GOOD Implementation: GOOD Findings / Observations The purpose of this-inspection area was to evaluate staffing controls, training, testing and qualification and to assess.the current status.
Review of the licensee's. training program revealed:
the i
licensee has an INPO accredited : training and qualification program which is considered a programmatic strength;.and improvement is needed to assure that the transmission department has training equivalent to site requirements (i.e).
Review of the licensee's personnel controls indicated:
all personnel receive timely. performance appraisals; initial and -
,
update training is provided; overtime was not excessive; permanent day crews with rotating shifts is a plus; low turnover
- _ _ _ _ _ _ _ _ _ _
_
._.
.
...
.
rate; and organization charts are available, up-to-date, and reflect a favorable. supervisor / worker ratio.
The testing and qualification of maintenance personnel is satisfactory.
4.
Followup on Previous Inspection Findings a.
(Closed)~ IFI 369,370/88-31-10, Followup of Maintenance Program Improvements Relative to Root Cause. Analysis.
See paragraph 2.d
.above.
'
~
b.
-(Closed) IFI. 369,370/88-31-11, Verify. Implementation of. Maintenance Trend Program.
See paragraph 1.q above.
c.
(Closed) Unresolved Item 369,370/87-40-01, Maintenance Deficiencies.
This item documented concerns regarding. apparent deficiencies found in the McGuire maintenance procedures' and WR-data. entries. Similar deficiencies were observed ' during the current-. inspection _ and are described i_n paragraphs l'.a. and 2.h of this-report. -They do not appear to represent a significant violation of regulatory require-ments and the unresolved item is being ' closed. ~They do,-however,-
represent areas of weakness in the -licensee's maintenance. program-and will be subject to. further review in subsequent. routine NRC inspections. Inspector Followup Item-369,370/89-15-05, Work Request Deficiencies, is being opened to address the concerns that remain.
5.
Exit Interview The inspection scope and results were summarized on.' July 28,1989, with those persons indicated in Appendix 1.
The inspectors described the areas inspected and discussed in detail 'the inspection results listed below.
Proprietary information is not contained.in this report.
Dissenting comments were not received from the licensee.
Open IFI 369,370/89-15-01, Walking in Cable. Trays paragraph 1.a URI 369,370/89-15-02, Adequate Licensee -Response to Exit portal Monitor Alarms paragraph 1.1 IFI 369,370/89-15-03,- Molded-Case Circuit Breaker Testing and'
Maintenance paragraph 2.ex IFI 369,370/89-15-04, Drawing Errors paragraph 2.g
- j IFI 369,370/89-15-05, Work Request Discrepancies paragraph 2.h URI 369,370/89-15-06, 600 Volt AC Circuit. Breaker.. Rating -
paragraph 2.1 i
h
_ _ - _ -__
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APPENDIX 1 PERSDNS CONTACTED Licensee Employees J. Amiri, Nuclear Production Department (NPD) Engineer D. Barnhardt, Maintenance Engineering Services (MES),
Maintenance Supervisor - Mechanical S. Bean, Instrumentation and Electrical (I&E) Supervisor
)
R. Bledsoe, Circuit Breaker Specialist, Transmission Department J
l M. Bouknight, Design Engineer l
l l
- J. Boyle, Superintendent of Integrated Scheduling P. Campbell, Shipping, Receiving an Procurement Supervisor
'
D. Coggins, QC General Supervisor - Nuclear
,
I L. Cole, IAE, General Supervisor l
l L. Cook, IAE General Supervisor i
'
T. Cook, IAE, Supervisor
- G. Copp, Planning and Materials Manager J. Culp, Assistant Operating Engineer
- P. Davies, Quality Control Supervisor
,
'
- J. Day, Compliance, McGuire, Associate Engineer B. Diel, IAE, Maintenance Shift Supervisor C. Drye, Planning and Scheduling Coordinator H. Farr, IAE, Work Group Supervisor K. Fox, Nuclear Production Engineer D. Franks, QA Verification Manager J. Freeze, MES, Engineer D. Gwyn, Performance Engineer B. Hart, General Supervisor - I&E i
S. Hart, Maintenance Engineer
- C. Hendrix, Maintenance Engineering Manager A. Hinson, MES, Support Engineer G. Holbrooks, MES, Associate Engineer - Mechanical A. Hollins, CMD North, Division Manager i
M. Horne, General Supervisor, Nuclear Maintenance - Mechanical j
R. Houser, IAE Calibration Lab Supervisor l
J. Iddings, UMP Operations Supervisor i
K. Johnson, Design Engineer J. Jones, Planning, PM Coordinator i
J. Kissner, IAE, Work Group Supervisor i
K. Louvin, MES, Suppo-t Engineer, I&E I
T. Love, Design Engineer
- T. McConnell, Station Manager S. McCurry, Mechanical Maintenance Instructor P. McHale, Director of Maintenance Training D. Mills, CMD North, Division Manager
'
,
I D. Motes, MES, Support Engineer - Mechanical D. Mustin, MES, Engineer J. Neel, IAE, Work Group Supervisor P. Norcutt, Planning, Maintenance Outage Coordinator T. Oswald, NPD Engineer - Performance i
R. Overcash, General Supervisor Materials j
i I
,
.
