IR 05000348/1989010
| ML20248C814 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 07/27/1989 |
| From: | Gibson A, Julian C, Kleinsorge W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248C808 | List: |
| References | |
| 50-348-89-10, 50-364-89-10, NUDOCS 8908100161 | |
| Download: ML20248C814 (123) | |
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p UNITED STATES j *utuq'o NUCLEAR REGULATORY COMMISSION
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h, REGION 11 J.
j 101 MARIETTA STREET,N.W.
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4 e ATLANTA, GEORGI A 30323
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Report Nos.: 50-348/89-10 and 50-364/89-10 Licensee:
Alabama Power Company 600 North 18th Street Birmingham, AL 35291-0400 Docket Nos.:
50-348 and 50-364 License Nos.:
NPF-2 and NPF-8 Facility Name:
Farley Nuclear Plant, Units 1 and 2 Inspection Conducted:
April 24-27 and May 8-12, 1989 7/7
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Inspectors: (
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C. A. JuliaA, ~ Am anager
/Date 5fgned Engineerin Divi '9j' g ati F.>dfrSafety 7 /7 sy f
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W.W. M einsorge, P.
,'leam sader N Uate Signed Team Members:
8. Crowley P. Fillig.
E. Girara G. Ha11strom M. Lauer
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M. Miller W. Ruland
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Approved by:
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pt-A. F. Gibson
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Date Signed Director
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Division of Reactor Safety 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 inspectier>
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Results:
Overall, the maintenance program was judged to be SATISFACTORY with GOOD implementation.
Areas of strength and weakness are highlighted in the Executive Summary with details provided in the report.
One violation was identified.
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,1 One unresolved item was identified related to adequacy of Vendor Drawing Manual
. Control Program (see Section B.6).
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i TABLE OF CONTENTS
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APPROVAL PAGE
l A.
Executive Summary
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l B.
Inspection Areas
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1.
Service Water System...........
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2.
Containment Spray System................................
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4160 AC Volt Distribution System........................
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125 Vo'lt DC Distribution System.........................
5.
Instrument Air System.........................
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6.
Maintenance Work Observation.............................
7.
Material Contro1.........................................
8.
Instrument Calibration Program...........................
9.
Health Physics...........................................
10.
Maintenance Facilities...................................
11.
Response to Industry Issues................
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Maintenance Work Management..............................
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Maintenance Personne1....................................
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Motor Operated Valve Program............................
15.
QA/QC Involvement in Maintenance.........................
16.
Engineering Support for Maintenance.................
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17.
Maintenance Related Data.................................
18.
Maintenance Self Assessment....................
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C.
Issues............................................................
1.
Calibration of DC Circuit Breakers.......................
2.
Motor Opetated Valve Problems..
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3.
Quality of Instrument Air................................
4.
Emergency Air Compressors................................
5.
Maintenance Procedures.....................
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6.
Housekeeping and Material Condition......................
7.
Bolted Thread Engagement..
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B.
ASME Section XI Procedure Interface......................
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Re v e r s ed Fi nw 0 ri f i c e s...................................
10.
Industrial Safety....
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11.
Maintenance Prioritization
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12.
Systems Engineering....
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Heat Exchanger Performance Monitoring...............
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D.
Evaluation of Plant Maintenance Inspection Tree.......
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1. Overall Plant Performance Related to Maintenance..
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1.0 Direct Measures...
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II. Management Support of Maintenance............................
84-L 2.0 Management Commitment and Invo1vement'...................
3.0 Management Organization and Administration..............
4.0 f e c hn i c a l. S up po rt.......................................
III. Maintenance Implementation..................................
5.0 Work Contral...........................................
6.0 Plant Me, atsnance Organization..............
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7.0 Maintent ce Facilities, Equipment and Materials Control
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8.0 Personnel Control......................................
E.
Followup on NRC Information Notice 87-44 and NRC Bulletin 88-09 -
Thimble Tube Thinning in Westinghouse Reactors...................
F.
Followup on Previous Inspection Findings...........................
G.
Exit Interview....................................................
APPENDICES Appendix 1, Persons Contacted Appendix 2, Acronyms and Initialisms Appendix 3, Proceduras Reviewed Appendix 4, Maintenance Work Requests Reviewed Figure 1, Maintenu..ce Inspection Tree
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EXECUTIVE
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EXECUTIVE SUMMARY
l Background a
The Nuclear Regulatory Commission (NRC) considers effective maintenance of i
equipment and components a major aspect of ensuring safe nuclear plant l
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 strectures of nuclear power plants be mcintained so that plant equipment will perform its intended function when required.
To accomplish this objective, each licensee should develop and imp 12 ment a maintenance program which provides for the periodic ev;:uation, and prcmpt repair of plant components, systems, and structures to ensure their availability."
. To ensure effective implementation of the Commissic7's maintenance policy, the NRC staff is undertaking a major program to inspect and evaluate the effectiveness of licensee maintenance activities. As part of this inspection activity, the current inspeccion 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 was designed to ensure that all factort related to maintenance are evaluated.
Conduct of Inspecticn The maintenance inspection at the Farley Nuclear Plant (FNP) was initiated wiuh a site meeting on April 10-14, 1989, where the inspection scope was discussed.
In addition, a comprehensive package of material, as requested by NRC le6ter dated April 6, 1989, was provided for inspection preparation.
The inspection was conducted by a team consisting of a Team Manager, a Team Leader and eight inspectors. On April 24, 1989, the licensee presented to the inspection team an overview of the site maintenance program.
The team spent two weeks, April 24-28 and May 8-12, 1989, on site conducting the inspection.
The inspection was performance based, directed toward evaluation of equipment conditions; observation of in process maintenance activities; review of equipment histories and records; and evaluation of performance indicators, j
maintenance control procedures and the overall maintenance program.
Maintenance activities were selected for detail review by the team using the following criteria:
Known industry problems
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Review of LERs - site specific problems
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Review of NRC Bulletins and Notices Review of Plant Maintenance History
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Consultation with the Senior Resident Inspector
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Probabilistic Risk Assessment Analysis
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Based 'on the above selection criteria, the following specific systems were selected for direct inspection effort:
Containment Spray System (CS)
Service Water System (SW)
4160 Volt Distribution System (Normal and Emergency)
Instrument Air System (IA)
125 Volt DC Distribution System 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 mainte-nance program were evaluated:
(1) Overall Plant Performance Related to Maintenance, (2) Management Support of Maintenance, and (3) Maintenance Implementation.
Under each major area, a number of elements were evaluated, rated, and colored in accordance with the folicwing guidelines:
" GOOD" Performance (Green)
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Overall, better than adequate; shows more than minimal effort; can have a few minor areas that need improvement
" SATISFACTORY" Performance Adequate, weaknesses may exist, could be
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(Yellow)
strengthened
" POOR" Performance (Red)
Inadequate or missing
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(Blue)
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Not evaluated In general, the top half of the box (element} was rated depending on how well the element had been specified programmatically and the bottom half was rated depending on how well the element was being implemented. As noted in the tree, overall, the Farley program for establishing an effective maintenance program was rated S/TISFACTORY. The implementation of the program was rated GOOD. For tne three major areas; (1) Overall Plant Performance was rated SAilSFACTORY, (2) Management Support was rated P00R for program and GOOD for implementation, (3) Maintenance implementation was rated SATISFACTORY for program and GOOD for implementation. These ratings were based on specific strengths and weaknesses identified in the issues section of the report. The following are the more significant strengths and weaknesses identified (see report for details):
Strengths:
1.
The I&C calibration lab is a professional, well run shop.
2.
The Health Physics and ALARA program in support of maintenance is a strength.
3.
FNP shops and maintenance facilities are a strength.
4.
Spare parts and material control are a strength.
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Maintenance training is good.
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FNP maintenance staff is competent and dedicated with high morale and low turnover.
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There is direct involvement of maintenance foremen during important steps of -the work which provides a sense of responsibility to see that work is done correctly.
8.
FNP has a good program for monitoring and treating the Service Water System for asiatic clams.
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The instrument calibration sticker program could become a strength but it is not being actively extended to all plant instruments.
Weaknesses:
1.
Engineering support for maintenance is a weakness due to marginal engineer i
staffing.
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QC is not doing sebected independent observations of the peer inspection process. This is possibly due to marginal staffing.
3.
Peer inspectors are not required to have an annual eye exam or to be decertified if they don't perform peer inspections for a year.
4.
There is very sparse use of independer.t inspection (I) points in maintenance procedures and even in the newly upgraded maintenance procedures recently issued.
5.
FNP program for handling industry operating experience exist but is slow in getting final resolution of issues and there is no procedural guidance for timeliness.
6.
Maintenance planning is marginally staffed and does not research all outstanding Temporary Change Notices (TCNs) while planning s job but leaves that function to the crafts 7.
Many Maintenance Work Request (MWR) cause and failure code blocks are being filled out incorrectly so the data is not useful for trending.
Also, MWR description of work performed is often sketchy so it does not provide a clear picture of work history.
NRC Concerns 1.
The examples of the violation cited are an indicator that maintenance workers at FNP do not have strong regard for the requirement to work in accordance with approved procedures.
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FNP has no documented guidance on post-maintenance testing. It is left up i
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Test (PMT) is appropriate.
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FNP maintenance staff works a lot of overtime during outages and appears to exceed the intent of the NRC overtime guidance in Generic Letter 82-16.
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The FNP maintenance program has little or no written guidance for maintenance management, but relies heavily on an experienced staff making correct judgements.
Future problems could result d. f FNP begins to experience staff turnover.
Many of the weaknesses identified had been identified by the licentre prior to the inspection.
The licensee had previously conducted a Maintenance Self Assessment, and had instituted corrective action cn identified recommendations.
Corrective actions were not all complete and/or effective however.
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SECTION B
INSFECTION c
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. Service Water System
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Background L
The Sarvice Water (SW) System provides cooling water from the SW pond to
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various heat 'exchangers that must be cooled for safe plant operation I
during normal and accident conditions.
It is a safety-related system.
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SW System flow is produced by SW pumps which take suction from ths SW l
pond through screens (to limit debris in the water) and a wet pit. A small l-amount of the discharge from the pump is diverted through strainers and back to the pumps for cooling and lubrication.
The remainder passes through coarte strainers and then through piping to the plant loads.
Examples of plant loads include the Component Cooling Water (CCW) Heat exchangers (HXs), Diesel Generators (DGs), pump room coolers, turbine exciter cooling units, and containment coolers. The SW from these heat leads is collected in a SW return header from which it may be distributed to the river, circulating water canal, pond fiume or SW wet pit.
A Chlorination system adds chlorine dioxide (C10 ) to the SW to reduce HX
fouling caused by organisms such as Asiatic clams.
Inspection The team's inspection of the SW System included a walkdown inspection of the system, review of historical maintenance data, examination of pump test data trending and assessment, and review of a HX performance monitoring program.
The 'stter is described in C.13 below.
In their walkdown inspection, the team msde the following observations:
Excessive water was observed in the Service Water Intake Structure
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(SWIS) which appeared to be principally the result of leakage from strainers and pumps.
Leaks were also noted at fire water valves.
Although the licensee had requirements for periodic infoection of the facility, the excessive leakage had not been corrected. The leakage dic not appear to represent any concern with re;ard to the currer.t I
operability of the equipment involved.
Several apparent pin hole leaks were observed in small diameter
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stainless steel piping - an indication of the probable preserce of Microbiologically induced Corrosion (MIC).
The licensee had not previously observed MIC in stainless steel piping and did not have a i
program in place to identify or preclude its degrading effects.
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While examining Unit 2 containment coolers, the team observed two workers dressed in prctective clothing and respirators lying down (resting) in the containment. This matter is discussed fLrther in Sections B.9 and C.10.
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L Jn their review of SW System historical data, the team examined 20 MWRs
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completed in the last two years. These MWRs involved pump evaluations 'and
. repairs, valve repairs, a flow element repair and a strainer repair, from the above review, the team found:
The 'MRs were readily available from the licensee's data base and
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(based on a check of 10) associated complete documentation was readily available on microfilm.
L Most MWR data entries appeared correct tr.d indicated correctly
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performed maintenance in accordance with procedure AP-52.
An exception to correct entries was the entry of cause codes which were
.so inaccurately entered as to make them useless icr trending.
Post-maintenance testing appeared very limited.
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testing mandated by regulation was shown to be performed.
This 1s-discussed further in Section B.12.
From a review of the above MWRs and a more extensive listing for the
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SW System, there appeared to be few examples of instances where repairs were incorrectly performed such that repeat failures occurred.
Having noted a number of evaluations of pump flow and vibration among the SW MWRs, the team reviewed pump performance data' evaluations and trending with Systems Performance Group personnel responsible for. these matters.
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l Evaluations examined included those contained in the above MWRs plus a detailed evo.uation described' in an April - 2, 1986, memorandum from R. Berryhill (Systems Performance) to R. Hill.
Trending examined was principally computer trending of SW pump vibration measurements performed during 1988. Both ASME Section XI and other more sophisticated vibration test data were observed to be trended.
The team's findings were as follows:
The evaluations, appeared well-based and generally conservative.
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Recommendations were appropriate.
P mp test data appeared appropriately trended. However, there was an
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excessive delay between the performance of pump tests required by ASME Section XI and the trending of the data. When the team noted i
that trending did not include recent ciata, they were informed that SW data had not been received since September 1988, over seven months.
l Later, the team was informed that this was inaccurate, that the delay was only three to four months. Licensee management acknowledged that this delay was excessive. They stated they had been aware of the excessive delays and thought they had been corrected. The team did not consider the delay in trending the ASME data to be of major significance as the licensee had prompt trending of apparently superior vibration test data frcr. separate maintenance vibration testing that was performed monthly.
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Farley has experienced many' problems with the heat exchangers, both water / air and water / water, that are served. by the SW System. These problems included:
SW flow reduction or stoppage resulting from silting, corrosive product buildus biofouling, and Corbicula macro invertebrate (Asiatic clams); airflow reduction resulting from air side fouling and leaks resulting from general corrosion, MIC, and seal and gasket failure. To combat ioese problems, the licensee has instituted several programs including:
chemical treatment of Sh; performance testing of safety-related room coolers; operational data monitoring of water / water heat exchangers; and maintenance bi-weekly area inspections.
The treatment of the SW System at Farley Nuclear Plant (FNP) consists of two methodologies. Both treatment processes are carried out on a permanent basis year round.
The treatment of service water to prevent fouling of plant components is performed by injection of C102 at the SW intakes for Units 1 and/or 2.
Routine chlorination periods for Units I and 2 SW are performed at one hour intervals three times per day.
The second approach of the service water treatment process is a permanent program initiated for Corbicula control. This process can only be performed on a single unit at a time, and is performed every eight weeks on an alternating basis between the units.
Corbicula control treatment of the designated unit and routine C10, treatment of the nondesignated unit can be performed simultaneously.
Sodium hypochlorite (15% by volume) is the chemical used for Corbicula treatment. Sodium hypochlorite is injected via a chemical addition pump into the C10 solution line of the designated unit.
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process is continuous for a period not to exceed eight weeks or until greater than 90% clam mortality has occurred in test aquariums. At this point, 51orination for Corbicula control of designated unit is complete and preparation for treatment of the other unit is begun.
Farley's service water treatment program has been effective in controlling both.biotouling and Corbicula. The licensee's program is documented, and in place for site activities only. The activities of the Alabama Power Company (APC) Central Laborato ry were not proceduralized. The licensee has, as a result of this inspection,
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l amended procedure Nos. FNP-0-CCP-201, FNP-0-CCP-20? and FNP-0-CCP-523 l
to assure programmatic continuity of the Corbicula Control Program.
The licensee's program for performance testing of safety-related room coolers is implemented by procedure FNP-ETP-4306.
Pe rformance
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testing of room coolers has been a formalized program for less than a year.
The licensee has performed some feasibility testing (two to
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five tests per cooler), over the past two years, at the direction of the Systems Performance and Planning Manager.
The room cooler l
performance testing program is innovative on the part of the
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licensee.
However, there appears to be rome question as to its applicability with changing input parameters as well as to the j
agreement of output data with the Final Safety Analysis Report. This matter is discussed further in Section C.13.
The operations personnel periodically record observed flow, p' essure and differential pressure. These observations are made at four hour intervals and documented on daily log theets, which means that no l
more than six date points, for each parameter / component are available for review at any one time. The monitored components are:
CCW HXs; charging pump oil coolers; service water strainers; and spent fuel heat exchangers.
Some, but not all of the instruments used to monitor these parameters are included in the licensee's calibration program.
The calibration of instruments is further discussed in Section B.8.
Although, there is no trending over time of the above operational data and some of the instruments are not maintained in calibration, no adverse HX's performance indicators were noted by the team.
The maintenance bi-weekly area inspections were noted by the team to be somewhat less than effective. This matter is discussed further in Section C.6.
2.
Containment Spray System Backoround 1The Containment Spray (CS) System, an Engineered Safety Feature, reduces airborne fission product concentration and pressure in containment following a Loss-of-Coolant Accident (LOCA). The system consists of two redundant subsystems and a common spray additive tank. Each subsystem has a pump, spray ring header, and the required piping and valves. The pumps normally take suction from the Refueling Water Storage Tank (RWST). Upon low-low level in the RUST, the system is manually aligned to take suction from the containment sump. A portion of flow from each pump discharges through an eductor where sodium hydroxide is drawn in and returned to the pump suction, thus introducing the sodium hydroxide into the spray' water.
During a LOCA, the water and sodium hydroxide mixture is sprayed into the containment atmosphere providing cooling and thus depressurization of the containment atomosphere. The sodium hydroxide improves the reme"al of radionuclides from the containment atmosphere by chemically absorbing gaseous iodine out of the atmosphere.
Inspection The team evaluated maintenance relative to the CS Systems (Units 1 and 2)
by performing a walkdown inspection of the systems, observing in process maintenance, and reviewing maintenance history records.
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In addition to examination of housekeeping in the various equipment spaces, general CS ecuipment condition was examined.
Pumps, valves (including operators), piping,. supports, and foundations were inspected l
for ' general condition and cleanliness, leaks (water, oil, and grease),
proper bolting, proper electrical connections- (MOVs and pump motors),
rust / preservation, lubrication,- dirt / trash, etc.
The. Team also observed the following in process maintenance for the CS L
Systems:
MWR 194251'- PM disassembly, inspection, and re-assembly of~3" spray
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additive check valve Q2E13-V007A MWR 166599 - Re-termination (including RAYCHEM connections) of valve l
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02E13-V005 (8820A) - in accordance with procedures FNP-0-MP-91.1, Rev. 4, FNP-0-ETP-4251, Rev. 4, and i'NP-0-GMP-27, Rev. 6 For the in process maintenance, the team examined procedure and drawing compliance,. use' of knowledgeable and ' qualified maintenance personnel, sign-offs, use of correct materials, use of calibrated tools, HP coverage, etc.
The in process MWRs were revicwed for compliance with applicable procedures.
The team examined maintenance histories for the CS Systems by reviewing a list consisting of MWR numbers and brief descriptions for all MWRs issued for the' systems.
CS MWRs selected for detailed review are listed in Appendix 4 The above inspections, observations, and record reviews revealed the following:
In general, housekeeping and cleanliness was found to be average.