Appendix 1
.
M. Pacetti, MES, Engineering Coordinator J. Pring, Project Services Engineer H. Ragland, Planning, Nuclear Production Engineer K. Reece, Units 1 and 2 General Supervisor - Nuclear N:1.tenance - IAE
- R. Rider, Mechanical Maintenance Manager S. Rosenau, MES, NPD Engineer - Mechanical
- M. Sample, Superintendent of Maintenance S. Seo, Nuclear Production Engineer J. Silver, Unit 2 Operations Manager D. Simmons, Materials Support Engineer L. Smith, Planning and Scheduling Coordinator J. Snyder, Performance Manager R. Spittle, Design Engineer B. Suslick, NPD Engineer - Performance B. Travis, Superintendent of Operations M. Vance, IAE Supervisor-F. Walley, MES, MPD Engineer - Mechanical R. Weidler, System Engineering Supervisor M. Weiner, Operations Staff Engineer M. Werner, NPD Engineer - SRO D. White, MES, NPD Engineer - Mechanical
- R. White, Jr., Nuclear Section Manager - I&E
- R. Wilkinson, Station Support Engineer, Transmission Department J. Willis, Operations, QA Director
'
Other licensee employees contacted during this inspection included craftsmen, planners, engineers, operators, mechanics, security force members, technicians, and administrative personnel.
NRC Personnel
- P. VanDoorn, Senior Resident Inspector M. Lesser, Resident Inspector (Catawba)
D. Hood, Project Manager
- T. Cooper, Resident Inspector
- S. Kirslis, Project Management
- Attended Exit Interview on July 28, 1989
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.
.
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APPENDIX 2
!
-
Alternating Current AE0D
-
NRC Office of Analysis and Evaluation cf Operational Data l
Auxiliary Feedwater Pump AFWP
'
-
As' Low As Reasonably Achievable ALARA
' --
A0V Air-0perated Valve
-
-
' Auxiliary Steam System BB
-
Steam Generator Blowdown System CA-Auxiliary Feedwater System
-
Code of Federal Regulations CFR
-
CGI Commercial Grade Item
-
Construction Maintenance Department
.CMD
-
DC Direct Current
-
-
Diesel Generator dp
-
Differential Pressure DPC
-
Duke Power Company EPRI
-
Electric Power Research Institute EQ
-
Equipment Qualification ETQS
-
Employee Training and Qualification System FCR Facility Change Request
-
-
General Employee Training GL
-
NRC Generic Letter GPM
-
Gallon-Per Minute
'HP
-
Health Physics HVAC
-
Heating, Ventilation and Air Conditioning HX
-
Heat Exchanger IAE
-
Instrumentation and Electrical IE
-
Inspection and Enforcement
'
IFI Inspector Followup Item
-
TN
-
NRC Information Notice ihPD
-
Institute of Nuclear Power Operations iP Instrument Procedure
-
KC
-
Component Cooling Water kV Kilovolt
.
-
!