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Poor housekeeping was identified in one area (Unit I spray additive
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tank area). General debris and dirt existed under and around the tank. The stainless steel piping around the tank was spotted with white paint from sloppy painting.
Housekeeping in this area was improved during the course of the inspection.
In addition, surface rust / caked boron and a loose 1" blank flange was noted under the CS 1A pump motor. These conditions were corrected during the course of the inspection.
The general equipment condition was considered average.
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significant number of leaks or evidence of leaks (boron or sodium hydroxide buildup) were identified.
For example, the following equipment on Unit I showed evidence of leaks:
Valve Q1E13-V005A Room Cooler leaking service water on valve 01E13-V005A L
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Valve Q1E13-V012A Valve Q1E13-V004A (MWR 193405)
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Valve 01E13-V004B Serv'ce Water Valves to Room Coolers in Pump Room IB rusty and leaking (Deficiency Tagged)
Spray Additive Recirc Pump NIE13-P002-N Valve Q1E13-V024 (Deficiency Tagged)
Valve 01E13-V021B oil leak (MOV)
Valve Q1E13-V021A i
CS Pump 2A shaft seal leak Similar deficiencies were observed on Unit 2 CS System. The majority of the apparent leaks had not been identified (no deficiency tag or MWR issued) by the licensee. Based on the number of apparent leaks, the team questioned the licensee relative to whether the systems could meet required flow rates i' called upon.
The licensee provided completed copies of Engineering technical Procedures FNP-1-ETP-240, Rev. 3 and FNP.2-ETP-253, Rev. 4, which quantified the leakage for the systems during recirculation flow test. These procedures are performed once each fuel cycle and provide some assurance that required flows can be met.
During walkdown of the CS systems, the team noted a number of flanged
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pipe joints with questionable bolting thread engagement.
See Section C.7 below for 6 tails of this problem.
During re-termination of Valve Q2E13-V005A under MWR 166599, the
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electrician was required to connect control wiring and verify to be correct per the connection diagram.
During connection, the electrician found that the control wiring could not be connected in accordance with the connection diagram furnished with the MWR since a jumper wire had been installed on the switch (the operator had been refurbished) that did not show on the diagram and another wire could not be connected as shown on the diagram. The electrician noted that the drawing had been stamped with an outstanding PCN. The PCN had chuaged the connection diagram.
However, the PCN had not been identified in the MWR package, other than being referenced on the drawing, and the electrician had not researched the outstanding PCNs referenced on the drawing to determine if the outstanding PCNs affected the work he was doing.
In discussing this problem with licensee personnel, it was determined the job was not planned by electrical planners since the MWR was written for mechanical repair to the valve.
It was further determined that, by the licensee's program, it was up to the electrician to research outstanding PCNs to
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determine if they affect what he is working on. Some PCNs are very voluminous and it' doesn't seem appropriate to have the craft responsible for researching PCNs to determine if the PCN~affects the work... It appears this should more appropriate 1y' be the responsibility of the planner. This appears-to be a weakness in the planning process, probably a result of the small planning staff (see Section 8.12).
Ouring review of completed MWRs, the team noted that the
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Failure /Cause codes (blocks 40 through 43) are not being used effectively.
For the majority of the completed MWRs listed above, blocks 42 and 43 were marked "N/A" or " Unknown" for the "Cause of Failure" and "Cause Description" codes. This poor use of Cause Codes renders. the information of minimal use for failure analysis and trending of equipment failures (see paragraph B.12 for further discussion on tnis subject).
The team found Flow Element FE 949 for Unit 2 Spray Additive Tank
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flow orifice installed backwards (see Section C.9).
The team found a pipe clamp on the U1 CS pump RWST suction line bent.
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The licensee performed a visual inspection of the clamp and the surrounding' welded lugs and found no damage. The licensee believes that the clamp was bent during initial fit-up o a. sway strut during construction. The team was unable to determine the cause since the NRC Bulletin 79-14 inspection program should have identified this problem if it existed since construction. The licensee stated that the bend was 4 and that the current support design has a significant safety margin. The licensee stated the sepport was operaole in the as-found condition and the team had no further questions.
3.
4160 Volt Distribution System Background The 4160 Volt Distribution System supplies electric power to all plant auxiliary equipment, either direr.ly or through step-down transformers.
The safety-related part of the system consists of six buses (or switchgear lineups).
In parallel, there is a nonsafety-related part consisting of five buses.
All of the switchgear is indoor type with air magnetic, stored energy, draw out circuit breakers rated 350 MVA.
Three of the nonsafety-related buses are General Electric Company's Magna-blast, vertical lift model. All other buses were manufactured by Allis-Chalmers Company. The inspection of this system focused on the switchgear; and the findings given below are indicative of the scope.
The 4160 Volt switthgear was in good condition, and the switchgear rooms were well maintained.
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i A pattern of repetitive failures could be discerned from the work history.
l On April 4,1955, a MWR was written on the breaker for component cooling.
I water pump 2A. The problem statement was: " Breaker closing spring failed l
to charge after rum was started then secured.
Breaker was then racked l
out and racked oack 'n, at which time the spring recharged. Note, this is the fourth time in last two months." Since January 26, 1988, nine MWRs were written by the Operations Department to correcs problems with the stored energy charging mechanism. Nearly all problems were attributed to mechanic.1 misadjustment. On August 29, 1988, a MWR was written because the spring would not, charge % the breaker for service water pump 2C. The worker's report states that the breaker operated properly from the test station, and no adjustment us made. Exactly one month later, an MWR was written for the same problem on the same breaker. This time an adjustment was made to the fact lever interlock switch. On July 29, 1988, an MWR was written bec;ust the charging spring motor would not stop af ter charging at safety-related breater DLO2. The charging switch and resistor were out of adjustment. The NRC team determined that the running motor was discovered during routine log taking and, therefore, the motor had been running for an indeterminate amount of time. However, the MWR did not indicate that the motor was replaced or even examined.
The team also discerned from study of the work history that, since November 25, 1987, there were nine documented cases of 4.16 kV breakers not being able to close or trip on demand.
Five of the cases were described in MWR's M00169719, M00382949, M00165802, M00173243 and M00181121, and were caused by problems within the switchgear.
The problems were mechanical adjustment problenis that were related to maintenance.
Two of the spring charging problems described in the previous paragraph (MWR's M00185377 and M00180716) were of the type that would prevent a breaker from reclosing after a trip, as would be required in diesel generator load shedding and sequencing schemes. There were two cases (MWR's M00175823 and 1400177073) wnere breakers could not be closed from tho main control board due to problems with remote cor.rol devices.
The latur two, although not related to breaker maintenan.e, are included in the total number of f ailures because published data for breaker failures included failures from all failure modes.
FNP has about 174 medium-voltage circuit breakers for the site. This equates to a failure rate of approximately O_036 failures per unit year.
"IEEE Recommended Practice for Design of Reliable Industrial and Commercial Power System, states in Table 11 on page 38 that the failure rate for metal clad drawout circuit breakers above 600 Volts is 0.0036 failures per unit year from all failures modes.
This figure represents tote i average failures; it is not a failure per demand value.
The IEEE failure rate figure includes the failure modes of spurious opening and damage discovered during maintenance.
These two failure modes are not included in the FNP failure rate calcelated by the team.
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Other conclusions that could be extracted from study of the work history are:
.(a) Some of the MWRs did not have sufficient descriptive information as to the circumstances of the problem and the troubleshooting methodology. For example, MWR M00190776 was sritten to replace the glass cover on a protective relay. However, the MWR did not address the need for re-calibration.
The broken glass cover could indicate that the relay had been bumped which could affect the relay set point. Similarly, MWR 142737 was written because 4160 Volt bus 1C did not fast transfer.as designed. The MWR was written on May 14, 1987 and was closed on May 6,1988, when a relay was replaced.
The MWR did not discuss the exact nature of the cause nor offer any explanation as to why one year elapsed between troubleshooting and closeout.
The circuit in question controls the transfer of the reactor coolant pumps to alternate power sources.
(b) The MWR forms are designed to help ensure that the cause of failures, for which MWR's are written, is identified.
The person completing the MWR form may select two out of eleven possible "cause of failure codes," and three out of thirty-four "cause description codes."
However, many of the MWRs have cause codes indicated that do not apply to the circumstances. For example, the MWR on the failure to fast transfer reads:
Cause of failure-ENGR / Design (Procedure) and Cause description - abnormal flow. Another MWR reads that the only work performed was to make a mechanical adjustment, but the cause description block indicated - foreign / incorrect material.
In these examples, the failure cause information is incorrect, and would be misleading to persons performing trends analysis using the failure codes.
See Section B.12 for further discussion.
(c) Review of sample Preventive Maintenance (PM) data sheets reveals various anomalies and irregularities with the work control process.
For each of five 4160 Volt switchgear compartments, the team requested that the last two sets of PM data sheets be pulled from the files for review.
The PM history for these five compartments is summarized below.
PM History for Four 4.16 kV Breakers Compartment Breaker Dates PM No.
Load Serial No.
Performed CA-04 RCP-2A 0256A2538-002 1/31/85, 10/21/87 DK-04 SWP-1B H-7249CA-3 6/18/82 OK-05 SWP-2C H-76565A-4 6/22/82, I
2/5/85 DB-03 RCP-2B 0256A2538-006 11/8/87 l
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PM History for 4.16 kV'SWGR Compt. DG-04 for CCWP-2A Breaker PM Date Serial No.
Remarks'
12/20/83 H-76556B-3 Breaker response time data was not recorded'per Procedure MP 28.109 4/4/85 H-76556B-9 Breaker was replaced due to problem with original breaker. PM performed on replacement.
4/16/89 H-765538-2 Data sheet not signed by foreman.
Work Authorization No. WOO 302464 indicates that last PM 'was performed 4/4/85.
As can be seen from the tabulation, for compartments DK-04 and DB-03, only one set of data sheets could be found in the files. The DG-04 history indicates two irregularities. The breaker response time data was not recorded (and the test may not have been performed) in the 1983 PM and the data sheet was not signed by the ~oreman as it should have been for the 1989 PM.
Computer generated work authorizations appear to be linked to breaker compartments rather than breaker serial numbers.
The Work Authorization for the 1989 PM at DG-04 states the last PM was performed on 4/4/85, but DG-04 contained a
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different breaker on that date as can be determined from the serial number.
This raises questions about the work hi story for the breakers, because it is not clear how the maintenance interval is tracked for individual circuit breakers that may be moved between switchgear compartments.
Given the relatively small sample of the inspection, these findings may have programmatic implications.
To maintain a useful equipment history, the breaker serial number should be tracked rather than the switchgear compartment.
The PM procedure for the Allis-Chalmers 4.16 kl circuit breakers was reviewed in detail.
The procedure, which had been developed by the Procedure Update Program (PUP) group, was a quality procedure because it was clear, haa appropriate detail, scope and cautions.
Some features of the procedure were excellent.
It called for breaker response time verification and insulation resistance testing of the control wiring. The lubricating instructions were very complete and clear. The fact that a specific set of steps covered the potential transformer compartment was considered a plus. On the other hand, the team had constructive criticisms of the procedures, which were discussed in detail with the Electrical Sector Supervisor.
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procedure did not actually call for checks of the primhry contact gap and wipe nor contact resistance test. Detailed steps for adjusting
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the contacts are provided, but they are optional. Many comments were j
made about the insulation resistance test for the breaker. Some of the comments were:
(a) The megger check was incomplete because it was not done phase-to phase (b) Megger readings are not recorded, and therefore, they cannot be trended by the engineer, nor can the reading for the different phases be compared.
A final comment was that the procedure did not call for checking the anti pump circuit.
The PM procedure for the General Electric Company 4.16 kV circuit breakers was an older style procedure, and it was much shorter and less detailed than its upgraded counterpart. Work performed under this procedure may have been adequate because it refers to the manufacturer's instruction book which is quite detailed.
The GE breaker procedure did not call for an insulation resistance check of the breaker.
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l The handling of instruction books for the 4160 Volt switchgear and related manuf acturer's correspondence was inspected by the Team.
Instruction books wre on file with Document Control. Correspondence from General Electric Company related to switchgear maintenance was being effectively tracked by the System Performance Group. The SPG stated that they did not have any correspondence on file from i
Allis-Chalmers concerning maintenance on the switchgear.
The team talked to the Customer Service Manager at the Siemens-Allis plant in Raleigh, NC, and confirmed that the company had not issued any
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maintenance information letters to customers for the model of switchgear at Farley.
The variables in PM programs among utilities are the maintenance interval and the quality of the actual work performed.
Farley has about 174 medium - voltage circuit breakers for the site. There were nine failures of the charging mechanisms and the breakers themselves within a period of about 18 months. This equates to a failt.re rate of approximately 0.036 failures per unit year for both these types.
This rate is ten times higher than published data for the industry.in general.
The planned maintenance interval at Farley for these breakers has varied from three to five years since plant startup, which is in line with industry practice.
Considering the sketchy procedures that were in use before 1988 and the irregularities found in the data sheets reviewed, one may reasonably conclude that the focus for corrective action should be on the quality of the work performed rather than the interval. The team recognized that ii the
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upgraded procedures, assuming comments made herein are incorporated,
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are applied at a three-year interval the failure rates observed may decline.
Careful trending of failures and aggressive root cause analysis will indicate whether or nct enhancements to the 4160 V
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breaker maintenance program are necessary.
4.
125 Volt DC Distribution System Background The purpose of the 125 Volt (V) DC distribution system is to provide a reliable source of continuous power for control, instrumentation, and emergency service.
The system consists cf independent and redundant subsystems primarily used for safety-related loads.
A separate nonsafety related 125 V DC system is used for direct current loads required for power generation.
The safety-related 125 V DC system consists of two subsystems. The safety-related 125 V DC system located in the auxiliary building is considered the main system for all loads except the service water building.
The service water system supports loads in the SWIS.
The auxiliary building system consists of two redunaant buses, Train A and Train B.
Each train has one 125 V DC battery and battery charger, three distribution panels, and associated switchgear feeding main loads.
A third battery charger, C is capable of swinging to either bus, A or B.
The batteries float on the busses fully charged and capable of supplying emergency DC power without charger support for a period of two hours. The emergency power is used for the following type of loads: instrumentation inverters; engineered safety features controls; emergency lights; circuit breaker tripping and closing; diesel generator field flashing and control;
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direct current solenoids for air-operated valves; miscellaneous controls and alarms; and reactor trip switchgear.
The purpose of the safety-related 125 V DC system located in the service water building is to provide a reliable source of continuous control power for service water switchgear.
There are two independent and redundant subsystems. Each subsystem has two 125 V DC batteries and two chargers.
One battery and charger set is operating and the other set is in standby.
The safety-related batteries for both the auxiliary building and service water building contain 60 lead-calcium cells connected in series to provide the nominal 125 V DC power.
Each cell is assembled in a clear plastic container and mounted on corrosion resistant racks.
In the auxiliary building, A and B batteries are located in separate rooms.
In the service water building, the two Train A and two Train B batteries are in separate rooms.
In addition, the batteries (both Units 1 and 2) for the Turbine Driven Auxiliary Feedwater Pumps (TDAFP) runinterruptible power supply (UPS) were examined. This battery powers components for the TDAFP.
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i Inspection
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The team performed walkdowns, observed - surveillance tests and work in progress,. and reviewed occumentation for portions of the safety-related 125 Volt DC distribution system.
The purpose of this inspectior was to determine if the batteries,' the battery chargers, the.DC switchgear, and the 125V DC powered 120V AC vital bus inverters are being maintained in a satisfactory condition.
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. Service Water Building Batteries The team performed e walkdown to examine the batteries and chargers..In
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addition, the performance. of-the weekly surveillance test FNP-0-STP-906.02 was observed for. the four batteries:
1A, 2A, IB, and 2B.
The specific gravity, the battery terminal voltages, and battery charger float current were measured. The proper water level for each cell was verified and a general inspection performed.
The team did not identify any deficiencies with the service water batteries or. chargers.
The batteries were found to meet tneir Technical-Specification (TS) requirements.
The housekeeping in the battery rooms was satisfactory. The licensee has maintained the service water batteries and chargers in a good condition.
The team ~ reviewed the maintenance work history, the Nuclear Plant Reliability Data System (NPRSD) reports, and the MWR list to determine the condition of the batteries and chargers.
Two recent problems were identified which required corrective action.
MWR M00165616, dated January 23, 1988, stated battery 1A had rust on the #2 ground strap.
NPRDS Report, Job Number 9387 stated battery charger 526A had a blown fuse. No recurring maintenance problems were evident.
Turbine Driven Auxiliary Feedwater Batteries (Units 1 and 2)
The team performed a walkdown and observed the performance of the weekly battery test specified in FNP-2-EMP-1352.01.
The specific gravity, the battery terminal voltage, and the battery charger float current were measured. The proper water level for each cell was verified and a general inspection performed. The team did not identify any deficiencies with the battery or charger.
The batteries met their weekly TS requirements.
However, during the walkdown two concerns were identified.
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For both Units 1 and 2, the lighting over the TDAFP UPS battery was found to be inadequate.
It was extremely difficult for the journeymen electricians to perform the weekly battery test and inspection even when a flashlight was used.
The licensee agreed the lighting may need
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improvement and stated they will evaluate the lighting condition.
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For both Units 1 and 2, the TDAFP UPS battery area does not have overhead protection. The Unit 2 battery was found to have debris wh_ich had fallen
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from overhead construction work. The Team was concerned with potential for water leaks from the overhead fire protection piping.
In response, the licensee : stated that' the piping was normally. dry.and two failures would be required before the : battery could :be ' sprayed by water.
The failures :are loss of electrical power and pipe rupture. The team found the licensee's response acceptable but still thought the licensee should
- consider overhead protection for these batteries.
Auxiliary Building 125V DC System The team. performed a walkdown to examine the switchgear for the 125 V DC system. During the walkdown, the team noted that many of the metal. clad DC circuit. breakers have not been calibrated since preoperational testing.
- The DC circuit breakers are discussed in paragraph C1.
The team reviewed. the battery testing procedures and observed the performance of battery. testing. Data from the monthly surveillance test was reviewed and' found to be acceptable.
The team evaluation of the licensee's maintenance program for the safety-related batteries is satisfactory.
The team reviewed the maintenance work history, the NPRDS reports, and the MWR list to determine if the licensee had any significant problems with the batteries, the battery chargers, the circuit breakers, and the 125 VAC vital bus inverters. A review of. NPRDS reports, Job Run Numbers 9387 and 9622 has shown the licensee has had 44 failures with the inverters since January 1985. The licensee agreed the inverters are not as reliable as they would like them to be. The licensee's intentions are to replace the Unit 2 i_nverters during the seventh outage (Fall 1990).
The Unit 1 inverters will be replaced during the tenth outage (Spring 1991).
The q
licensee stated that getting an acceptable vendor and delivery date was j
very difficult. This fact has prevented the inverters from being replaced
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The reply was acceptable to the team.
A review of eleven MWRs since Mcrch 1985 has shown the licensee has significant failures with the battery chargers.
These failures are with the firing modules cards and the gate filter cards.
The licensee has q
identified that the gate and filter modules were improperly wired from the
vendor.
This problem has been corrected.