MES Maintenance Engineering Services
-
MMP Maintenance Management Procedure
-
MP Maintenance Procedure
-
NC
-
-
Nondestructive Examination NEMA National Electric Manufacturers Association
-
NI
-
Safety Injection System l
-
Nuclear Production Department;
-
Nnclear Plant Reliability Data System i
Nuclear Management and Resources Council l
-
Chemical and Volume Control System j
NV
-
Operating Experience Program
]
OEP
-
ONSA
-
Operational Nuclear Safety-
,
-
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.
Appendix 2
I Performance Indicator.
-
-
Problem Investigation Report PM Preventive Maintenance.
i
-
Preventive Maintenance Procedure j
PMP-
-
PM/PT Preventive Maintenance / Periodic Test i
-
)
-
PT Performance Test
-
-
Pressurized Water Reactor PZR Pressurizer
-
Quality Assurance QA
-
-
Quality Control RC
-
Regulatory Compliance RCA Radiation Control Area
-
-
Reliability Centered Maintenance I
Rev.
-
Revision RF Fire Protection System
-
RI Receiving Inspection
-
RN-
-
Nuclear Service Water System RWP
-
Radiation Work Permit RWST Refueling Water Storage Tank q
-
-
System Expert SG
-
Steam Generator SM Main Steam System
-
SNSWP Standby Nuclear Service Water Pond
-
SOER Significant Operating Event Report
-
Main Steam Vent to Atmosphere System i
-
TD Turbine Driven
-
VAC-Volts Alternating Current
-
VDC
-
Volts Direct Current VG Diesel Generator Storage (and control) Air System
-
VI Instrument Air System
.
-
VIL
-
Vendor Information Letter WR Work Request
-
YC Control Room Chilled Water System
-
YD
-
Primary Water System
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APPENDIX 3 LICENSEE PROCEDURES REFERENCED / REVIEWED Frocedure Number Title MP/0/A/2002/01 Motor Inspection and Maintenance IP/0/A/3190/01 Preventive Maintenance Inspection and Cleaning MP/0/A/2001/04 Air Circuit Breaker Inspection and Maintenance QCE-1 Quality Control Procedure - Electrical Equip-ment Installation and Maintenance Inspection ETQS Employee Training and Qualifications System Manual IP/0/B/3214/01A Calibration Procedure for Rosemount Series 1151 Smart Pressure Transmitters IP/0/A/3000/19 ICCM-86 Malritenance and Calibration IP/0/A/3000/18 ICCM-86 Programming and Operation IP/0/A/3006/09 Radiation Monitoring System RP-30A Loop Cali-bration PT/1/A/4601/03 Protection System Channel III Functional Test I
IP/0/A/3219/04 Procedure for Corrective Maintenance and Set up
!
of Fisher Type 667 Actuator MP/0/A/7600/82 Fisher Type EC Globe Valve Corrective Mainte-nance IP/0/B/3006/07 Radiation Monitoring System Liquid Monitor Transfer Calibration IP/0/A/3219/03 Setting Stem-Mounted Limit Switches IP/0/B/3250/49 Calibration Procedure for Bailey Characterize-able Pneumatic Positioner Type AP2 IP/0/A/3090/02 Instrument and Electrical Troubleshooting IP/0/A/3061/05 Vital Battery Charger Corrective Maintenance IP/0/A/3061/06 Vital Inverter Corrective Maintenance IP/0/A/3061/06A Inverter Alignment IP/0/A/3061/07 Vital Battery and Terminal Post Inspection
_
.