However, the licensee recognizes that the battery chargers neea improvement and is working with the vendor to resolve the problems. Several procedures have been revised to maintain the silicon controlled rectifier (SCR) current balance as part of preventive maintenance. The team observed that the lack of engineering support in the area of solid state electronics may be one reason the licensee has not resolved the problems with the inverters and battery chargers.
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- During the. loss of. the off site power test (2-SOP-37.10) for Unit' 2,.
[ conducted while the team was on site] battery charger 2B failed. The gate and filter. boards were severely burned. This: failure indicates the licensee has not cor.spletely resolved.these ' problems.
5.
Instrument' Air System Background
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The FNP ; Instrument Air System - (IAS)' provides the motive ' force lfor operating pneumatic equip. ment throughout the plant and is a subsystem of'
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the compressed air system. The compressed air system can be divided into three areas.
The first area is the air corepressor packages that supply-the air for distribution throughout the plant.
The remaining two areas-are the service air system and the instrument air. system.
There are a total of eight air compressors and their associated i'
intercoolers, aftercoolers, and air receivers for.the plant.
Four air compressors 'each are located in Units 1 and 2, (A, B, C, and D). The A, B, and C air compressors are dedicated to their respective unit. However, the D air compressors can be aligned to either unit.
The air ' compressor package is made up of an air compressor, which rt.ises the pressure of the air to 100 psig.
The heat generated by the compression process is removed by air coolers, which are cooled by service witer. The air receivers provide a storage volume for the compressed air, and they dampen out the pressure pulses generated by the air compressors.
The air compressor packages are connected to a common header.
Prior to the air being distributed throughout the plant, it passes through an air dryer unit. The instrument air system has two air dryer units, and the service air system has one dryer unit.
Each air header supplies branch lines, which distribute instrument and service air to all parts of the plant.
All instrument air lines penetrating containment have isol6 tion valves in series located outside the containment and check valves located inside containment.
All service i
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air penetrations into. containment have a normally locked closed valve on each side of the containment penetration.
The instrument air system branches into headers which supply separate areas.
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supply the following areas:
auxiliary building and containment; turbine building and outside areas; and service building (supplied only from the Unit I header).
.If +.he instrument air system starts to lose pressure, it attempts to maintain a supply of air to the auxiliary building and containment by
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isolating selective branches from the system.
At 75 pounds per square
.l inch gauge (PSIG) decreasing at the air dryer outlet, purging air for air dryer regeneration is isolated by closing the air dryer unit purge valves C and D.
If the instrument air header pressure decreases to 70 PSIG, the air drying unit bypass valve, V-902, opens.
If pressure drops to 55 PSIG
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(Unit' 1. only), instrument air 'is isolated from the service building. At.
'45'PSIG, instrument air-to the turbine building and outside areas is isolated by closing V-903 in an attempt to provide'the. auxiliary building and containment with instrument. air.
In - order.for the pressurizer power-operated relief valves (PORV) to - remain. operable on a loss of
. instrument air, they have. their own emergency' operating gas supply.(from
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nitrogen bottles).
The main steam atmospheric relief valves also have -
theirL own emergency air compressors, to maintain operability on a loss of L
instrument air.
Inspection
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The. team completed a general walkdown of selected portions of the IAS for both ' Units 1. and 2..
The major components ex'amined included the main station and emergency air compressors, alternate nitrogen sLpply to PORVs, and ' various safety-related end-use dev. ices as permitted by plant conditions (PORVs, TDAFP, steam atmospheric reliefs, SW flow control valves (FCVs) for'CCW HX, etc.).
The team also completed a review of documentation and held discussions with cognizant licensee personnel regarding work histories associated with IAS (especially regarding main station and emergency air compressors), and an in-depth review of the licensee's interim responses to NRC Generic Letter (GL) 88-14 on instrument air.
'The general condition of components examined was observed to be good.
However, the team noted discrepancies as follows.
Essential air to turbine building pressure switch N1P19PS505 was
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observed past due for calibration as of December 12, 1988. This switch controls isolation of Turbine Building on ~ loss-of-instrument air i.e.,
isolation at 45 psig. Calibration problems. are further discussed in Section B.8.
Some end-use devices were observed to be without locally installed
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filter-regulators.
Also, a discrepant condition (inoperable bleed valve) was observed for the filter regulator associated with Unit' 2 CCW HX FCV 3990A.
The need for filter-regulators on all end-use i
devices due to poor air quality is further discussed in Section C.3.
Several deficiency tags were noted, especially in regard to the
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station and erergency air compressors.
Discrepancies involved were considered minor except for the emergency air compressors.
The team's concerns related to the availability of emergency air compressors are further discussed in Section C.4.
Indication of poor welding practice was observed associated with
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modification of supports for Unit I backup nitrogen supply for PORVs.
Welding on the supports was completed with the compressed gas bottles in place and within one inch of the cylinder's surface. Smoke stains from the welding arc remained on the bottles in three places.
NRC
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concerns. regarding safe work ' practices are further discussed in Section C.10.
The team's review of a random sample of repest IAS mechanical MWRs
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(48 MWRs initiated in.1987 and 1988) revealed _that'none were'actually due to rework. Multiples of the same MWR occurred'due to inadequate-initial analysis of the problem, use of the same ' number._when different disciplines wert. involved in completing the work and work on different subcomponents -for-the majori component involved.
The team,also noted the following during this review:
The cause code analysis is often improperly used due to lack of procedural guidance The.'cause code is not considered useful by maintenance personnel in completing a root cause analysis Root'cause analyses are not completed for equipment failures Mechanical maintenance appears to be of high quality and was not
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the source of repeat MWRs for the majority of MWRs reviewed
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'6.
Maintenance Work Observations In addition to the work observations detailed in Section B. I through B.5'
above, the team observed the following inprocess maintenance
' Turbine Driven Auxiliary Feedwater Pump (TDAFP)
During ' the current outage, the licensee disassembled and inspected the Unit 2 TDAFP as part of their PM program. The work was accomplished in -
accordance with MWR 183004 and Procedure FNP-0-MP-7.1, Revision 7, Disassembly, Ir,spection,. and Reassembly of Aukiliary Feedwater Pumps.
Upon disassembly of the pumps, the licensee found that the " disaster" seals (backup seals on both ends of the pump) were missing.
New seals were' procured and installed during reassembly of the pump. Upon starting the pump after reassembly, the inboard seal smoked.
Disassembly of the seal showed that the expansion collar (part 25) had rubbad the sleeve (part 10) damaging the parts.
Prior to installation of new parts, the licensee determined that the seals had been deleted by design modification (1975) ' prior to initial plant operations, explaining why th2 seals were missing.
It could not be determined why the vendor drawing was not updated in 1975 to show deletion of the seals, or whether there are additional examples where vendor manuals have not been updated.
This weakness in the. vendor drawing control program should be pursued by the licensee, to determine whether the licensee's vendor drawing / manual control program has many other like deficiencies. This matter will be identified as unresolved item 348,364/89-10-02:
" Vendor Drawing / Manual Control Program."
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The team observed disassembly and reassembly of the bearirg and seal area of the pumps to remove the disaster seal. Use of approved procedure, procedure compliance, use of knowledgeable and qualified crafts, use of proper and calibrated tools, cleanliness control, etc. were examinsd. The team noted that the procedure (FNP-0-MP-7) had been through the PUP and in general appeared to be a good procedure.
However, the Team noted that procedure step 7.12 still called for installation of the " disaster seals" and "M" sign-offs for certain seal assembly steps. In addition step 7.14 had a "S" sign-off for the supervisor to verify installation of the seals.
Steps 7.12 and 7.14 were signed off by the journeyman and the foreman just as if the seals had been installed.
This indicated some weakness in verbatim compliance with procedures and is in violation of procedure FNP-0-AP-15, Revision 11, paragraph 5.0, which requires that plant procedures be adhered to and that journeyman and foreman ensure that steps are being correctly performed and signed off.
This an example of violation 348,364/89-10-01 discussed further in Section C.5.
Electrical Maintenance
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Portions of the following PM work was observed:
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Work Authorization No. WOO 309518 and 22 for calibration of induction disk overcurrent relays for reactor coolant pump 2A (phase two) and incoming feeder to bus 2A from unit auxiliary transformer 2B (phase two)
Work Authorization No. WOO 305500 for preventive maintenance on reactor trip breaker used in by pass position train B, Unit 2 Work Authorization No. WOO 305664 for preventive maintenance on 600 Volt breaker from Unit 2 and replacement of pole shaft per NRC Bulletin 88-01 Work Authorization No. W003065674 for cleaning and testing of i.
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inverter 2F MWR No.198960 for incorporating PCN No. B87-2-4001 to rearrange I
indicating lamps for the containment isolation valve position indication system
Each of the observed activities was being conducted under approved work authorizations or maintenance work request.
Procedures were being followed step-by-step, data was being carefully recorded and steps initialed.
It was determined by observation that procedures were in place., and were being followed, to control fuse and parts replacements.
In summary, as far as could be determined by observation, electrical maintenance work performance at FNP was adequated.
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Cracks in the door skin near the hinges, were to be repaired using welding procedure CSM-10 (a manual gas tungsten arc (GTA) procedure requiring 45-100 amps with a 3/32" ERCUSI-A welding rod).
Af ter observing completion of several repair welds, the team noted that the welder was welding out of procedure (20 to 25 Amp versus 45 amp required minimum). This was verified with a calibrated amp meter (FNP LEA-1119).
Follow on conversations with cognizant licensee personnel revealed that The welder had not reviewed CSM-10 prior to beginning work and was not aware of the minimum requirement Another welding procedure was available for use with minimum amperage requirements within the actual ranges used. Failure to j
assign this procedure was an apparent oversight by the welding
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foreman involved Welding surveillance checks of volts / amperages is not normally done due to the lack of Quality Control (QC) surveillance personnel The team informed cognizant licensee personnel that there was no concern regarding adverse affects to the fire door repaired under MWR 188040.
The work was apparently e good quality despite the c
procedure problem.
This failure to weld within procedure is another example of a weakness in verbatim compliance and violation 348,364/89-10-01 discussed further in Section C.5.
One of the welding foremen involved had recently failed the required eye examination required by paragraph 8.1.1 of FNP-0-M-24.
The foreman performs inspection of weld craf tsmen work. An estimated twenty percent of the ASME Code welds for which he had inspected fit-up did not receive any further inspection. No attempt had been made by the licensee as of this inspection to assess potential adverse impacts to the hardware involved. Subsequently, at the exit interview, NRC was informed that the welding #oreman had been reexamined by a doctor and found to have adequate vision. NRC had no further questions on this matter but cautioned that corrective action should be taken for future failures of eye examinations by peer inspectors.
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' Accumulator Check' Valves
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The' team inspected maintenance activities for Unit 2 Safety Injection Accumulator _ check valve 02E21V032A.
The accumulators are a' passive engineered safety feature that provides borated cooling water to _the reactor core in the event of a loss of coolant. accident in which the
. reactor pressure falls below 600 psi.
The accumulator. tanks are pressurized to about 600 psi and inject., to the - reactor _ ' coolant ' loop piping; One accumulator ' tank is provided for-each reactor coola_nt loop for a total of three. The accumulators are not designed for the full-reactor pressure of over 2200 psi. and in' normal operation each is separated and protected from that pressure by two accumulator check'
valves.
Accumulator check valve Q2E21V032A was found to be leaking excessively during a ' surveillance test, 'and the maintenance. on it was conducted to identify and correct the cause of the leakage.
Actual maintenance work performed on the valve was not observed by the team, as the important
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assembly and machining operations were performed while the team was not on site.
The team's inspection was accomplished through' review of-in progress documentation, observation of some of the parts obtained for replacement, observation of examples of all of the valve parts actually replaced, and discussion of the work activities with involved maintenance craft.
Maintenance was performed on this valve as follows:
The valve was partly disassembled (disc and hinge parts not removed),
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manually stroked to verify free disc opening movement, and then inspected for wear and damage per MWR 198152 utilizing instructions in Surveillance Procedure STP-644.7. No unacceptable conditions were identified.
The sealing capability of disc and valve seat were verified by a
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tissue paper test conducted per MWR 178500 utilizing instructions in Procedure MP-63.4. This test involved closing the disc with tissue paper placed at various locations on the valve seat and then attempting to pull the tissue paper out without tearing.
The valve passed the test. The tissue paper tore in each instance indicating seating. Also, the procedure required a visual inspection of the seating surface which was performed, but revealed no abnormalities.
In accordance with the procedure the valve was acceptable and could be reassembled on the basis of the tissue paper test and visual inspection.
The valve was reassembled and the bonnet bolting torqued to 500
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ft.-lbs. for temporary closure to facilitate other plant work while management was determining whether and what further maintenance should be performed to assure that valve leakage would be corrected.
Note: The maintenance foreman informed the team that it was believed that the leakage would not occur if the leakage test was p'.-formed at
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. a higher. pressure (below reactor operating pressure) as the previous test pressure may have been too low to seat the valve.
L After consulting with the valve vendor and reviewing ~ possible
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corrections, management decided to replace the disc and lap the seat of the valve. The valve was disassembled again and in this instance the disc and hinge' parts were removed and replaced and the seat was lapped. In replacing the hinge block new holes had to be drilled in-the valve and the new block so that the block could be ' pinned in place.
The hole ' ' size and. location-' were.not ~ described in. the procedures 'or any vendor documents. The. location and drilling of the holes was done at the verbal direction of the on-site ' vendor representative.
Post maintenance. testing had not been completed as of the end of the inspection.
From their inspection related to the above maintenance the team determined the following:
Important repair steps were not specified in either the MWRs or the
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procedures.
For example, neither the MWR nor the procedure steps specified the initial reassembly and torquing of the valves (interim - to close valve for refueling operations), the need to.
perform lapping and ' disc replacement (in the absence of failure of STP 644.7 tissue paper testing) or the drilling of holestfor hinge block replacement.
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The work orders involved were properly authorized, issued and approved.
The maintenance was performed wholly without any independent
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inspections or verifications.
In the team's experience, steps such as torquing of bonnet bolting on Class 1 valves like the accumulator check valves is verified correct'by independent QC inspectors.
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I Recorded data showed properly calibrated torque wrenches were used.
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Maintenance foremen were directly involved in performance of
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important procedure steps.
l Parts information was correctly recorded.
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Through the licensee data base maintenance personnel were able to
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readily determine the availability of needed replacement parts.
Based on actual checks of parts in storage the team determined that
the data base was accurate.
Although the procedures involved (which had been recently upgraded)
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were generally clear and accurate in describing steps to be performed, some weaknesses were noted.
For example, sign offs for steps were on data sheets rather than within the procedure at the actual steps, making it more likely that steps may be missed; some
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. materials needed were not described well - as with the tissue paper used for the test in Procedure MP-63.4; the final procedure page was
not clearly identified as such; the valve drawing in the MP 63.4 was marginally legible in same areas; and, as already noted many of the:
steps performed to accomplish the maintenance were not included in the procedures or MWRs.
Cleanliness steps were properly included in the MWRs and procedures.
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For the important maintenance decisions involved in repairing ' the
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check valve the licensee had obtained direct vendor input through having an on-site representative present and consulting-with the
' vendor by phone.
The personnel involved in the planning and performance of : the
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maintenance appeared knowledgeable and well qualified.
Records checked.b3r the team for two foremen involved in the work indicated satisfactory qualifications.
The. team concluded that the work on the check valve appeared generally.
well performed by properly qualified personnel. The direct involvement of foremen in important steps provided a strong sense of responsibility for assuring the maintenance was correctly performed. This involvement of the
. foremen as well as the capability ano attitude of the personnel involved was considered'an important strength in the process. The lack of formal
. written planning and control of the work afforded a potential for error of omission and appeared to be a possible weakness.
Battery Specific Gravity Tests The team observed the weekly surveillance test specified in FNP-1(2)-STP-905.03 for both A and B batteries. The specific gravity, the bettery terminal voltage, and. the battery charger float current was measured. The team observed that the electrician performing the current measurement was not measuring both power cables connected to the battery.
Instead one cable was measured and the value was multiplied by two. The electrician, after being questioned as to properness of this type-measurement, measured both cables. The licensee agreed both cables should-be measured. The licensee revised the procedure accordingly.
The proper water level for each cell was verified and a general inspection performed.
No deficiencies were identified with the batteries.
7.
Material Control Background The team examined the licensee's material controls in their support of the maintenance process.
This area was examined by general inspection of l
warehouse storage conditions and specific examination of a random sample of stored parts (Code Class Valves, Welding materials and emergency air compressor parts) together with attendant QC documentation / computer
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records for the parts involved.
Records associated with maintenance of Class A storage temperature and humidity requirements (August 1988) for
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the warehouses were also reviewed.
Procedures and other documentation l
were also reviewed in order to assess the following attributes:
Policies and procedures had been documented and implemented which provide for: ensuring a timely procurement of materials, including long lead time items; identifying required documentation, testing, inspections; traceability of records; identifying required specifications for materials; identifying and expediting emergency procurement; identification of acceptable sources including their qualification; identifying the required number of spare parts (each type), the number control, and reorder.
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Guidelines and criteria are implemented for:
identification of materials shelf life; spare parts identification; acceptable consumable materials; receipt inspection including acceptance criteria.
Guidelines and criteria are implemented for storage, considering:
separation of qualified and unqualified materials; storage of hazardous materials; protection of stored materials and parts; traceability of documentation; and issuance; with consideration for requisit. ion identification, work order identification and guidelines and controls for returning parts if not used per the work order.
Observations Documentation and hardware examined by the team are as listed below:
Procedures:
FNP-0-AP-9, FNP-0-AP-21, FNP-0-AP-31, FNP-0-AP-49,
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FNP-0-AP-52, and FNP-0-AP-63 Ten Parts - ASME 12" Accumulator Swing Check Valve TPNS-Q2E21V032A
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Six Parts - ASME 12" 1500# RHR Valves TPNS - Q2E11V016 A & B,
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Q2311MOV8702 A & B, Q2E11V0013
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Two Parts - ASME 3" Check Valves Forty Eight Parts - Units 1 and 2 Emergency Air Compressors
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TPNS Q1P18C002 A & B, Q2P18C002 A & B Welding Rods / Electrodes - Thirteen classes of various sizes
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Moisture / temperature monitor record charts were examined for
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verification of Class A warehouse storage:
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L Month
. Location Recorder No.
= August.1988 Service Building FNP-HH1-9055 Store Room
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August 1988 New Warehouse FNP-HH1-9086 Receipt-Inspection /
Wrapping Area 19.87 and 1988 trend data associated with spare parts, store room
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issues, etc.
Findings The lisensee has. established an effective materials control system.
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The team was-especially impressed with the corrosion protection (most-parts are blister bubble packed), location. system (store rooms are well laid-out with each part assigned a particular. location), and computer control system (only one minor discrepancy between computer data. base and actual verification for all-line' items checked).
The team noted a discrepancy associated with storage of the Class A
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temperature / humidity records.
These were available but were _ not being maintained as plant quality data and stored in document.
control. The licensee made immediate arrangements to effect this -
change'.
Review of the trend data revealed few instances of ~ maintenance work
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on hold related to spare parts. However, some delays are associated with "high priority" items and normally occur due to long lead times and/or backlog associated with materials upgrade / procurement QC i.e.,
need. for-additional procurement QC activities in order to upgrade commercial class items to Q class. MWRs on-hold for parts for more than one-year averaged less than five (5) from June 1988 through Apri l. ~1989. Total MWRs on hold for parts averaged approximately 300 for the same time frame. This is contrasted with an inventory of greater than 40,000 lina items and store room issues of 30,000 to 80,000 items per month.