Appendix 3
.IP/0/A/3061/12 Charging Station Lead-Calcium Batteries PT/0/A/4350/008A 125 VDC Vital I&C Battery Service Test PT/0/A/4350/008B 125 VDC Vital I&C Performance Test PT/0/B/4350/008C 125 VDC Auxiliary Battery Capability Test PT/0/A/4350/008E 125 VDC Vital Charger Performance Test PT/0/A/4350/008F 125 VDC Vital Charger (EVCS) Performance Test PT/1/A/4350/011A Unit 1 125 VDC Diesel Generator Battery Service Test PT/1/A/4350/0118 Unit 1 125 VDC Diesel Generator Battery Per-formance Test PT/2/A/4350/0118 Unit 2 125 VDC Diesel Generator Battery Per-formance Test PT/1/A/4350/011C Unit 1 125 VDC Diesel Generator Battery Charger i
Performance-Test PT/0/A/4350/028A 125 Volt Vital Battery Weekly Inspection PT/0/A/4350/028B 125 Volt Vital Battery Quarterly Inspection PT/0/A/4350/038 125 Volt Vital I&C Battery Service Test PT/0/A/4350/040 125 VDC Vital IAC Battery Performance Test using Alber BCT 1000. Discharge: System PT/0/A/4350/042 125 VDC Vital I&C Charger EVCS Performance Test Radiation Protection Personnel-Contamination Monitoring and Manual (RPM) 11.3 Decontamination Rev. 27, dated 5/5/89 RPM 7.7, Rev. 12, 4/21/89 Radiation. Protection Training - Independent Radiation Worker RPM 2.4, Rev. N/A, 11/21/88 Radiation Work Permits RPM 8.3, Rev. N/A, 12/23/88 Radiological Status and Routine Surveys Administrative Policy Control of Materials, Parts, and Components Manual Chapter 2.4, Rev. 27
- - _ _ _ _ - - _ - _.
._.
. _ _.
_
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!
Appendix 3
Station Directive 2.4.4, Procurement Determinations Rev.'1 Material Handling Procedure Requisitions for Materials of Services (MHP) 1.2, Rev. 13 MHP 2.1, Rev. 13 Receipt, Inspection, and Control of -Stores Stock, Capital Stock and Non-Stock Items MHP 3.2, Rev. O Shelf Life Program-MHP 5.2, Rev. 8 Issuing Stock and Non-Stock Materials Returning Unused Stock ar.d Non-Stock QA-500, Rev. 20 Quality Assurance Surveillance Program QA-515, Rev. 3 Operations Division Tour Surveillance QC A-2, Rev. 6 QA Condition 2 Inspection Requirements QC A-3, Rev. 5 QA Condition 3 Inspection Requirements QC A-4, Rev. 4 QA Condition 4 Inspection Requirements QC E-1, Rev. 13 Electrical Equipment'
Installation and Maintenance QC E-2, Rev. 13 Instrumentation Installation, Modification Inspections QC F-4, Rev. 4 Mechanical Equipment Inspection QC F-5, Rev. 5 Valve Disassembly and Assembly Inspection and Other Miscellaneous Valve Work PT/0/A/4601/08B PM/PT - Functional Test SSPS Train-13 IP/0/A/3190/03 PM - 600 V Circuit Breaker Trip Function Test IA/4350/03A Bus Voltage PT/2A/4350/09A PM - Circuit Breaker Trip Function Test IP/0/A/3090/02 IAE Troubleshooting MP/0/A/2004/1 Doble Testing-IP/1/A/3952/01 Indicating AC Voltmeter MP/0/A/2001/04 Air Circuit Breaker Inspection and Maintenance I
o
.
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Appendix 3
i MP/0/8/7300/03 (5/30/89)
Air Compressor - Preventive Maintenance
-l MP/0/A/7300/30 (12/9/88)
Instrument Air Type Compressor CENTAC Type Oil Sampling and Oil Change Procedure MP/0/A/7300/01(4/3/89)
Rotating Equipment - Preventive Maintenance
)
i MP/0/A/7450/04 (2/6/89)
Control Room Chiller _ Preventive Maintenance
.j
)
MP/0/B/7650/09 (3/17/89)
Ignition Sources (Cutting, Welding, Grinding, i
Bolt-Heating, and Open Flame Safety)
MP/0/A/7650/52 (8/5/88)
Controlling Procedure for Piping Modifications Mechanical-Manual, Use of Procedures Section 5.0
Admin. Policy 2.1 Document Control
)
Admin. Policy 2.1.4 Vendor Documents Admin. Policy 2.1.13 Modification Manual Admin. Policy 3.3 Maintenance Admin. Policy 3.3.5 Maintenance-Documentation
.1 Admin. Policy 3.4 Modifications I
Admin. Policy 3.4.5 Modification Documentation Station Directive 2.0.13 System Expert Program Station Directive 3.1.7 McGuire Action Director (MAD)
Station Directive 3.1.29 Outage Management Program Station Directive 3.1.35 Plant Labeling Station Directive 3.2.2 Identifying and Performing Plant Retesting j
Station Directive 3.3.4 Relief From Hydrostatic Testing l
<
!