The team. discovered an inadequacy related to the total plant
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numbering system-in-that it is. not cross-referenced to parts unless the parts - have been upgraded by QC procurement-engineering. This deficiency does -not handicap parts or procurement control since a separate store number.is assigned for each parts line item. However, this is considered a potential weakness associated with the purposed used of TPNs in the SEE-IN and NPRDS date bases.
On review of the above, the team consensus was that materials control at plant Farley was a strength in both program and implementation.
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8.
Instrument Calibration Program The, calibration program for plant installed instrumentation is the
responsibility of the Instrument and Calibration (I&C) group in the
. maintenance department. The calibration program and its implementation is primarily controlled by procedures FNP-0-AP-3, FNP-0-AP-5, FNP-0-AP-51, FNP-0-AP-52, FNP-0-AP-53 and FNP-0-GMP-1 listed in Appendix 3.
These L
~ procedures were reviewed to determine if the calibration program meets NRC requirements and licensee's commitments.
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In addition to the I&C, other groups on site have. calibration programs for-specialized instrumentation.
These groups.are Health Physics, Chemistry, and Computer _ Services. These groups and I&C implement the calibration program as part of the preventive maintenance program.
The-PM program for I&C includes periodic calibration by. either surveillance testing or repetitive tasking.
The instrumentation-referenced in the TS is calibrated by surveillance testing. Surveillance testing is controlled or coordinated by the Outage Planning Supervisor.
Other. selected safety-related and. plant instrumentation is calibrated using the repetitive task method.
The planning group in the operation departmant and the operation department staff are responsible for determining and scheduling calibrations and repetitive tasks to the I&C groap on a monthly basis. The daily and weekly scheduling is performed by the I&C group. It should be noted that the operation department does not'
require all plant instrumentation to be calibrated. Some instrumentation is put in a " Calibration Not Maintained" status.
As instruments are worked they are having -either a green or. red sticker placed on them for " calibrated" or " calibration not maintained." This is an excellent program to allow plant staff to readily determine the calibration status but.it does not extend to all plant instruments. If it is only done as instruments are worked, it may 'never reach all instruments.
FNP management should take positive action to. extend this program to all instruments.
This appears important at FNP as many instruments are not in a routine calibration program.
The team performed walkdowns on selected systems. During these walkdowns, many instruments were identified that did not have a current calibration sticker or any calibration sticker.
In addition, many instruments had the
" Calibration Not Maintained" sticker. The instruments on the main control panels for both units were examined to determine their calibration status.
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Several instruments had the " Calibration Not Maintained" sticker (back of instrument). When the team ask several operators which instruments were not calibrated, the operators did not know.
In the main control panels the team also identified lifted leads with bare terminals. The licensee immediately took corrective action by taping the bare terminals. In addition, the licensee revised Instrument Maintenance Procedure FNP-0-IMP-0 by adding Step 4.20 requiring all lifted leads from
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plant equipment to be taped. The licensee stated all electrical'and I&C-personnel will be trained to tape lifted leads.
After. the walkdowns were completed, the team requestL. the I&C group furnish an instrument list for nine selected systems' providing the
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calibration status.
In addition, a list of all repetitive tasks,
- including calibrations, was' requested to determine work load and back log for the I&C group.
The selected systems, the total number of instruments in each system, and the number of instruments. not calibrated (Calibrated Not Maintained) are listed as follows:
Systems Total No. Instruments Not Calibrated RHR/LHSI
0 Diesel Generator 101
Aux. Feedwater.
118
HHSI/CVCS 309 176 Service Water 366 268 Inst Air
55 Cont Spray
6 Main Steam 113
Main FW
9 Fr'om the list, 619 of the 1240 total number of instruments were not calibrated. Most of these instrument not calibrated were local and panel mounted indicators and alarm switches for annunciators.
The licensee explained that any instrument in the " Calibration Not Maintained" status would be calibrated before use if needed for testing by using the MWR.
However, since the sample indicates and the licensee agrees approximately 50% of the plant instrumentation is not calibrated, this is considered a
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weakness by the team, specifically for annunciator switches.
The.I&C repetitive tasks ccmputer list was reviewed to determine if any calibrations were over due.
The licensee explained that a 25% grace period is used for items on the repetitive tasks list. Thirty six items were identified as being overdue. The licensee was requested to review these items and provide an explanation.
Twenty four of the items were incorrectly listed as overdue by computer error.
Ten items were within the~25% grace period and two discrepancies are under investigation.
In addition to the preventive maintenance calibration program previously discussed, the I&C group has a calibration lab. The calibration. lab was inspected to determine if the measures specified in FNP-0-AP-11 were being met. These measures are the requirements for the control and calibration of test equipment under the control of the I&C group and used in the calibration, testing, and maintenance of plant equipment and systems.
Various calibration lab test equipment, shop test equipment, and field test equipn.ent and the associated calibration files were examined to verify this test equipment was properly calibrated.
The calibration j
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stickers for this tect equipment, including the due date, were reviewed l
and compared against the equipment files. The following documentation was reviewed and compared with selected test equipment in the lab to assure accuracy:
Test Equipment Inventory List; Test Equipment Status and Checkout Log; Test Equipment Calibration Files; Controlled Vendor Manuals; and Test Equipment Calibration Procedures.
The calibration lab was found to be neat :.nd clean.
The test equipment was properly stored. The documentation reviewed was found to be complete
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and neatly filed. The I&C technicians working in the lab acted in a professional manner. The calibration lab was found to be satisfactory.
The I&C calibration program has the following strengths:
exceptionally low backlog; the program is well managed; the calibration lab was found ';
meet all requirements; the I&C technicians performed their work in a professional manner; and the required work in the calibration program was well implemented.
The I&C calibration program has the following weaknesses:
a 25?; grace period is too frequently used; the calibration stickers on some (approximately 5094) field equipment are not up to date; not all plant instrumentation is being calibrated and the new calibration sticker program is not being rapidly spread to all instruments.
9.
Health Physics Health physics' involvement in planning and preparation, as it related to support of maintenance work was reviewed by the team and found to be adequate.
The licensee's morning outage planning meetings were observed by the team. Health Physics (HP) personnel attended and participated in i
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all meetings observed. Scheduling conflicts which affected HP were openly discussed.
Through interviews with HP technicians and maintenance foremen, it was determined that a good line of communication existed between the HP and maintenance organizations.
Maintenance personnel i
stated that few jobs, except for high dose and nonroutine evolutions, were i
held-up from lack of HP field support.
Mair,tenance jobs in progress, within the radiation control area, were observed by the inspectors.
Radiation protection activities for these jobs were commensurate for the radiation hazards present.
HP aspr.ts of the Maintenance Work Request (MWR) program were reviewed by the inspector. The maintenance planning staff included two assistants whose responsibilities included system walkdowns in preparation of MWRs.
In many instances, these job site visits resulted in more thorough
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planning, thus, resulting in quicker more efficient job completion.
It l
was noted t' at the MWR preplanning worksheet, used by the planners
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contained HP related check-off items, such as the identification of a job site as a high radiation area, radiation exclusion area, or the possible need for an RWP prior to job initiation.
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'38 Through discussions with HP-personnel and maintenance procedure review, the inspector determined that maintenance procedures controlling work in areas with extreme radiological conditions or work on contaminated systems'
are. routed.to the HP group for the addition of HP holdpoints and caution statements.
Health Physics training for maintenance personnel was discussed with the I
licensee's training ' staff.
Lesson plans and sample. test questions from General Employee Training' were reviewed and found to contain appropriate radiation worker topics.
Licensee. representatives stated that mock-up
- training.is sometimes used for maintenance worker training and that a steam generator' channel head mock-up had been utilized prior to the
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current Unit 2 outage.
The licensee's external and internal dose control activities were better than average as evidenced by past and present annual collective doses at or below the national average. The plant 1989 Monthly Exposure Report, which detatis collective monthly doses by work groups, showed that all maintenance groups had received collective doses below their goal each month this year, through April. The Group Exposure Trending Table, dated April 25, 1989, was also reviewed.
Radiation work permits (RWP)
associated with selected MWRs listed in Appendix 4 were observed.to contain appropriate internal and external dose control requirements for the job (s) being covered by the RWP. The team examined Radiation Incident Reports for 1989 and determined that very few maintenance workers were identified within the reports.
Procedures, listed in Appendix 3, which controlled the licensee's personnel monitoring program and skin dose assessment due to contamination were reviewed and found to be adequate.
s The licensee's program for maintaining doses as low as reasonably achievable (ALARA), of which internal / external dose control is an integral part, was discussed with licensee representatives. Though the program is marginally staffed and implemented with some informality, it appears to be accomplishing its intended function of initiating daily and longterm dose reduction actions.
It should be noted that during discussions with foremen and worker level maintenance personnel, it was observed that few were cognizant of their individual last quarter dose and none cnuld state their groups current quarter collective dose goal.
Procedures dictating pre and post job planning for jobs within the Radiation Controlled Area (RCA), ALARA activities, and RWP completion were reviewed and are listed in Appendix 3.
.
i Numerous radioactive material and contamination control activities. were i
observed during the inspection. This included general area surveys, free release of equipment from the RCA checkpoint, and the bagging and tagging of material being removed from contaminated areas.
In general, contamination control was adequate considering the facility's outage status, however, an excessive amount of small item trash was observed in i
containment.
Even though this trash was determined to be uncontaminated,
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the entire containment building is controlled as a contaminated area and i
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it is poor practice to maintain a contaminated area in such a condition.
This item is considered as another example of inadequate housekeeping which is more fully described in Section C.6.
An additional poor work practice noted during containment tours was the observance of. two individuals in protective clothing and respirators laying on the floor, one near the ledge of a reactor coolant pump (RCP).
L access, well. :The area was not designated as a " low dose waiting area,"
however, dose rates in the area were nominal.
In addition to the potential ALARA impacts, this behavior was of safety concern as the RCP 1:
access well was an approximate 20 to 15 foot drop onto the RCP. After L
questioning HP technicians in the area, licensee representatives stated
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that the individuals were not asleep and were awaiting permission to begin a. job in - the area.
Licensee representatives concurred with the team-
. concern and stated the management does not condone or. tolerate.such activities;from contract or utility personnel.
The team's. consensus - was that health physics program as it relates to maintenance activities was a strength.
' 10. Maintenance Facilities Observations The team was able to observe general conditions and specific activities
- during this inspection for clean and " Hot machine shops and tool rooms.
The shops are well laid out with adequate space, equipment, and partitioning to accomplish a variety of tasks associated with machining, cutting and welding, troubleshooting and assembly / disassembly bench work.
The clean machine shcp also has adequate space.and bench cabinetry for tool storage by individual mechanics.
The clean machine shop area is conveniently located on the bottom floor of the service building and near the RCA. Maintenance foremen offices are located adjacent to the shop for efficient' communication.
The area also houses the service building store rocm and clean tool room which are adjacent to the shop.
A welding shop is also located in the area and can accomodate welder training / testing and shop fabrication of medium-sized welded assemblies.
.The hot machine shop has less space and equipment than the clean machine shop, but.large machine tools are installed and the space appears adequate-
- for a variety of " Hot" machining tasks due to good organization of the space involved. A special large test facility is included for snubber testing. The atmoshpere of the " Hot" shop is controlled, and radiation monitors, decontamination equipment and health physics support appeared adequate.
A " Hot" tnolroom for each unit is established in the auxiliary building by back-to-t,ack. wire cages for more efficient use of space.
Access is controlled and the toolroom is manned by a toolkeeper to support outage / maintenance needs.
A wide variety of gages, wrenches, pullers,
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slings, hoists and other tools are available for work in " Hot" areas.
Decontamination and HP support of the hot toolroom appeared adequate.
Conclusion After review of the above, the Team consensus was that maintenance facilities were a strength in the maintenance program.
11.
Response to Industry Issues The team's observation of the licensee's review and processing of several types of industry operating experience are described in this section. The inspection included a brief review of the process for handling operating experience described in licensee nrocedures AP-65 (FNP Operating Experience Evaluation Program) and AP-0-M-028 (SEE-IN Procedures Manual);
followed by examination of the licensee's handling of an INP0 Significant Operating Event Report '(SCER), an unsolicited vendor information letter involving a concern under consideration for deportability in accordance with 10 CFR Part 21, and 10 NRC Information Notices (ins).
AP-65 describes the responsibilities and functions to be performed in processing operating experience and translating it into corrective actions to improve plant safety and reliability.
Sources of this operating experience include vendor technical information, in-house events, information from INPO and other nuclear industry sources, and communications from the NRC.
Responsibilities for receipt screening and dissemination of the information, and for coordinating and tracking response actions are assigned to various groups depending upon the type of information and wisether a response is required.
The licensee's Systems Performance Group had principal responsibility for the vendor information letter and SOER examined by the team while their Technical Group had principal responsibility for the Information Notices.
The SOER examined was SOER 86-03 issued October 15, 1986, entitled " Check ~
Valve Failures or Degradation." The team's examination of the licensee's related actions reviewed the progress of the licensee response.
It was found that FNP delayed actions while the industry developed guidelines for
!
responding to the concern; that these guidelines (Electric Power Research Institute (EpRI) Report RP-2233-20) were issued formally by February,1988
'(the licensee had preliminary information in 1987); but that, as of the
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team's inspection in May 1989, no significant site actions had been undertaken responding to the guidelines.
Correspondence indicated an off-site engineering review was being undertaken, but initial schedules did not appear to have been met.
The vendor information letter considered by the team was a Limitorc;ue l
Maintenance Update letter dated August 17, 1988, which was received by the i
Systems Performance Group on September 1, 1988.
This letter described l
concerns regarding nuclear qualified valve operator torque and limit i
switches. The valve operator vendor, Limitorque Corporation, stated that one of the concerns was undergoing evaluation for deportability per
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On the basis of that statement, licensee personnel determined it should be handled as a 10CFR Part 21 report.
Procedure M-028 requires that Part 21 reports receive an expedited review. The team found that the vendor letter had been distributed to appropriate personnel for prompt review by the Systems Performance Group and that in most cases formal acknowledgement nf receipt and corrective actions were reported.
An exception was the Technical Group which did not respond. When questioned regarding this, Systems Performance personnel stated that no one was required to acknowledge receipt of Part 21 information transmitted to them.
Systems Performance was required to complete an evaluation of the vendor information (per Procedure AP-65) and obtain review and approval.
As of the team's inspection, the evaluation, review and approval had not been completed though over eight months had passed since receipt of the letter. The licensee appeared to have no guidance or responsibilities for assuring prompt completion of evaluation, review and approval of proposed actions or of actual completien of corrective actions. The team did find, however, that appropriate prompt action appeared to have been taken by the site personnel who had acknowledged the transmittal from Systems Performance. Personnel who had responded to the original distribution of the vendor information reported corrective actions that appeared appropriate and a check of several of these by the team found that they were implemented as stated.
For example, letter information was incorporated into plant training in October 1988.
The sample of Information Notices considered by the team and comments from the team's review are summarized below:
IN No.
Date Subject Team Comment 87-12 2/13/87 GE AKF - 2-25 Problem appli4s but is circuit breakers not yet resolved.
87-61 12/7/87 Failure of W-2 Final resolution S/3/89.
type cell switches Resolution verified by Team 88-11 4/7/88 Silicon bronze Problem applies but is not bolts for bus yet resolved.
Interim action bars appropriate.
87-61 5/31/88 Failure of W-2 Combined with 87-61 S-1 type cell switches Final resolution 3/3/89.
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88-42 6/23/88 Charging moter Problem applies and was bolt resolved.
l 88-50 7/18/88 Ferroresonar.ce Assessment very good.
88-57 8/8/88 SCR failures Final resolution with commitments 5/3/89.
88-72 9/2/88 DC MOV's Does not apply. Assessment verified by team.
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88-75 9/16/88 Anti pump circuit Final resolution with commitment 5/3/89.
88-86 10/21/88 Grounds on Final resolution with DC system commitment 5/8/89.
89-11 2/28/89 DC MOV's Same as. 88-72.
88-86 3/31/89 Grounds on DC Under assessment.
S-1 system In terms of assessing the problems described in the ins, the licensee appeared to expend a good deal of effort with good or excellent results.
However, in terms of the length of time to achieve. final resolutions, the team believes there is a weakness. Response to IN 87-12 and associated GE Service Information Letter is a notable case in point.
There is a long time from issuance of the IN to issuance of position memorandum. In some cases, corrective actions were initiated before issuance of the position memorandum. However, issuance of the position memorandum was considered by the team to be important, because it represents final assessment of the issue and contains formal internal commitments.
In summary, the team concluded that the licensee appeared to respond to most industry issues but that they were not timely in completing their final written responses. There appeared to be no procedural guidance or responsibilities specified for timeliness.
12. Maintenance Work Management The administrative control s for identifying, controlling, scheduling, authorizing and docur.ienting maintenance and maintenance related activites performed at the FNP are implemented by FNP-0-AP-52. FNP-0-AD-52 assigns responsibilities and directs the preparation and flow of paper necessary for the accomplishment and documentation of maintenance activities.
Specific areas inspected were scheduling /prioritization and post-maintenance testing.
FNP-0-AP-52, Appendix I, defines Priorities 1.
2, and 3.
The vast majority of maintenance work falls into Priority 3.
Interviews with licensee planning and scheduling personnel revealed that scheduling of maintenance activities are accomplished by a committee composed of the Daily Planning Supervisor and the two operations planners.
There is no documented guidance for the scheduling of work within c priority.
This activity is controlled strictly by the experience and judgement of the three individuals involved.
Currantly, Post-Maintenance Test (PMT) responsibilities are specified in
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l AP16 and AP52, however, there is no proceduralized guidance for the type
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or extent of PMT, outside of the envelope of the American Society of
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Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,
Section XI testing.
The licensee depends on the staff's expe-ience and
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engineering judgement to assure adequate PMT. The licensee has contracted r
with a consultant to write component specific post-maintenance test procedures.
To date, the consultant has submitted approximately 50 procedures with more to come.
The procedures are currently in a review status and were not available for review by the team.
The program is expected to be completed by mid year.
The above shows a program with sketchy or non-existent written guidance for the decision making process related to maintenance management. This appears to be consistent with APC/FNP managment philosophy:
strong emphasis on a small, experienced, aggressive and knowledgeable staff who make decisions based on their experience and judgement. The team did rot identify any examples where the lack of procedural guidance, in the decision making process, related to maintenance management, lead to circumstances adverse to quality. The concern in this management approach is the lack of consistency and continuity, which may occur with future staff changes. The lack of procedural 12ed guidance in the maintenance management decision making process is considered a weakness.
The maintenance department uses the MWR to authorize repair of equipment failures.
The MWR has several sections to document the description of failure, the cause of the failure, and a summary of the problem. These sections are as follows:
Failure of Description
Summary of Problem and Work Performed
Type of Failure
Mode of Failure
Cause of Failure
Cause Description Code The information from these sections is entered in the Maintenance History File and the NPRDS. The NRC team reviewed several hundred MWRs and NPRDS component reports.
The team determine these sections are often not adequately completed as disc,ussed in Sections B1 through B5.