-Station Directive 3.3.10 Rotating Equipment Monitoring ~ Program
~!
Station Directive 3.11.0 Housekeeping and Cleanliness i
Station Directive 3.11.1 Housekeeping and Material Conditions i
Station Directive 4.7.0 Control of the Maintenance Program
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- - -
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w
.
Appendix 3:
Maintenance Management Definition of the Work Request. Form Procedure (MMP) 1.0'
MMP 1.1-Emergency Work Requests MMP 1.2~
Maintenance Support Work Requests MMP 1.4 Lost Work Requests
.MMP 1.6-Maintenance Activities Associated With Func-tional Verification MMP 2.1 Daily Schedule MMP 2.2 Shift Schedule MMP.3.3 Equipment Failure Analysis-MMP 3.5 Failed Surveillance Analyses MMP 3.6 Root Cause Failure Analyses MMP 4.0 Definition of-the Preventive. Maintenance Program-MMP 4.1 Predictive Maintenance-and Monitoring Program Duke Power Company ASME Section XI Manual, Section A, Revision 0 (November 30, 1988)
McGuire Nuclear Stat'on Maintenance Welding Program Manual i
Section Revision Title I
Maintenance Welding Procedure for Identification and Control of Class a, B, C, E, and F Piping II
Maintenance Welding Procedure for Class G and H Piping III 6-Maintenance Welding Procedure for Heat Treatment of Welds.
IV
Maintenance Welding Procedure for welder and Welding
'
Operator Certification
-
V
Maintenance Welding Procedure for. Structural ' Steel and Miscellaneous Steel VI
Maintenance Welding Procedure for Marking and Stamping Welds
_ _ _ - - _ _ _ _ _ _ _.
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- _ -
i
.
O Appendix 3
i VII
Duke Power Construction Department Welding Program
'
VIII
Maintenance Welding Procedure for Station Additions to the Welding Program IX
Welder Performance Cross Qualification List i
X
Maintenance Welding Procedure for Control and Care of Safety-Related Welding Electrodes in the Field i
gek'a Power Company Welding Program Process Specification L-200 for Gas Tungsten Arc Welding (August 19, 1987)
i l
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)
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e.
APPENDIX 4 WORK REQUESTS REVIEWED
'
WR Number Description
WR 050566 PM safety injection pump. motor IA
!
WR 065235 PM safety injec. tion pump motor 2B j
.WR 028529 PM-safety injection pump moter 1A WR 034226
.PM safety injection pump motor 2B
'WR 028505-Doble test 4.16 kV switchgear group.IETA WR.01241A PT PM/PT containment' hydrogen' analyzer - A Train l
WR 066358 PM 4.16 kV switchgear group IETA WR 066317 Doble test 4.16 kV switchgear group IETA
,
WR 050629 PM 6.9 kV switchgear group ITA WR 028534 PM 4.16 kV switchgear group IETA WR 01645A Verify and scale items in computer ICCM-86 for 2E1ACA9220 WR 01458A Calibrate flow transmitter 2MRNFT5371 WR 01450A Perform loop calibration for loop RP-30A WR 01519A Perform functional test for RPS channel 3
,
WR 301221 Perform corrective maintenance and set up of Fisher type 667:
actuator WR 43107 Perform radiation monitoring syst'em liquid monitor transfer l
'
calibration WR 501186
. Repair, adjust and calibrate instrumentation for atmospheric dump valve - Unit 2 i
WR 01247A Perform weekly test (PT) for battery EVCA
!
!
WR 01248A Perform weekly test. (PT) for battery EVCB i
WR 01249A Perform weekly test (PT) for battery EVCC
!
i WR 01250A Perform weekly test (PT) for battery EVCD
'
WR 099234 Perform quarterly' test (PT) for b'attery EVCD
'
'WR 501186 Repair valve leak i
'
)
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.
l;.