The licensee's SAER group also identified in an audit Section 18 of the MWR was not properly completed in sufficient detail for trending and failure analysis. The licensee apparently recognizes this problem but has not yet taken corrective action.
13.
Maintenance Personnel The team inspected two aspects of maintenance personnel controls - (1)
training and (2) overtime. The inspection conducted and findings for each are described in the following paragraphs.
Training The team assessed the licensee's training through observations of maintenance craft capabilities while performing maintenance, discussions with maintenance personnel regarding the extent and frequency of training, discussions with training personnel, and review of training records and
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procedures. Records for 11 mechanical maintenance personnel (about 10% of the total) were reviewed in detall.
The licensee's program consists of classroom training with written tests and on-the-job training in which individuals are evaluated in their performance of selected tasks defined by Qualification Records (QRs). The-QRs guide and document the tasks in on-the-job training.
Training instructors and maintenance foremen perform the evaluations to acceptance standards given in the QRs.
The licensee's training program was stated to have initially received INP0 accreditation in 1986. At that time all maintenance personnel at or above the Journeyman level were " grandfathered" (considered to be adequately qualified basr!
on previous experience).
However, subsequently, even most " grandfathered" personnel have received complete training, tests and QR evaluations needed to assure their capabilities.
Supervisory personnel (e.g. foremen) were not required to have QRs but,
'i according to training personnel, have also taken training and associated tests.
The team verified, from their check of records for the sample of personnel, and from training lists, that most mechanical maintenance journeymen and foremen had completed all phases of the INPO accredited training program. The course material appeared adequate, but the training could not be observed - as none was in progt ess during the inspection.
Maintenance personnel appeared adequately qualified in work observed by the team and in discussions.
Subjectively, the team judged that the licensee's training program was not as detailed or extensive as some other licensee's.
However, this was offset by the fact that Farley appears to have a particularly stable work force which apparently exhibited satisfactory proficiency before the INP0 accredited training program was implemented.
The team concluded that the licensee had satisfactory training which included sufficient testing and evaluation to assure properly qualified maintenance personnel.
Overtime The team examined and assessed the licensee's maintenance overtime practices through discussions with maintenance personnel and through review of the following:
- The controlling procedure (FNP-0-AP-64)
- Farley Technical Specification (TS) 6.2.2.f
- NRC Safety Evaluation of the TS overtime requirement (letters from the NRC to the licensee dated 12/30/83 and 5/7/84)
- NRC GL 82-16 (9/20/82), NUREG-0737 Technical Specifications
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From their discussions, the team found that many maintenance personnel routinely work 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> / day 7 days / week during refueling outages.
The seventh day is at the option of the individual, but is often worked, resulting in an 84 hour9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> work week.
The Farley practices permits key maintenance personnel (e.g. instrument servicemen, machinists, welders and electricians) to work 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> / week or even more with approval by the maintenance manager or his maintenance group leader. In accordance with Farley procedure AP-64 this approval is made before the work is performed for posted temporary scheduled work but may be made after-the-fact in unexpected situations. The review is made as part of the normal by-weekly approval process for payroll time records.
Based on their discussions with Management and maintenance personnel, the team believes that the TS and procedure requirements are met.
The team-identified no pattern of mistakes or low morale as a result of excessive overtime.
However, the Farley maintenance overtime practices and requirements referred to above appear substantially less restrictive than the NRC intended. NRC GL-82-16 indicated that 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> work weeks should normally be used with an extension of up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> when necessitated by special or unforeseen plant conditions such as refueling.
T'e GL indicated that exceeding the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> could only be permitted wt n authorized by the plant manager or his deputy.
Farley TS allow thir
'horization to be performed for maintenance personnel by the Mainteru
- Manager or his designee (group supervisor).
The team's review of the Farley TS overtime practices and requirements found that they permit routine refueling outage overtime in excess of that intended by the NRC GL. Further, the Farley TS permits a lower level of authorization for overtime than that specified in the GL (maintenance manager versus plant manager).
This matter will be reviewed further within the NRC to determine if additional action is needed.
14.
Motor Operated Valve Program The team evaluated the licensee's program to upgrade maintenance, operation, and the design information of their motor-operated valves (MOV)
and actuators.
The team reviewed procedures, interviewed selected plant personnel, and examined design information for selected valves.
The program was examined to find if key elements were included:
program control responsibility, a design and equipment review, design document control, detailed procedures, a training program with operating experience reviews, testing, preventative and predictive maintenance, and procurement and spare parts control. The team reviewed the licensee's resolution of several technical issues to further assess the program.
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The team found, through interviews and document review, that the licensee was implementing portions of all the key elements listed above. A program coordinator had been appointed and corporate support was evident.
The design and equipment review has been performed for each units' 37 NRC Bulletin 85-03 valves. The licensee used MOVATS and new procedures during this review. The M0 VATS testing and torque switch setting program was extended to 58 EQ valves during the current Unit 2 outage.
Licensee's current plans include testing all EQ MOVs by the next Unit 2 refueling outage. The scope of the program outside of the 85-03 and EQ valves was not complete.
However, the licensee has plans to perform diagnostic testing on all safety-related valves within two refueling outages. As the valves are tested, design documents are being written. The new training program has included two foremen and eight electrical craftsmen; however, any electrical craftsman can work on a MOV. No new mechanic traintig has been planned. The licensee does not trend MOV failures or changes in thrust or torque switch settings within the allowed limits.
Specific findings:
No comprehensive program exists to eliminata valve packing leaks.
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The licensee has contacted other utilities aax; live-load packing but has no implementation schedule.
Several problems were noted related to the encapsulated containment
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spray pump containment sump suction isolation valves, MOVs 8826A(B).
See Section C.2.
Motor brake wiring for MOVs are not shown on ar.y wiring diagram. See
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Section C.2.
MOVs outside the MOVATS program have the close indication (red goes
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off when closed) on the same limit switch as the open torque switch bypass. See paragrcph C.2.
The licensee updated their thermal overload heater sizing design
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guide to conform to current industry practice. The team examined one calculation and found the technique acceptable.
The team found that the licensee responaed appropriately to several
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indust ry issues.
These issues included possible damaged magnesium rotors, metallic bead intrusion, and thermal binding of gate valves.
15. Quality Assurance / Quality Control (QA/QC) Involvement in Maintenance The Safety Audit and Engineering Review (SAER) group performs the quality assurance function at Farley. The inspectors reviewed the following SAER audit reports that had been performed in the maintenance areas.
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Audit No.
Date Audit Subject Results 89-06 4/12/89 Electrical Maint '
One Noncompliance for failure to. properly tag deficient equipment l
l 88-18 11/1/88 Surveillance Testing Comments on several (Maintenance)
examples of failure to properly complete paper work l
9/22/88 Surveillance Testing Comments on examples (I&C)
of failure to properly complete paper work 88-16 9/19/88 Control of Measuring Uncontrolled vendor and Test Equipment manuals in I&C calibration lab
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88-43 8/10/88 Maint (Instruments and Controls)
88-13 8/10/88 Maint (Mechanical)
No procedure for painting inside containment, contrary to FSAR 6/21/88 MOVATS Activities Lists 6 noncompli~
ances on MOVATS from audit 88-1 and states that corrective action was completed 88-4 3/18/88 Electrical Maintenance Finding on use of uncontrolled vendor drawings.
This is a repeat item f em 87/4.
Comment an block 18 of MWR not filled out with sufficient description of failure.
Comoents repeated from.1986 audit 88-15 9/8/88 Control of Special Findings on welding Processes procedure l
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From this review, the team observed that SAER is perfoiming numerous audits in the maintenance area and having substantive findings.
There were several instances where comments from previous audits were repeated verbatim in subsequent audits, indicating that the issue was not corrected.
The team observed that SAER is doing a competent job and has the technical respect of the plant staff although they don't always egree s
f on the significance of audit findings. Several members of the SAER staff have come from operations and have an excellent knowledge of the plant.
The team concluded that there is effective monitoring of maintenance by quality assurance at Farley.
The team examined.the role of QC in the maintenance process. Farley QC policies and practices are detailed by plant procedure FNP-0-AP-31, which established the responsibilities and controls in which quality control is accomplished by a " Peer" review.
In lieu of the traditional QC organization, the Farley's " Peer" QC program is based on the premise that,
"Each employee performing a task always has the primary responsibility for the quality of work being performed. The first line supervisor (foreman) always has the primary responsibility for controlling the quality of work being performed by those over whca he has supervisory responsibility. The Group Supervisor always has the primary responsibility for identifying problems of quality within his area of responsibility, for taking appropriate immediate corrective action, for correcting quality problems and for taking further corrective action to eliminate or reduce the' probability of recurrence."
Based on this premise, the QC organization consist of only a QC engineer and five other QC personnel.
The departments efforts are primarily dedicated to Material procurement and qualification activities with minimal effort expended to inspection of maintenance activities.
Cased on the above QC program, the following inspection / sign-offs are specified in maintenance proceduref..
"M" Points -
Craftsman performing step to sign-off
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Responsible supervisor to sign-cff
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These steps require independent inspection and are to be accomplished by certified inspectors within the discipline but who are not involved in the work activity nor work for the foreman responsible for the task being accomplished.
In general, all journeymen and foreman are qualified inspectors.
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l Maintenance personnel pointed out that even though journeymen are l
qualified, practice is to have independent inspections performed by l
foremen. In addition to the above inspections / sign-offs, paragraph 6.1 of procedure FNP-0-AP-31, required the QC Engineer to provide overall
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responsibility for the adequacy and effectiveness of the quelity control
inspections for which independent inspections apply.
This is to be
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accomplished by observing " selected independent inspections" to ensure inspections are performed, evaluated and documented in accordance with the requirements of procedure FNP-0-AP-31.
i The team requested records of the QC Engineer's observations of " selected I
independent inspections." The QC Engineer stated that records were not available and that only a few observations (none in 1985 and 1987, 3 in 1986, and none tc March 1988) had been made.
In. March 1988, the NRC identified this as a weakness in tne Farley QC program (see NRC Report 50-348,364/88-05).
The QC enginear further. stated that after the NRC l
finding, additional independent observations (approximately 6) were made
by QC.
Discrepancies were found and there was disagreement about how to resolve the discrepancies. Since no procedure guidelines existed relative to how to perform the observations, what to look for, how to resolve findings, how to document findings, etc.,
the observations were discontinued until a Droctdure could be issued. The procedure still has not been issued.
This is considered to be r significant weakness in the QC program since independent observations. 4 vital part of the Peer inspection progre?, are not being accomplished. The team considered a contributing factor to this weakness is the small QC staf f.
With only six people in the QC organi;:ation and their being predominantly involved in material activities, the QC staff appears inadequate to ef fectively ensure that peer inspections are being done correctly.
The team noted that independent inspectors (journeymen and foremen),
except Nondestructive Examination examiners, are not required to pass an annual eye exam.
Based on paragraph 2.5 of American National Standards Institute (ANSI) N45.2.6-1978, the applicable qualification document, the responsible organization is to identify any special physical characteristics needed in the performance of each activity and these characteristics are to be verified by examinations at intervals not to exceed one year.
The team considers that inspectors required to use or read measuring and test equipment to critical dimensions should recebe an annual eye exam.
Also, paragraph 2.3 of ANSI N45.2.6.-1978, requires that inspectors who have not performed inspections, examinations or testing activities in his qualified area for a period of one year shall be reevaluated by determination of required capability in accordance with original qualification requirements.
This requirement is not included in the Farley Peer in.spection program.
Farley considers
" Inspection, examination, and testing activities are inherently integrateo into the FNP staff's routine job responsibilities such that when a person holds a given position, he routinely performs those inspections, examination, and testing activities for which that position is responsible.
Therefore, an annual demonstration of proficiency has no meaning under the FNP Quality Control program."
(See Farley 10 CFR 50.59 Safety Evaluation for
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Revision 8 to FNP-0-AP-31). The team considers that the program should include some provision for evalaution of inspector's capability should he not perform inspections for a year.
The failure to require annual eye exams and failure to provide for evaluation of inspector's capability should he not perform inspections for a year are considered to be weaknesses in the QC orogram.
The team noted very limited use of
"I" points in the maintenance procedure.
It appeared the use of independent inspections was reserved for required code or regulatory inspections. There are other activities, e.g. torquing of ASME Class I valve closures, where it appears that independent inspections would be desirable.
Since independent Peer inspections play a vital role in the Farley QC program, the Team considers
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that small number of independent inspections to be a weakness in the QC program.
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J 16.
Engineering Support for Maintenance l
The maintenance department was found to have very limited engineering support at the plant site.
In the maintenance department itself, three staff engineers report to the maintenance manager and one or two engineers are assigned to each of the three maintenance groups, electrical, mechanical, and I&C.
Discussions with the licensee revealed these maintenance engineers perform duties such as scheduling preventative
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maintenance rather than pure engineering functions.
The maintenance department appears to depend on the skill of craft specialists, foreman, and group supervisors to perform the required daily engineering functions.
There are other groups on site which provide limited engineering support to the maintenance department, but this is not their main function. These groups are the System Performance and Planning Department, the Operations Department, the Plant Modification Department, and the SAER group. Except for system performance, the other groups only provide individual engineers for tasks considered urgent.
The System Performance group perform the
following maintenance engineering functions: trend reactor trip breakers;
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trend safety injection lines; trend pressurizer surge line; perform j
vibration analysis on pumps; trend pressure drops and flow for pumps; I
trend incident reports; and trend safety-related room coolers using I
service water. Operations performs the trending for valve performance.
Off site, engineering support is available from corporate headquarters, i
the architect engineer, Becthel Power Corporation, and equipment vendors.
However, no system engineering program is available eitbar on or off site where engineers are assigned specific system responsibility.
The licensee has used off site engineering to provide support.
Several
examples are listed: battery load studies for the DC system; battery charger investigations; batte ry replacements; motor operated valve i
testing; design assistance for replacement of a damaged hanger; and incore instrumentation thimble tube eddy current examination. These items are discussed in other parts of this report.
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LThe team observed that the licensee was not using engineering support to-perform ' the followingj functions:
review of Maintenance Work History;.
review of NPRDS;. review'of the completed MWRs; performance of-root cause analysis; trending. of failures,(except.' where previouslydiscussed);
performance. of plant walkdowns; provide technical assistar.ce in' solid state electronics [ battery chargers 'and inverters].
These tasks 'are-i usually assigned to. maintenance engineers at other plants;
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The team hasHdetermined that engineering support for the maintenance department..is a weakness.
This matter is discussed further in.
Section C.12.
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17. Maintenance Related Data The team examined various maintenance related data relative to the success of the licensee's maintenance and maintenance-related activitics. These included current. internally trended data posted by the. licensee, NRC Office of Analysis and Evaluation of Operating Data (AE00) data (1988 and'
first quarter 1989) and' NRC Licensed Operating Reactor' Status Summary Report Data as of February 28, 1989. Overall, the team concluded that the data provided evidence that Farley plant maintenance had been sufficient-to' support above average operational' performance.
The 11censee's internel data shows that the number of open work orders was increasing, but that historical data indicated that the trend was similar to that_ experienced -in the past when. refueling outages were being undertaken.
The AE00 performance data examined by the team included automatic scrams while critical, safety system actuations,- significant events, safety system failures, forced outage rate, and equipment forced ' outages /1000 critical hours. Both Farley units showed above average performance during 1988 as compared to other plants.
First quarter 1989 data supported continued above average performance.
Data in the Licensed Operating Reactors Summary Report indicated high availability and supported the low forced outage rate reported by AEOD.
The performance data examined indirectly indicate a successful maintenance program at FNP.
18. Maintenance Self Assessment In February 1988, Farley completed a maintenance self assessment performed by e.n outside contractor. The team reviewed the documented results of that assessment and concluded that it was a worthwhile effort with valid findings. The licensee established an action item tracking system for the recommendations and the status as of March 21, 1989, reflects that action has been taken on most of the 50 items. Approximately 20% are not yet listed as closed.
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It appears that the licensee has taken substantial action and dedicated resources to implement the recommendations but the results have not always been totally successful.
For example the maintenance department established a goal in early 1988 to improve the material condition of the
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service water intate structure, yet the team observed numerous deficiencies at the SWIS during this inspection. Licensee representatives stated that the SWIS material condition had improved in 1988 but had declined again in early 1989.
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S~E C T I 0 N C
ISSUES
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ISSUE NO. 1 CALIBRATION OF DC CIRCUIT BREAKERS l
The team performed walkdowns in the auxiliary building for Units 1 and 2 to determine the condition and calibration status of the safety-related 125V DC switchgear. The switchgear examined was the metal clad General Electric Type AK DC circuit breakers which are the main feeder (output)
circuit breakers for the Trains A and B batteries and battery chargers.
During these walkdowns, the team identified that many of these circuit breakers had calibration stickers dated during the preoperational testing-startup period of the units. These calibration dates went as far back as.1975 for Unit I and 1977 for Unit 2.
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The team identified that 14 of the 24 Unit I circuit breakers had current (up-to-date) calibration stickers. Only 2 of the 23 circuit breakers for Unit 2 had current calibration stickers. A current calibration sticker on the circuit breaker means the circuit' breaker, specifically the trip units, has been tested to vcrify that it meets specifications and operational requirements. The licensee was requested to explain why all of the circuit breakers had not been calibrated since 16 circuit breakers had a current calibration sticker.
The licensee responded that PM has been performed on all the circuit breaker but not all have been calibrated. The PM performed was cleaning and lubrication, not trip unit calibration. The team requested the licensee provide a calibration W d preventive maintenance list for all Units 1 and 2 circuit breakers to determine the exact status.
In addition, calibration data sheets were also requested.
The licensee provided the requested PM list which included the circuit breaker cubicle location, the cubicle name, the cubicle required trip rating, date last PM was performed on installed circuit breaker, and date last trip unit calibration was performed.
(Note - The circuit breakers are removable and interchangeable in the switchgear cubicles, and the trip units are removable and interchangeable in the circuit breakers. The trip unit rating is determined by the load of the bus for the cubicle.) The PM list is as follows which includes the circuit breaker calibration sticker date:
Unit 1 PM List Circuit Circuit Circuit Breaker Breaker Breaker Breaker Cubicle Last Last Calibration Cubicle Cubicle Trip Unit Calibration PM Sticker Location Name Rating-amps Performed Performed Date LA05 1A Battery 1000 4/77 11/86 10/86
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LA06 1C DG
10/76 4/85 1975 LA08 1A Panel 225 10/86 11/86 10/86 LA09 1A Batt charger 600 9/76 4/88 1975 LA13 1A Inverter 100 11/86 11/B6 11/86
.LA12 IB Inverter 100 10/86 10/86 11/86 LA13 IB Panel 225 10/76 10/86 None
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LA16 1F Inverter 100 10/86 4/88 10/86 LA17 1-2A DG
3/87 4/87 3/87 LA18'
1C Batt charger 600 10/76 10/86 1975 l
LA20 IC Panel 225 10/86 4/88 10/86 LB02 10 Panel 125 10/86 4/88 10/86 LB03 IB Batt charger 600 10/76 6/86 1975 LB04 1C Inverter 100 6/76 10/86 11/86 LB06 ID Inverter 100 11/86 10/86 10/86 LB07 IE Panel 225 10/86 10/86 10/86 LB08 IE Inverter 100 10/86 10/86 None LB10 IG Inverter 100 10/86 10/86 9/86 LB11 2G Inverter
11/76 4/85 1975 LB12 IC Batt charger 600 10/76 10/86 1975 LB14 1F Panel 225 10/86 10/86 10/86 LB15 Security 150 7/80 4/88 None LB18 IB Battery 1000 4/77 10/86 10/86 LB19 IB DG
10/76 4/88 1975 Unit 2 PM List LA05 2A Battery 1000 3/78 10/87 1977
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LA06 1C DG
2/78 6/86 1977 j
LA08 2A Panel 225 2/78 10/87 1977 LA09 2A Batt charger 600 2/78-11/86 None LA10 2A Inverter 100 1/79 11/87 1979 LA12 2B Inverter 100 2/87 2/88 None LA13 2B Panel 225 2/78 11/87 1977 LA16 2F Inverter 100 2/78 11/87 1977 LA17 1-2A DG
3/87 11/87 1977 LA18 2C Batt charger 600 2/78 11/86 1977 LA20 2C Panel 225 2/78 7/87 None LB02 2D Panel 225 3/78 11/87 1978 LB03 2B Batt charger 600 3/78 2/85 1977 LB04 2C Inverter 100 3/78 11/87 1977 LB06 2D Inverter 100 3/78 3/87 1977 LB07 2E Panel 225 3/78 11/87 1977 LB08 2E Inverter 100 3/78 11/87 1977 LB10 2G Inverter 100 3/78 11/87 1977
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LB11 2C DG
3/78 11/87 1977 LB12 2C Batt charger 600 3/78 4/86 1977 LB14 2F Panel 225 3/78 11/87 1977 LB18 2B Battery 1000 3/78 7/87 1977 LB19 2B DG
3/87 9/86 3/87 l
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A review. of the PM-List reveals that for Unit 1, circuit breakers in cubicles LA05, LB04, and LB18 had a current calibration. sticker although the trip unit was notl calibrated.
This occurred because the licensee deleted the calibration requirements (temporarily) from the test procedure when PM was performed. (Discussed in later paragrsph). The.. team reviewed 14 work authorizations (WA) and the calibration data sheets for circuit breakers that had been calibrated. The WA List is as.follows and includes the test procedure number (s).
WA List (Calibration)
Removed Installed from in Test Unit Item-No.
'Date Cubicle Cubicle Procedure No.
B001B-5/5 10/28/86 LB07 LA20 FNP-0-MP-28.7 &
28,116
B001A-A/3 10/20/86 LA08 LB06
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B001A-A/5 11/10/86 LA10 LB04
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1-B001A-A/6 11/3/86 LA18 LA10
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B001A-A/8 10/24/86 LAlf LB07
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LA17.
3/27/86 LA1)
LA17 FNP-0-MP-28.116
B001A/11 10/29/86 LA20 LA13 FNP-0-MP-28.7 &-
28.116
B0018/1
~10/17/86 LB02 LB02
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B0018-B/6 10/20/86 LB08 LA16
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.1 B0018-B/7 10/14/86-LB10 LB08
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B001B-B/4 10/30/86 LB06 LA12
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B001B-B/10 10/27/86 LB14 LB14
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'2 Q2R428001B'B/12 3/19/87 LB19-LB19 FNP-0-MP-28.116
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LA17 3/26/87 LA17 LA17.
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From the list, it can be seen that most of the circuit breakers have been
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For 2xample, in the Unit 2 PM List, LA08 requires a 225 ampere rating and LB06 i
requires a 100 ampere rating. Since the circuit breakers are interchanged.
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between cubicles. the trip units rust also be changed for the required rating. This interchanging of circuit breakers between' cubicles created a deficiency. This deficiency is the "as found" data was not taken for the existing trip unit if the trip unit was to be replaced, with another trip unit of a different rating. The licensee stated corrective action would
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be taken to correct this deficiency by revising FNP-0-EMP-1340.1. This i
revision would require the "as found" data to be taken before the trip unit was removed for replacement.
i The licensee had preventive maintenance performed during the 1985-1988 time period on the 125V DC circuit breakers. The PM required the circuit l
breakers to be removed from service. The time to perform the trip unit l
calibration would have been during these PMs. The team was told that the licensee did not have an adequate supply of spare parts for the circuit i
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. breakers. lTherefore, the licensee decided not to test the trip unit since spare parts were. not available to repair or replace any defective trip units.
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Maintenance Procedure FNP-0-MP-28.116, DC Circuit Breaker Testing was the applicable procedure used during 1987.
One of; the purposes listed in :
Section 1.5 is "To test and verify proper long time trip characteristics, short time trip values and times, and instantaneous values and times." -A procedure' change request-form Temporary Change Notice (TCN) from-FNP-0-AP-1-dated November 7,1987, was implemented to delete the' sections -
pertaining' to. testing and: the associated data sheets.
During this time period' ~ the' licensee had a. preventive maintenance program requiring the
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125V DC circuit breaker be calibrated at five year intervals.
This program is'still in effect. The team requested the licensee's SAER (QA);
group - review the TCN 4A to 'FNP-0-MP-28.116, and provide an evaluation.
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The preliminary finding from the SAER audit are listed below:
SAER Evaluation (Preliminary)
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FNP-0-AP-1 requires a Nuclear Safety Evaluation Check List to be completed when preparing a TCN.
A Nuclear. Safety Evaluation Check List'was attached to TCN 4A of FNP-0-MP-28.116 and was signed by the preparer and reviewer. However, there are no check marks to indicate the items listed on the Nuclear Safety Evaluation Check List were-addressed.
2.
FNP-0-AP-1, Section 6.2, states in part,
" Safety-related plant procedures not requiring final approval by the GMNP are approved by the Manager responsible for the procedure development." Contrary to the above, FNP-0-MP-28.116 TCN 4A received final approval by the'
Electrical Maintenance Supervisor not the Maintenance Manager.
3.
'FNP-0-AP-1, Section 7.3.3 and Section 6.2 require Manager approval of temporary. changes to procedures which represent a change of intent prior to their implementation.
Contrary to the above TCN 4A to FNP-0-MP-28.116 was not approved by the appropriate manager prior to its implementation.
Discussion This temporary change to the prom dure appears to represent a change of procedure intent and insufficient documentation was presented to justify the temporary change Le the procedure as not representing a change of intent.
4.
The " Reason for Change" (Step 2.3) indicated on the Procedure Request Form for TCN 4A of FNP-0-MP-28.116 states, " Testing of breakers will not be performed this cutage, only cleaning, lubricating correct operations." This appears to be a statement of fact not a reason for
the change.
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Sect 1on. '8.3.2.1.5.of the Final Safety Analysis Report (FSAR)
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. indicates "The DC'switchgear, batteries, and battery chargers will,be inspected and tested on a periodic basis in ' accordance.with manufacturer's. recommendation." It 'is not clear. as to the effect-of TCN 4A to FNP-0-MP-28,116 as it relates to this section'of the FSAR.
The team concurs with.these findings and concludes that items 2 and 3 are an example where the licensee has failed to follow his program and procedures.
In addition, the licensee failed to perform an adequate engineering analysis before deciding not to calibrate the circuit breakers.
This is an example of violation 348,364/89-10-01, discussed further in Section C.5.
FNP-0-MP-28.116 (old. test procedure)
has been superceded by FNP-0-EMP-1340.01, Revision 0, issued April 7,1989. The licensee, at the request of the team, was in the process of calibrating the Unit 2 125V DC circuit breaker using FNP-0-EMP-1340.01 at the end of this inspection.
'In another area concerning maintenance for these' GE AK type circuit breakers, the licensee has not implemented recommendations by the General Electric Compnay (GE).
GE, SIL-448, Maintenance and Lubricants for GE Type AK Circuit Breakers recommended lubricant (GE. Specification D50HD38)
.be:used and annual proventive maintenance be performed.
The licensee's System Performance Group issued Problem Report No. OEE-088, dated
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This has not yet been accomplished by - the licensee, although NRC.Information Notice 87-12: Potential Problems with Metal Clad Circuit Breakers, General Electric Type AKF-2-25, dated February 13, 1987 was issued. Notice 87-12 discusses problems identified with the GE AKF type circuit breakers.
It also lists recommendations for the entire'GE AK series circuit breakers.
One other deficiency identified during the inspection with the 125V DC circuit breakers is the lack of " cell switch" maintenance.
The cell switch is an interlocking switch located inside the cubicle, not the breaker.
Maintenance procedures at FNP do not call for cell switch maintenance.
The licensee was performing a loss of off site power surveillance test per 2. SOP-37.1C for Unit 2 during the inspection period when the cell switch in LB12 for battery charger 2C failed. The licensee stated FNP-0-EMP-1340.01 will be revised in the future to include cell switch maintenance.
The team has identified deficiencies with the implementation of the calibration program for the safety-related 125V DC circuit breakers.
The licensee had not performed the required calibration in the past and did not plan to perform them during this Unit 2 outage. The licensee did not have adequate spare parts for the GE AK type circuit breakers and that was used as justification for not checking calibration.
In addition, the licensee had failed to take the proper "as found" data when calibrations were performed in the past.
The team concluded the maintenance program implementation for the 125V DC
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circuit breakers has been unsatisfactory.
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ISSUE NO.2 MOTOR OPERATED VALVE PROBLEMS The team inspected Unit 2 MOV 8826B, an encapsulated valve in the-containment spray system, and questioned certain design aspects of the valve to evaluate how the licensee was implementing the MOV program. The team also reviewed MWRs worked on the ather CS encapsulated valves. Based on ihe licensee's responses, the team concluded that the valves could perform their design function.
Specific findings included:
MWR 174071 documented severe corrosion problems for the components in
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U1 CS 8826B limit switch compartment. While the affected components were replaced, the team was not shown any documentation to demonstrate what caused the coriosion and why the other encapsulated valves were not likewise affected.
The team found the disconnected motor heater leads on U2 8826B
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wrapped in black electrical tape. The tape was not identified during any previous licensee EQ inspection of the actuator.
The licensee argued that a short through the heater could not spuriously actuate this particular valve while it was in the open or accident condition.
However, detailed knowledge of all safety related valves and the condition of the motor heater leads would be required to generalize this conclusion.
The team found that the U2 8826B valve torque switch settings were
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different than the as left settings recorded on the last MWR that
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worked the actuator.
The MWR listed both the open and closed settings as 1.75.
The actual settings were 2.0 (open) and 1.9 (close). The settings were still within the allowable ranges. Also, on the same MWR, the actuator size was incorrectly listed as an l'
SMB-00 instead of an SMB-2.
Actuator size and style is used in the i
licensee procedures to direct the worker to the right torque switch
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i figures in the procedure.
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The motor brake leads for U2 8826B were not shown on any drawing l
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shown to the team. The drawings normally supplied to the craft, the
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elementary diagram (D-207190) and the connection diagram (B-204612),
i do not show if the motor has a brake. Also, the vendor supplied
wiring diagram ( U-209579A) shows that a brake is attached to the motor but does not show the connections. With no drawings covering the brake connections, there is a significant potential that brake connections can be miswired during work on the valve.
Based on discussion with planning personnel, this problem applies to all motor
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I operators at FNP.
MOVs outside the MOVATS program have the closed indication (red light
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goes off when closed) on the same limit switch as the open torque switch bypass. For example, for U2 8826B, both contacts associated i
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with these functions are on limit switch rotor #2. Thus, the torque switch would be back in the circuit after the valve opened only 5%.
During accident conditions, the torque switch bypass may be required
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while opening the valve since the valve is not noemily cycled with i
differential pressure.
Also, this valve could not be manually operated since it is encapsulated.
Limit switch rotor #4 is unused in this actuator and could be used. The licensee has separated these two functions (indication and torque switch bypass) on the 85-03 valves and plans to change the 9ther valves in the futur p-_g.
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ISSUE N0.3.
L QUALITY OF INSTRUMENT ~ AIR
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purpose of GL 88-14 is to request that each licensee review NUREG 1275, l'
Volume 2 (Operating Experience Feedback Report - Air System Problems)~ and then perform a design and-operation verification of AS. Verification was-to include:
Verification by test that actual inst'rument air quality is Item 1
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consistent with the manufacturer's recommendations for individual' components served.
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Verification that maintenance practices,- emergency
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procedures, and _ training are adequate to_ ensure that safety-related equipment will function as' intended on loss of instrument air.
. Verification of the design of the entire instrument air Iter. 3
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system including verification by test that air-operated safety-related components will perform cs expected.in accordance with all design basis events, including a loss of the normal instrument air system.
This desfgn verification should include an analysis of current air-operated component failure postions to verify that they are correct for assuring required safety functions.
A final request, Item 4, was-to provide a discussion of the licensee's program for maintaining proper instrument air quality.
The team reviewed the licensee's preliminary response, dated February 3, 1989, to GL 88-14 'and noted licensee statements as follows:
The reviews and/or investigations to date indicate that the design,
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installation, testing, operation and maintenance of the instrument air systems at FNP are adequate to ensure the proper and reliable operation of pneumatically operated, safety-related equipment.
Upon completion of the additional evaluations, a subsequent report
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will be submitted.
This report is scheduled to be provided by June 1,1989. A final report will be issued. upon completion of all actions associated with GL 88-14.
Documentation Review The team held discussions with cognizant licensee personnel and reviewed additional documentation associated with GL 88-14 activities as follows:
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'l Documentation associated wit.h air sampling and Station Service Air
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Compressor maintenance and reliability l
Documentation associated with design verification of Instrument Air
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end users (valves, dampers, etc.)
Documentation associated with reliability of emergency air
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compressors.
Findings The team noted that the licensee had completed some testing
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associated with GL-88-14 by the date of this inspection.
An initiated air quality test had been completed at 27 locations. Tests had revealed particulate of greater than 100 microns diameter (twenty times the normal requirement) at 13 locations and particulate of. between 50 and 100 microns at all except 3 test locations. These results were forwarded to the appropriate component manufacturer for " review and acceptance."
The team asked whether cognizant licensee personnel had determined the reason for the poor air quality and were informed that the part.iculates were due to rust in the cast iron headers involved and that the majority of end use devices were protected by filte -regulators.
The team requested a licensee commitment to complete installation of filter-regulators on all instrument air end-use devices.
This commitment was not obtained.
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The team noted that tests were not yet initiated to verify the fail-safe position of end-use devices on loss-of-instrument air.
Cognizant licensee personnel indicated that pitns were to use IMP-0.11, " Instrument Airline ' and Pressure Regulator Preventive Maintenance Procedure," to accomplish verification of fail-safe devices.
The team reviewed the latest revision of IMP-0.11 (Rev. 4, dated 11/24/87) and noted that the procedure only included valves in containment, auxiliary building or main steam valve room "which cannot be normally maintained due to critical operations considerations or the inaccessibility of the valves due to their location."
Therefore, many additional valves must be included.
Further, no verification of fail-safe position was presently included. The team requested clarification from cognizant licensee personnel as to verification testing which has been completed in response to GL 88-14.
Cognizant licensee personnel responded that previous testing had verified Main Steam Isolation Valve (MSIV)
closures on loss-of-air, operability of PORVs from bottled nitrogen, and accumulator testing for the TDAFP steam valve. Other devices were tested during preoperations testing.
No further testing has occurred.
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J Conclusion i
After review of the above, the team concluded that licensee actions in j
response to GL 88-14 do not appear to meet the intent of the GL. Further
this appeared to be caused by lack of management commitment.
The-team J
informed cognizant licensee personnel that NRC concern, regarding need for
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completion of actions necessary to protect instrument air end-use devices
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from poor air quality would be identified by IFI 348,364/89-10-03:
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" Adequacy of Action to protect End-Use Devices from Poor Quality l
Instrument Air."
Following receipt and evaluation of the licensee's final written response to GL 88-14, the actions will be reviewed during a future NRC inspection.
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ISSUE NO.4 EMERGENCY' AIR COMPRESSORS l
Background As discussed lin Section B.5, the main steam atmospheric relief' valves have q
their own emergency air compressors to maintain operability on
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loss of-instrument air..These compressors also supply emergency air to TDAFP steam supply valves,
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Amendments 52 and 53 to the FSAR state that an assured backup air supply system' will be provided for the main steam relief valves to allow controlled atmospheric venting of, the steam generators, in conjunction -
with auxiliary feedwater addition, during the initial cooldown stage, until the primary coolant. temperature and pressure permits residual heat removal system. initiation.
The system will includr redundant air compressors, pressure. regulator and piping, and wi? 5e designed to Seismic Category I requirements.
The compressors wiil be located in an
. accessible _ area isolated from the main steam valve room.
The design basi s for the backup air system is described in FSAR Section 10.3.8 as'follows:
In the event of a high-energy line break which prohibits operator access to the: manual handwheel located on each power-operated relief valve and the simultaneous loss of offsite power and valve air supply, an alternate air supply is located in the EL 100-ft area in room 194 as shown in Figure 1,2-5 for Unit 1 and in room 2189 for Unit 2 directly beneath the EL 127-ft main steam and feedwater valve room. This area is isolated from the main steam and feedwater valve room and would be accessible following-any main steam or feedwater line break that makes the atmospheric relief valves inaccessible for manual control. The alternate air supply consists
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of two redundant, seismic, self-contained, nonlubricated air compressors rated at 41.6 cu. ft./ min at 100 psig.
The team became aware of potential reliability problems associated with the emergency air compressors due to observation of a deficiency tag (MWR No.180777C) for compressor C0002A for Unit 1.
This MWR was on hold awaiting parts (a pressure switch). MWR 180777C had been issued due to failure of surveillance test FNP-1-STP-65.1 associated with MWR 180777B which had been issued due to failure of STP-65.1 associated with MWR 180777A, etc. Details associated with this sequence are as follows:
MWR Issued Item 180777 8/29/88 Issued due to failure of intercooler pressure while performing STP-65.1.
Replaced HP valves
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180777A 9/27/88 Intercooler pressure still too low. Cleaned and lapped (2) LP valves and (1) HP valve 180777B 9/30/88 Autostops at 127# when max allowable is 122#
Auto unloads at 117# when max is 115# per STP-65.1, calibrated PS 1A 180777C 10/3/88 Auto starts at 112# with max at 102#. Still unloading at 117# with max at 115#, on hold awaiting parts.
The team noted that Unit 1 emergency air compressor C0002A was presently not in conformance with FNP-1-STP-65.1, " Emergency Air Compressor IA Operability Test," and requested clarification from cognizant licensee
- personnel sas to conformance with TS requirements for this condition.
Cognizant licensee personnel responded that the emergency air compressors were not considered TS related and no Limited Condition of Operation (LCO)
condition existed even though Unit I was in mode 1.
The team noted the FSAR design basis for the emergency air system and contended that this equipment should be treated like TS related equipment and some priority should be placed on solving the reliability problems.
The team reviewed MWRs associated with the Unit I and Unit 2 emergency air corspressors in order to assess historic reliability.
Results were as follows:
Unit 2 Compressor C002A MWR No.