Appendix 4'
WR 94617 Repair chlorine detector circuit boards -
WR 131886 Repair static inverter IEVIC WR 68990 Repair battery charger for EVCC'
WR 68965 Replace capacitors in battery'. charger WR 68684 Repair ICCM 1B plasma display WR 136225 Repair Train A ICCS.
i WR'133972 Repair annunciator panel LAM 2 WR 137078 Repair battery EVCD ground WR 953540 Test connection on recirculation line at valve ICA32B
-
WR 95428 Part of_NSM 1402, Rev. 0 (Steam Generator 810wdown) MBB WR 01100A Vibration reading on TD CA pump (PM 3676) MP 0/A/7300/01
'
PT 1/A/4252/01 Pump Performance Test on Turbine Driven CA Pump _ (Unit 1)~
WR 138971 Troubleshooting' control switch for 2CA-15A WR 500286 Cleaning and repacking valve 2CA-25 -
WR 96539 Rewire valve position circuitry for CA throttle valves.
WR 138951 WR voided, deficiency tag 001459 (walkdown)
\\
WR 88765 Repair packing leak on 2RN-69A (walkdown)
WR 137067 Scaffold removal step on-WR not completed (walkdown)
WR 96675 Replace valve ICA-45 WR 95159 PM/PT on Motor Driven CA pump A-
~
WR 138382 Troubleshoot TO CA~ Pump #1 suction flow indication-i WR 137146 Repair selector swicch for-ICA-98
~
Transformer-1ELXF gas pressure is low WR'133724 IB DG lube oil heater. breaker chattering
i i
WR 88250 2EMXF-F2A breaker failed to shunt trip WR 95950 Verify proper phasing-and voltage for MCCs 2EMXB1/2/3 I
l i
,
,
.o Appendix 4
.3:
'WR 68647.
' Install fuse block'and fuse in 2EMXA WR 137628 Failed breaker at LC 1ELXD
.
WR 69001 Replace breaker'in IEMXC, compt SE WR 69072-.
Replace 90-amp breaker in 2EMXD, compt 6E WR 69073 Replace 150-amp-breaker in IEMXB, compt 6E WR 69074 Replace 100-amp breaker in 2EMXC, compt 3D l
WR 69076 Replace 90-amp breaker in 2EMXC, compt 6D WR 69175 Replace 40-amp breaker in 2EMXD4A l
WR 076667 PM on 600-V ground monitor protective relaying
WR 083559 PM on 600-V LC IELXD breakers WR 083923 PM on 600-V LC IELXB' breakers
'WR 095579 PM on 600-V LC 2ELXA breakers
-)
i WR 95263 Replace PCB filled Cts on IEPDME circuit breakers WR 132665-Breaker on ILXC' fails to auto close WR 95349 Replace indication lights on 2LXD, compt SC WR 95462 Increase breaker trip unit to 225 amps
WR 134278 Ground on 2LXC WR 134405 Ground on 2LXC WR 135120 Feeder ' reaker on ISLXA fails to close in manual u
WR 136017 Transformer 2SLXC has low gas presse:s l
WR 136859 Repair handle on "A" brg. cooling water pump WR 137637
' Transformer ILXF has lcw gas pressure l
i WR 138753 600-V load center trouble I
WR 076676 PM on load center ISLXF breakers
!
,
!
WR 076795 PM on load center ISLXH breakers l
WR 099577 PM on air compre.ssor controls
j
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.
-Appendix 4
WR 88530 Investigate and repair valve 2RN190 actuator binding
- WR 138483'
Repair / replace loose handwheel on valve IRN174 WR 138403 Investigate and repair valve IRN171 which wf11 not indicate closed WR 128897
. Inspect RN strainer 2A internals WR.500064.