Issued Problem Description 172982 5/15/88 2A Compressor will not run 139266 2/9/88 Speed control problem 139300 1/20/88 Conduit to oil press SW. broken 119475 11/21/85 Compressor will not load Unit 2 Compressor C0002B 304228 2/12/89 Complete lube senedule 139221D 3/29/88 Out-of-Spec per STP-65.1
139221C 9/16/87 Out-of-Spec per STP-65.1 l
139221B 9/7/87 Out-of-Spec per STP-65.1 139221A 9/6/87 Intercooler press still less than l
required
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139234 9/4/87 Distance piece press problem with A/C loaded - repair 139221 9/4/87 Intercooler press less than required
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Unit 1 Compressor C0002A 187547 3/4/89 Does not unload until press. is 116#
301570 12/8/88 Calibrated gauge per FNP-0-IMP-415.1A 301571 12/8/88 Completed lube schedule 186776 11/1/88 Completed load and unload test in constant speed mode 184888 10/29/88 Does not turn off in start /stop mode.
Press. switch out-of-tolerance 180777C See Previous Paragraphs 180777B 180777A
.180777 144658 3/21/87 High intercooler press. problem 157569-3/19/87 Calibrated PS 157570 3/16/87 Calibrated press. gauge 147980A 9/14/86 Does not develop intercooler press nor distance piece 147980 9/10/86 Will not develop intercooler press. nor distance piece press.
121887 12/12/85 Will not operate correctly in constant speed control Unit 1 Compressor C0002B 158040A 6/5/87 Does not load / unload per STP-65.2 158040 6/4/87 Starts and Stops out of spec setpoints 15111A 9/7/86 Auxiliary valve still cycling in const.
speed mode 15111 9/5/86 Auxiliary valve cycles frequently in constant speed mode
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121888B 3/11/86 Press. switch worn
12/554 3/9/86 Will not operate properly in const.
speed mode 121888A 12/21/85 Still will not operate correctly in const, speed mode 121888 12/12/85 Will not operate correctly in constant speed control 119476 11/22/85 Will not load in ccnst. speed mode After review of the above, the team observed that there have been apparent historical problems which limited the operability of the emergency air compressors.
Cognizant licenseo personnel agreed but rioted that maintenance was working with the vendor to correct the problems.
Cognizant licensee personnel further contended that the compressors were capable of performing their intended function even if in non-conformance with the STP acceptance criteria.
The team noted that STP-65.1 and 65.2 establi.;hed the acceptance criteria to establish operability and that these compressors are often in non-conformance for extended lengths of time.
Conclusion The team informed cognizant licensee personnel that NRC concern regarding the reliability of the emergency air compressors and their operability l
requirements would be idantified by IFI 348,364/89-10-04:
" Lack of Operability Requirements for Emergency Air Compressors." This matter will be reviewed further within the NRC to determine if further action is required.
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ISSUE NO. 5 j
MAINTENANCE PROCEDURES During observation of maintenance in progress, the team noted several examples of failure to follow procedures or of inadequate procedures.
This is an i'dication that the verbatim compliance with procedures is not n
always the practice at Farley and perhaps needs more management emphasis.
The following examples were observed.
As discussed in issue C-1, DC circuit breakers have not been calibrated for long periods of time. 'This was apparently accomplished by a Temporary Change Notice (TCN) Number 4a to proceriure FNP-0-MP-28.116 which deleted the requirement to calibrate the breakers from that procedure. TCN 4a was processed on November 7,1987, initiated by a member of the maintenance group, approved by a Senior Reactor Operator (SRO), and given final approval on the same day by a Group Supervisor.
This change was not properly conducted in compliance with procedure FNP-0-AP-1 in that the deletion of the breaker calibration appears to be an intent change that should have _been approved by the Maintenance Manager prior to implementation.
If this had not been an intent change it should have received final approval within 60 days by the Maintenance Manager which was apparently not done. Also, the Nuclear Safety Evaluation Check List was not completed as required by FNP-0-AP-1.
As discussed in Section B.6, the team observed on May 10, 1989, maintenance work on the Unit 2 turbine driven auxiliary feedwater pump.
This work was done to remove a secondary seal part that was erroneously installed earlier. The procedure was initialed as if the extra seal part was installed again when in fact it wasn't.
This step should have been deleted from the procedure by TCN. The work eppeared to be performed correctly but this represents an example of failure to follow procedure verbatim.
As discussed in Section B.6 on May 11,1989, the team observed in shop welding repairs on a fire door.
The welding procedure CSM-10 issued to the welder called for too high amperage and hence too high weld heat for the thin metal being welded. The welder was using reduced heat and made the repair correctly but no effort was made to change the procedure or to seek another procedure.
As discussed in Section C.9 on April 25, 1989, NRC identified that the orifice plate for flow element FE949 was installed backwards. The licensee subsequently identified four other orifice plates that were installed backward. Failure to have maintenance procedures that ensure that orifice plates are installed in the correct direction is an example of failure to provide adequate procedures.
These four circumstances above are examples of a
Violation 50-348,364/89-10-01.
These examples are indicative to the NRC of a
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weakness at Farley in the maintenance program implementation. It appears that the craftsmen are doing quality work but do not always properly regard the requirement to do that work in accordance with procedures.
Farley has in progress a procedure upgrade program (PUP) to write improvea
. maintenance procedures.
The team interviewed plant personnel, reviewed the maintenance procedure writers' guide, reviewed procedures, and observed use of a new procedure to determine the scope and effectiveness of the PUP.
The PUP started in May 1988.
The project scope includes the review of over 1500 procedures (992 I&C, 314 mechanical and 245 electrical).
The scheduled completion date is May 1990.
The team concluded that the new procedures were, in fact, an upgrade from the old procedures. The guide gave detailed instructions on format but left the level of technical detail up to the writer and the reviewer, normally foreman or sector supervisor.
Craft interviews did not reveal any problems with the new procedures.
The team also found that:
Procedure writers were experienced technicans.
However, no
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engineering expertise was used for procedure development.
The writers' guide stated that the procedure user should note all
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problems during the first use of the procedure. No mechanism existed to tell users when a first use occurred.
No verification or validation was performed prior to procedure
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issuance. The procedures are issued for field use and craft feedback is relied on to catch procedure errors.
The team witnessed the first use of an auxiliary feedwater pump
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repair procedure that directed the installation of a part not actually required.
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No re-verification of TS compliance was performed as part of the PUP.
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The procedure writers are all contractors.
The licensee has not
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finalized plans for procedure maintenance when the project ends.
Sign-offs were inconveniently located at the end of the procedure,
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which could increase the likelihood of skipping steps.
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No positive method was included to insure the user would catch missing pages (pages are numbered 1,2,3... etc. vice 1 of 20, 2 of 20 etc.).
Based on the above review, the team concluded that the PUP was improving the licensee's procedures but that the program has several potential shortcomings.
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ISSUE NO. 6 l.
HOUSEKEEPING AND MATERIAL CONDITION l
The below listed items were noted by the team during general plant walkdowns:
a.
A number of loose or missing electrical cabinet cover retaining i
fasteners.
Additional examples were reported in NRC Report I'
No. 348,364/89-09.
b.
Instruments with outdated or missing " calibration" or " calibration not maintained" stickers.
c.
Trash and clutter in several rooms
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Several burned out instrument panel indicating light bulbs.
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Numerous fluid leaks f.
An example of inadequate lighting g.
Several examples of inoperative Gaitronic equipment On November 28, 1988, the licensee issued a maintenance memorandum (MM)
' LTR-88-MTG-315 to implement the. " Maintenance Department Bi-Weekly Area Inspection Program."
The MM specified an implementation date of l
Decemoer 12, 1988.
The MM requires bi-weekly area inspections and provides a list of 31 " Suggested Items to Inspect For." The eight items identified by the team are eight of the above 31 suggested items. Clearly the program impimented by LTR-88-MTG-315 is not fully effective.
I Review of the index of electrical procedures led to the realization that the plant did not have any preventive maintenance procedure covering the cathodic protection system. According to a consultant's report, cathodic protection systems at FNP were intended to protect the 60" river water lines, 42" service water supply lines, the 60" dilution line, 36" discharge lines, 60" discharge lines, the 230 kV oil static cables and other piping.
Follow-up inquiries by the team disclosed the following facts about the cathodic protection system:
1.
A significant portion of the system (4 of the 9 rectifiers) was inoperative in 1987.
2.
The licensee's examination of buried air piping that was leaking, in 1987, indicated the inoperative cathodic protection system was a j
contributing factor to the corrosion.
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It appears that preventive maintenance and surveillance had not been l
performed on the system from startup to 1987.
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MWRs were written to repair the inoperative rectifiers, although the status of these work orders was not reviewed by the team.
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An engineer' from the Corporate Nuclear Engineering Department, who was coordinating a project to upgrade the system, stated that a PM procedure was under development. This statement was contradicted by the coordinator of the Procedure Upgrade Program who did not know of any Cathodic Protection PM procedure in his group.
To allow a nonsafety-related system of-the importance of the cathodic protection system degrade to the point of total inoperability due to lack of maintenance could indicate a lack of attention to detail on the part of the maintenance organization.
Since pipe leaks brought the problems to light in 1987, some actions have been taken but a PM procedure has not yet been developed.
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ISSUE NO. 7 BOLTED THREAD ENGAGEMENT During walkdown inspections of Units 1 and 2 CS systems, the team _noted a number of examples of questionable thread engagement on pipe flange bolting. The end of the bolts were flush or slightly below flush with the end surface of the nuts. For two bolts on the suction flange of the IB CS pump, the bolts extended only about 75% through the nuts.
The team also noted questionable thread engagement on:
Unit 1 "C" CCW Heat Exchanger head to vessel flange, two examples on service water strainer bonnet to strainer flanges, and a flanged join adjacent to lubecil strainer service selector valve QSV43-V531.
- The team requested that the licensee provide design / procedural requirements for thread engagement for bolting at Farley.
The licensee stated that thread engagement requirements were met through using EPRI
" Good Bolting Practices" guidelines in training of mechanics.
No procedures existed documenting requirements.
" Good Bolting Practices" stace that one or two threads sticking out beyond the nut should guarantee full engagement.
EPRI guidelines are related to stress concentration.
A review of mechanical maintenance training plans revealed that reference to EPRI " Good Bolting Practices" for thread engagement was not added to the' lesson plan until May 5, 1989, after the team raised a question.
On May 19, 1989, Bechtel and Southern Company Services (SCS) provided Farley information relative to various industry requirements codes as
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Visible evidence of complete threading
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through the nuts ASME Section III Bolts shall extend completely through the
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Tubular Exchanger Ensure nuts are fully engaged and studs
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Manufacturer's project through the nuts approximately 1/8 Association inch (TEMA) Inquiry SS-1102-23 CCW Heat Exchanger Based on the team's findings, Farley inspected approximately 1100 bolts in the CCW, CS, SW, and Diesel Generator systems and found:
Approximately 25 fasteners with stud less than flush with nut Three fasteners with 3 or 4 threads under flush with nut
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20 te 25*4 of the 1100 had less than 2 threads projecting through the nuts MWRs were written to correct these conditions.
Based on the above findings, the lack of procedural guidance for thread engagement is considered a weakness. The licensee agreed that a procedure defining requirements for thread engagement is needed and will be provided.
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ISSUE NO. 8 ASME SECTION XI PROCEDURES INTERFACE During the team's examination of the maintenance program, a need was identified for additional precedural requirements to ensure proper coordination and testing for ASME,Section XI components. An equivalent need was also identified for the predictive maintenance program, particularly for vibration analysis.
Details are listed below:
Procedure FNP-0-AP-52 establishes the requirements and
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responsibilities for the control of maintenance activities at FNP.
This procedure details requirements for initiating and processing MWRs. Section 7.5.6.8 requires: "The planner will determine if the components fall under the ASME Code Section XI requirements for class 1, 2, or 3 systems or components or their supports per the guidance given'in 3.10" (FNP-0-GMP-0.2). "If the MWR affects such components, it shall be stamped 'ANII notification required. A Form NIS-2 may be required, and the requirements of Reference 3.10 or 3.11 shall be followed in conjunction with this procedure."
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FNP-0-GMP-0.2 Appendix A, Section 4.0 lists examples of routine maintenance that do not require Section XI compliance.
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incorrectly included in this list which affect post-maintenance testing (valve stroke times or pump performance) are as follows:
4.3 Valve or pump repacking or adjustment i
4.10 Removal and reinstallation of valve bonnets, valve sten assemblies or actuator, using the original parts
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4.16 Disassembly of punps to replace packing or seals, perform internal inspection, etc.
4.18 Replacement of valve operators Cognizant licensee personnel informed the team that Section 4 of Appendix A was not intended to address retests necessary due to performance of the maintenance involved.
Cognizant licensee l
personnel state that Section 7.5.9 of AP-52 addresses test and
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restoration from work involving ASME Classes 1, 2, or 3 systems or components or their supports. The team noted that 7.5.9 of AP-52 references Appendix III for post-maintenance test requirements.
Further that post-maintenance requirements listed in Appendix III are
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limited to verification of alignment but valve stroke testing and I
pump performance testing are not addressed.
Therefore, correct I
guidance should be included in FNP-0-GMP-0.2 and Appendix III of
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Procedure FNP-0-AP-53 established the scope and responsibility for the Farley Nuclear Plant preventive maintenance program. Maintenance Department responsibilities are detailed in Section 3.6.
Section 3.6.2 requires " periodic vibration analysis of key pieces of rotating equipment.
This information will be used to establish trends in order to take timely corrective action."
FNP-0-GMP-1 establishes the administrative control for the maintenance department's preventive maintenance program.
Neither-FNP-0-AP-53 nor FNF-0-GMP-1 include guidance for the case when the PM vibration analyses conducted also applies to a Section XI pump.
In that case, if PM vibration trend results exceed Section XI alert levels, then Section XI,' Subsection IWP, Table IWP-3100-2 must take precedence end proper action taken to satisfy Section XI requirements.
The above requirements should be clearly stated in
.FNP-0-AP-53 and FNP-0-GMP-1.
The team informed cognizant licensee personnel that NRC concern regarding need for correction of the above procedures to ensure proper coordination and testing for ASME,Section XI components would be identified as Inspector Followup Item (IFI) 348,364/89-10-05:
"ASME Section XI Procedure Interface."
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ISSUE NO. 9 REVERSED FLOW ORFICES During a CS system walkdown described in Section B.2, the team found the flow element FE949 for Unit 2 flow transmitter for the spray additive tank control room flow indicator installed backwards. The team discovered the problem by noting that the orifice plate handle was stamped INLET on the installed downstream side. Further, the plate's inlet side is beveled, as shown on the drawing N-142-1.
The licensee confirmed the team's finding and found four other orifice plates reversed. They were:
28 CS Pump room cooler FE 3280B U1 Auxiliary Feedwater (AFW) Flow to B Steam Generator 2A Charging Pump CCW Return U2 Charging Line Flow The licensee concluded that there was no. operational or safety
. significance with the flow elements reversed. Westinghouse performed an evaluation for the /FW element.
They assumed & 10% error due to the reversal and show no significant effect.
For a different element, the conclusion may have been different, especially for a TS instrument. Since the mechanic who incorrectly installed the orifice plate (MWR 192156)
failed to follow the instructions on the plate itself, this event is an additional example of Violation 50-348,364/89-10-01, in that maintenance procedures should be established to prevent improper installation of orifice plates.
This issue is discussed further in Section C.S.
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ISSUE NO. 10 INDUSTRIAL SAFETY The team did not make a specific effort to review the licensee's industrial safety.
However, in the coucse of their inspection the team made two observations which reflect adversely on the licensee's industrial safety practices.
As mentioned in B.9, the team observed an individual resting in an
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unsafe position inches from an opening with a significar.t drop. -The individual was not secured by a safety belt or other device and had, in fact, lain down inside of a safety railing that had been erected as a precaution.
Indication of poor welding safety practice was observed associated
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with modification of supports for Unit 1 backup nitrogen supply for PORVs. Welding on the supports was completed with the compressed gas bottles in place and within one inch of the cylinder's surface.
Smoke stain from the welding arc remained on the bottles in three -
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places.
From a positive standpoint. the team noted that FNP's reported lost time accident rate for 1988 was zero.
Although evidence of possible weakness in the licensee's industrial safety practices were noted by the team, the licensee's performance suggested that there is not a significant problem in this area.
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ISSUE NO. 11 Maintenance Prioritization The team inquired of plant management if Probabilistic Risk Assessment techniques were utilized at Farley to prioritize maintenance work. The
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team was told that Alabama Power is doing some PRA work at Corporate but
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PRA is not used in the maintenance area at Farley.
As discussed in section B-12, the maintenance prioritization scheme at FNP is not well' defined in written procedures.
Most MWRs are classified' as priority 3 and the actual priority decisions are made in daily meetings.
The success of the activity depends on the experience and judgement.of the Daily Planning staff and the Operations staff. The team was not able to attend a planning meeting, as they are suspended during outages. The team therefore did not observe, nor did they pursue, examples where this prioritization scheme exhibited deficiencies.
Maintenance prioritization at FNP does not appear to utilize any consideration of risk significance in maintenance prioritization, i-q
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ISSUE NO. 12 SYSTEMS ENGINEERING Farley does not use the method common in the industry where each plant system is assigned to an individual engineer for monitoring.
Exceptions are the diesel generators and a few other complex and critical systems which have individuals assigned. The engineering work.needed to support maintenance at Farley is performed by the operations or maintenance organization. These individuals are competent and very knowledgeable of plant equipr:+.nt but are generally not degreed engineers. This philosophy is the result of a management decision at Farley and seems to work well for Farley.
The Farley Maintenance Self-Assessm2nt performed in 1988 identified the need for more engineers to support maintenance.
In response, three engineers were assigned as permanent maintenance staff engineers. The team did not attempt to identify current problems that need additional engineering support for maintenance.
However, the team observes that Farley does not have the number of degreed engineers that exist at other operating nuclear plants available to solve maintenance problems.
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ISSUE NO. 13 HEAT EXCHANGER PERFORMANCE MONITORING The _ licensee has an innovative program for performance testing of i
safety-related room coolers.
This program is implemented by procedure FNP-0-ETP-4306, Revision 1.
The program recommends ("should") that each room cooler be tested annually as a minimum.
The data examined by the team indicated that the room coolers had been tested from two to six times F.uring the period of the program's existance.
The basis of the program is the heat removed from the air in the room is equal to the heat absorbed by the service water in the cooler. This heat is represented by Q in the following equations:
Equation 1 Q=M CPA [T3 -T3 A
Equation 2 0=M Cp3 [T3 -T]
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Equation 3 Q = FUA ATM vhere AT =[(T -T )-(T -T )]/in[(T -T )/(T -T )]
M 3 3 2 4
3 2 4 Q
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Heat transfer - Btu /hr M
Service Water Flow - lbm/hr
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Specific heat at constant pressure for air -
BTU
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Log mean temperature difference (LMTD) - F g
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ft hr F
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T SW utlet temp - F
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Using 104 F.for T air-inlet temperature (FSAR Specified Maximum) and 95 F y
for T service water inlet temperatures. (FSAR specified maximum), known
values of CPA and Cp3, assumed fixed values of T.(air outlet temperature)
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and T service water outlet temperature and usingl varying values for M,
3 the licensee calculated the corresponding values of FUA expressed in units of --BTU /HR-F.
These -values were graphed with service water flow in gallons per minute (GPM) on the vertical axis versus FUA on the horizontal axis. The program indicates that the loci.of these point' establishes the
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" Design Basis Curve"- (DBC).