Cut out, repair and replace valve 2RN235 WR 136955 Repair capability of valve IRN190 to be manually opened from control room WR 501365 Replace RN strainer 2B packing WR 136402 Change bearing oil in RN pump 18 WR 136451 Repair valve IRN174' to correct seat leak 'and loose handwheel WR 88604 Clean RN/KC Hx 2A by rodding out WR 136167 Repair valve 2RN89 to correct binding WR 88591 Repair. valve 2RN89 to indicate and permit stroking with pump
>
off WR 135139 Repair valve IRN73 seat leakage WR 500872 Adjust valve 2RN235 travel stops to permit' valve closure WR 88706 Investigate slow stroke time for valve IRN89 WR 133647 Inspect lines for clams through valve 2RN113 WR 500187 Inspect check valve 2RN30 for flow induced wear WR 500186 Inspect check valve 2RN28 for flow induced wear WR 88095 Replace inoperable valve 2RN141 WR 134315 Inspect RN piping for clams through valve IRN880 WR 135814 Repair capability of valve IRN89 to be manu' lly operated a
from the control room WR 134533 Repair valve 2RN174 seat leakage WR 132951 Inspect and repair IB RN pump for degraded flow
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O-
- 6 Appendix 4
4 WR 092516 Perform PM oil analysis on RN pump and motor 1A WR 093046 Perform PM on RN pump 28 -
WR 071187 Rod out'HX tubes of RNIA motor cooler-WR 070868 Perform PM oil analysis on RN pump _ motor IB WR 071591-Perform PM on RN pump 1A-WR 094394 Perform PM on RN pump IB WR 093582 Perform PM oil-analysis-on RN pump and motor 2A WR 095895 Adjust valve IRN89 travel stops to perform super-flush WR 095793, Adjust valve 2RN190 travel-stops to perform super flush'
WR 096014 Perform PM oil analysis on RN pump and moter 2B WR 094421 Perform PM oil analysis on RN. pump'and motor IB WR 092920 Rod out tubes'of KC 2A HX WR 502252 Repair. bent needle on mix bed demineralized upstream pressure gage WR 502255 Replace missing rod on rod hanger located south of valve 2N1-808 WR 138442 Repair seat leakage on valve 2BW-13 WR 532105 Rebuild rotating element removed from 103 heater. drain tank pump WR 501186 Repair seat leakage on atmospheric steam dup valve 2SV-40 WR 96281 Replace pressure switch 2KDTS5320 with United Electric model F-400-7BS-20 FT WR 953539 Install test ' connections on each side of. motor driven auxiliary feedwater pump' recirculation valve ICA27A WR 953540 Install test connections, on each side of-motor driven auxiliary-feedwater pump recirculation valve ICA32B
,
WR 128021 Repair reason why
"D" VI compressor seems to not-load properly WR 127923 Investigate and repair as necessary "D" VI compressor not loading
,
]
,
...
Appendix 4
WR 127214 Investigate and repair cause of low water flow alarm on "D" VI compressor WR 131053 Identify cause of _ surging and. repair
"D" VI compressor -
surges WR 134238 Check and/or repair IDPF n; itch on "D" VI compressor WR 136416 Investigate reason "D" VI compressor will not start-WR 501693 Replace pneumatic positioners on CENTAC air compressor inlet-positioner WR 138354 Repair leaking oil ~ pressure gage on "D" VI compressor WR 138571 Investigate reason for
"D" VI compressor compression trapping WR 131378 Replace drain valve on air dryers OMVI AD 009, 10, 11 and 12 WR 128294 Investigate and repair as necessary compressor.on light on
"B" VI dryer WR 127528 Repair " compressor on" light socket on the B VI d'yer r
WR 131378 Replace drain valve on' water traps on' VI dryers OMVI AD 0009, 10, 11 and 12 WR 131994 Investigate and repair trip-L-~ trap on "B" VI dryer WR 132197 Investigate and repair as necessary "C" VI dryer compressor not running WR 127959 Investigate and correct compressor trips on "D" VI air dryer WR 132066 Repair VI dryer'"D" WR 138499 Repair or replace controller assembly on first stage inlet to "D" VI compressor WR 138660 Repair ruptured diaphragm.inside pressure switch WR 138712 Repair HP station air compressor l"A" so-that it does not leak oil l
WR 138058 Repair leak on menuel drain valve on "B" VI tank WR 88804 Fail air to YC valves and verify they fail open. Sixteen valves total to verify.
-
--
O Appendix 4
NSM No.
Description MG00299 Add wattmeters for PZR heater power drain MG00903 Replace Westinghouse circuit breakers MG01065 Revise power feeder from SSF to MCC IEMXH-1 MG01223 Replace trip overload heaters on 600-V power system MG01303 Add interposing relay to size 3 and 4 starters MG01311 Connect jumper wires on PZR heater group breaker MG12262 Revise IEMXB1/2/3 feeder circuits MG20177 Remove overload heaters in 2EMXA-4,
-5, and spare i
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