Using the same process with T =120 F the y
program established the "EQ Basis Curve" (EQC) which is to the-left and below.the DBC.
This.is done for each safety-related room' cooler.
There.~1s no installed instrumentation to measure M.
The program
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recommends that annually field values for T, T, T, T and M be taken y
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A and service water flow and FUA calculated. This point is then placed on-the graph for each appropriate' room cooler.
The. program provides the following guidance for the evaluation of the field data:
Points. falling above the DBC are considered acceptable. Acceptable values mean that the room cooler will remove the design heat load with 95 F inlet SW temperature and maintain the room temperature below 104 F.
Points falling between DBC and the EQC indicate degraded room cooler performance, but capability of maintaining the-room temperature below 120 F.
It is recommended that action be taken to determine the cause of the degradation and prevent further loss of room cooler performance.
Points falling below both DBC and EQC will require additional action.
The team made the following observations relative to performance testing
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The FSAR states:
"The pump room coolers are designed to
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maintain the ambient temperature in each of the charging /high head, residual heat removal, containment spray, component
- cooling, and auxiliary feedwater pump rooms at or below 104 F during the operation of the pumps." The preceeding is to be
. accomplished with service water inlet temperature not to exceed r
95 F.
This means test results which yield any data point below (to the left) of the DBC on a specific graph would indicate that cooler would not maintain those pump rooms at or below 104 F with 95 F service water.
Several examples were noted where points fell to the left and below the DBC while the unit was at power.
When questioned, the licensee indicated that FSAR provided design data was for new clear cooling coils and, L---_______-___.
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Besides all points-were within the EQC_'and,.therefore, considered
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The purchase specification for the ' charging /high head. safety injection pump rooms cooler required the cooler to maintain.
l 104 F (dry ' bulb) temperature.with 95 service water inlet temperature. and 75% cleanliness factor.
In other words, the designers. considered operation within the design envelope with a 25% fouling factor.
It appears.that if the test results are valid,; room coolers in some cases are not meeting the design performance as stated in the FSAR.
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Data points appeared to be widely scattered on the charts makirg
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meanirgful trending' impossible.
One would expect successive tests to exhibit a consistent. trend.
Licensee representatives stated that the changes resulted from work.they had done on the.
coolers.
No consideration is given to condensation in the calculation.
Condensation is a strong possibility with high room humidity resulting-from steam leaks.
The F valve for the heat exchanger varies with the temperature of the process fluids. The UA term. for the heat exchanger -is the critical value which must be determined to determine adequacy of heat exchanger efficiency.
The graphs created assumed-Q was at its rated value.
For different Q the curves determined in the flow vs FUA curves would be different. The tests were performed at a Q much different than rated Q.
The minimum acceptable values for FUA for a different Q would be different than for the rated Q that is assumed in the plot'used to determine adequacy.
It is uncertain that the graph can be used to determine adequacy unless the component was tested at near to rated Q. The team was uncertain if the test results are actually measuring heat exchanger performance in a consistent manner.
Conclusions In conclusion, the team noted that although the program for room cooler performance monitoring is innovative, there are several unanswered questions. With the observed data scatter and the theoretical questions about test methods, there is uncertainty-about test method validity.
Furthermore, the NRC is concerned that,-if the test results are valid, they are demonstrating that the room coolers are not capable of meeting their FSAR described performance level.
Prompt management action should be taken to resolve this issue to ensure that the room coolers are meeting
'their FSAR specified performance level.
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SECTION D
EVALUATION OF PLANT MAINTENANCE INSPECTION TREE I
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EVALUATION OF PLANT MAINTENANCE
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I. Overall Plant Performance Related To Maintenance Rating:
SATISFACTORY-Enough. s. significance was attributed to -the walkdown deficiencies by 'the -
team, to evaluate "Overall plant. performance related to maintenance" as
. SATISFACTORY.
1.0 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.
The plant availability is. consistently above' industry averages.
The forced outage rate is significantly lower than the industry averages for the last year..
However, preventative maintenance activities are not always timely.
Various walkdown inspections noted, in many cases, multiple examples of the following conditions: piping leaks (C-6); (Discussed further -
in Section C, paragraph 6) loose or missing fasteners (C-6);- trash and loose stripchart recorder cover noted in a control room
- electrical panel (C-6);.significant amounts of water on the floors of-i the service water intake structure (SWIS)' (B-1)', dirty and poor-
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housekeeping noted in Unit. 2 TDAFP batteries (B-4) and. Unit I spray additive tank area (B-2); poor lighting, panel lights out, Gaitronics
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inoperative, and MIC in SW piping. (B-1 and C-6); missing and out of date calibration stickers (B-8); deformed pipe support (B-2);
reversed flow orifices (C-9); MOV deficiencies (C-2); and poor bolting practices (C-7).
II. Management Support of Maintenance Rating:
Program: > POOR Implementation: GOOD Management support of maintenance was examined by reviewing and evaluating (2.J) management commitment to and involvement in maintenance; (3.0)
management organization and administration for both the corporate and plant level; and (4.0) technical support 'provided to the maintenance organization.
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Program:
SATISFACTORY Implementation: GOOD Findings / Observations:
The rating of.'.this section was based on application of industry initiatives and management's commitment to improvement of maintenance performance.
Evaluation of. the. licensee's application of industry, initiatives indicated the following: FNP participates in the NPRDS program; the licensee's final resolution to NRC notices is slow (B-11); slow -
response -to EPRI guidelines and INPO SOER on checP. valves; relaxed -
attitudes toward nssuring quick review of 10 CFR 21 reportr lB-11);
the licensee.does not have a system engineering program; the licensee has' an INP0 accredited training program; and FNP response to GL-88-14 on ' instrument air is incomplete to date but less responsive than expected (C-5).
In. evaluating management vigor and example, the team noted the following:
The licensee performed an adequate self-assessment; management supports the training program; management demonstrates a strong interest in maintenance; top management's~ maintenance philosophy is reflected at all levels; and maintenance receives high visibility.
3.0. Management Organization and Administration Rating:
l Program: NOT EVALUATED Implementation: GOOD Findings / observations:
Inspection in this area was accomplished by the review of procedures included in Appendix 3 of this report; interviews with all levels of management; sampling of selected systems and component MWRs; and observation of maintenance meetings and interface activities between Maintenance and Technical Support groups.
The sampled MWRs are listed in Appendix 4 of this report.
Examination of the allocation of resources indicated the following:
overtime exceeds the intent of NRC guidelines even if it is within the parameters of the TS; maintenance work is seldom delayed due to
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unavailability of. spare parts; maintenance work is seldom delayed due L
to inadequate maintenance support; maintenance is potentially-L adversely affected by lack of engineering support (C-12); planning L
and scheduling marginally staffed (B-12); and inadequate staff levels
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for required QC field observations (B-15).
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Review of the licensee's specification of. maintenance. requirements revealed:
The maintenance program implements EQ, preventive and
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predictive maintenance, ISI requirements, surveillance testing and
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diagnostic examination requirements; PM program does not address calibration of all instruments (B-8);
and the operability
. requirements for. the emergency air compressors is not adequately addressed (C-4).
Review of the licensee use of maintenance performance measurement indicated 'the following:
ioot cause analysis ineffective (B-16);
maintenance performance trends are established and ' implemented
'(B-17); maintenance performance quality is addressed in QA Audits (B-15); and corrective action for QA Audit findings-is slow (B-15).
The licensee has established and implemented a document control-
-system for maintenance.
Documents were retrievable and identifiable.
The team did not spend significant time reviewing the management organization program through interviews thus the program. is listed as NOT EVALUATED, As noted in (B-12), the written guidance for mainte.'ance prioritization is sketchy.
4.0 -Technical Support Rating:
Program:
POOR Implementation:
SATISFACTORY
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The purpose of this inspection was to evaluate the technical support i
received by the Maintenance organization from other plant organiza-
tions such as Engineering, Health Physics, Quality Control, i
Regulatory Compliance, and Onsite Nuclear Safety. Also of interest in this area was the level of communications between various organizations and the role of Probabilistic Risk Assessment (pRA) in f
the maintenance process.
'-Inspection in this area was accomplished by the review of procedures
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included in Appendix 3 of this report; interviews with supervisors I
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and engineers in various Technical Support organizations; inspection of selected MWRs, and licensee followup of NRC Information Notices NRC Bulletins and Generic Letters; and observation of ongoing maintenance activities.
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Findings / Observations:
Evaluation of the licensee's technical support indicated the following:
the licensee has developed and implemented an innovative program for monitoring ~ room cooler efficiency (B-1 and C-13);
ceveloped and implemented a program for vibration monitoring of equipment'outside of the envelope of ASME B&PV Section XI; inadequate procedures tie between ASME Section XI and non Section XI vibration testing (C-8); material qualification / substitution and authorship of procurement specifications.are the responsibility of QC (B-7);
Engineering support for EQ is considered acceptable (C-2); the licensee has established a methodology which appear to assure that industry initiatives are adequately addressed,- work in this area is of-good quality, however, there appears to be no written prioritization and final resoution is often slow (B-11);
!" stem engineering philosophy is not used at FNP (C-12); post-ma'ntenance testing is determined by operations without written gn delines (B-12); no technical support in the review of completed MWRs (B-3)
(B-16);
no engineering trending of failures (B-16); minimum engineering support at the site with attendent potential for inadequate engineering review and resolution of problems (B-16); the few engineers on site provide quality output; technical evaluation of maintenance procedure revisions is accomplished by the line organization without engineering involvement (C-5);
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inadequate / undocumented engineering analysis fcr the deletion of the
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testing of the overcurrent trip device in lorvoltage circuit breaker used on the DC system (C-1); marginal engir.eering support related to battery chargers and inverters (B-16); and there is adequate technical support for the motor operated valve program.
Probabilistic Risk Assessment (PRA) is not used in the maintenance process at Farley.
There is no formalized process for factoring relative risk significance of components and systems in to maintenance prioritization Inspection of QC revealed the following:
very limited independent inspection hold points are established, generally limited to regulatory requirements (B-6, 6-15, and C-5); lack of independent observation of selected maintenance activities by QC personnel (B-15); numerous QA audits were performed in the past year; corrective action to audit findings is not timely (B-15); based on limited field observations, inspections and signoffs using the peer program meet procedure requirements (B-15); longstanding audit findings relating to peer inspection program remain open (B-15);
maintenance foreman involvement in the final stages of work provides a strong sense of ownership / responsibility for correct performance of maintenance.
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Radiological controls, are integrated into the maintenance process.
Relative to industrial safety the following safety concerns were noted:
An individual _ resting in containment in an unsafe posture (B-9 and C-10); and unsafe welding practice related to the proximity of a compressed gas bottle to the welding area (B-6 and C-10).
III. Maintenance Implementation Rating:
Program:
SATISFACTORY Implementation: GOOD The purpose of this part of the inspection was to determine the quality of the established controls and, more importantly, the implementation of these controls.
The four areas evaluated are (5.0) Work Control, (6.0) Plant Maintenance Organization, (7.0) Maintenance Facilities l
Equipment and Materials Controls, and (8.0) Personnel Control.
The effectiveness was determined through a review of completed work orders, procedures, and other documentation associated with maintenance and training of maintenance personnel; physical observation of work in progress, tools in stock, and spare parts; and discussions with all levels of personnel.
5.0 Work Control Rating:
Program:
SATISFACTORY Implementation:
SATISFACTORY Findings / Observation Inspection in this area was accomplished by review of procedures 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: work orders were properly cuthorized, issued, and approved (B-6); strict adherence to ALARA concepts (B-9); housekeeping and cleanliness was generally maintained (B-6); properly calibrated tools were used (B-6); appropriate personnel were used (B-6); correct parts and materials were identified (B-6); good foreman / management oversite (B-6); personnel qualification / training were identified, verified and adequate for the task performed (B-6); an observed weakness was not always revising / correcting procedures prior to use (B-6 and C-5).
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Review of the licensee's work order control system indicated: work-order control provides for identification of work; required reviews and approvals, tracking of status of work in progress; ensures work order completeness; TPNS not completely cross referenced to parts inventory (B-7); Cause/ Failure analysis codes not well defined or adequately used (B-1, B-2, B-3, B-4, and B-5); and repeat work descriptions appears misleading (B-5).
Examination of equipment histories indicated the following:
equipment history records are - maintained, easily accessible, kept current, document repair time; equipment history data is reported to NPRDS and NPROS data is used; and equipment history records appear not to have sufficient detail to support trending (B-1, B-3 and B-4).
Review of the conduct of job planning revealed:
sketchy. procedure controls are established to assure adequate job planning and subsequent implementation; drawing and requirement review is often left to the craft (B-6); the planning staff, though dedicated, well trained and qualified, is marginally staffed (B-12); accumulator check valve work not completely planned (B-6); and ALARA is included in the planning process (B-9).
Work prioritization is based on safety / continued plant operation.
PRA is not considered in prioritization.
Prioritization is not programmatically defined (B-12 and C-11).
No improperly prioritized J
work was noted but very limited inspection was done by the team.
Examination of work scheduling revealed the following:
preventive, corrective, predictive maintenance and surveillance activities are scheduled and controlled; scheduling appears to control backlog; potential conflicts are considered in the scheduling; activities are j
scheduled to assure appropriate supervision, scheduling is largely an informal program; procedurally, only the responsibilities for scheduling are documented (B-12); and scheduling resources appear to be marginal.
The licensee's goals associated with open MWRs are consistently met
(B-17); and the licensee often uses the maximum grace period for i
calibraties (B-8).
{
Examination of the licensee's program to provide procedures indicated:
Farley has implemented a maintenance procedure upgrade
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program (C-5); there is no procedure validation prior to issuance l
(C-5); there is no engineering support review of procedures, review l
is left to the line organization (C-5); procedure technical l
inadequacies were identified (B-3 and B-6); very limited number of independent inspection hold points in procedures (B-15);
no procedural guidance for thread engagement (C-7); and upgrade procedures do not fully accomodate human factors concerns (C-5).
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i No procedural guidance for post-maintenance testing is provided with the exception of the ASME B&PV Code Section XI mandated test.
Review of completed documents indicated: minimal technical review of completed MWRs (B-3, B-16); root cause analysis ineffective (B-2, B-3, B-6 and B-16); completion deficiencies noted in some MWRs (B-3);
and insufficient descriptive detail noted in some MWRs (B-2, B-3, B-6 and B-16).
6.0 Plant Maintenance Organization Rating:
Program:
SATISFACTORY Implementation:
SATISFACTORY Finding / Observations Inspection in this area was accomplished by observation of licensee's plant maintenance organization and how it responds to unusual events; how it supports maintenance activities; how it controls and imple-ments maintenance activities; how it controls personnel; how it establishes 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 uf MWRs included in Appendix 4.
Review of control of plant maintenance activities indicated: vendor technical manuals are controlled and updated; repetitive faileres on 4160 volt breakers and batteries charger and inverters (B-3, B-4);
and failure to adequately calibrate DC circuit breakers (C-1). The licensee exceeds industry practice by: testing of molded-case circuit breakers and complete disassembly of low voltage power circuit breakers.
The maintenance organization has established methodology to identify maintenance needs, ensure plant configuration control, control materials, control tools, and accountability of work
performance.
]
Inspection of the Farley deficiency identification control system revealed:
licensee's housekeeping walkdown system is not totally ef fective (B-1, B-2, B-4, B-6, B-8, C-6); Licensee panel walkdown did not identify that loose leads were unprotected (B-8); deformed pipe l
support not identified (B-2);
in general, the maintenance organization has an effective process for the identification and control of deficiencies: and failure cause determination on MWRs is ineffective (B-2, B-3, D-6 and B-16).
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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 excessive delay in data trending (B-1).
The maintenance organization-appears to have effective communication / interface with other organization on and off site.
l 7.0 Maintenance Facilities, Equipment and Materials Control l
. Rating:
Program: GOOD Implementation:
GOOD Findings / Observations The inspection in this area was accomplished by general inspections l
within the maintenance shops, tool rooms, and training areas.
A i
general inspection was made of warehouse storage conditions and specific details associated with problems in procurement of spare parts.
Maintenance facilities are considered a programmatic strength (B-8 and B-10).
The licensee has established an effective materials control system (B-7). The licensee has effective programs for tool, equipment and measuring and test equipment control.
8.0 Personnel Control Rating:
Program: GOOD Implemer.tation: GOOD Findings / Observations Tbe purpose of this inspection area was to evaluate staffing controls, training, testing and qualification and to assess the current status.
Inspection activities consisted of interviews with supervisors and craft personnel, observation of work activities in the field, and a review of some documents and records.
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Review of the licensee's training program revealed: the licensee has an INPO accredited training and qualification program; records indicate that upgrade training has been provided to almost all of the journeymen. Even personnel previously considered qualified received
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training and testing; The team saw no evidence of programmed training for peer inspection; and maintenance training appeared to be
. adequate (B-13).
Review of the licensee's personnel controls indicated: all personnel receive timely performance appraisals; initial and update training is provided; excessive outage overtime (B-13); rotating shifts is a plus; low turnover rate; organization charts are available, up-to-date, and reflect a favorable supervisor / worker ratio.
The testing and qualification of maintenance personnel is adequate.
Overall, personnel controls are acceptable at Farley.
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SECTION E
F0LL0WUP 0N NRC NOTICE 87-44 A t: D NRC BULLETIN 88-09 THIMBLE TUBE THINNING IN WESTINGH0USE REACT 0RS
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1-(Closed) NRC Information Notice (NRCIN) 87-44, " Thimble Tube' Thinning in Westinghou'se Reactors"
]
I This Notice issued Septamber 16, 1987,. alerted licensees to potential
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problems. 'resulting from ' thinning of incore neutron monitoring system.
thimble tubes.. NRCIN 87-44, Supplement 1,= dated March 28, 1988, provided additional information.
On July 26, 1988, NRC Bulletin -(NRCB) 88-09, y
" Thimble Tube Thinning in Westinghouse Reactors," was issued requesting addressee.to establish and implement an inspection program to periodically confirm incore neutron monitoring system thimble tube. integrity.
Because the licensee had already establish an inspection program to monitor thimble tube integrity, they were required to respond within 90 days of receipt of. NRCB 88-09 '(August 5, 1988). The licensse responded to the-bulletin by letter, dated November 2, 1988, 89 days after receipt of the bulletin.
The licensee closed NRCIN 87-44 by memorandum to file dated April 5, 1989, approximately 19 months after the initial issue.
(0 pen) NRC Bulletin (NRCB) 88-09, " Thimble Tube Thinning in Westinghouse Reactors" The team - reviewed the licensee letter, dated November 2, 1988, and determined that the requested actions of the bulletin have been acceptably addressed.
The team held discussions with responsible site personnel, reviewed supporting documentation, and observed representative samples of work to verify that the actions identified in the letter of response have i.
been completed.
The licensee contracted with Cramer and Lindell (C&L) to inspect thc thimble tubes of Unit I during the seventh refueling outage in 1986 and the eighth refueling outage in 1988 and the thimble tubes of Unit 2 during l
the fifth refueling outages in 1987. Westinghouse Electric Company iW1 l
inspected the Unit 2 thimble tubes during the sixth refueling outage. The licensee has contracted with W to perform a safety evaluations of the C&L test results. To date, the licensee has found one tube blocked, plugged one tube as a precautionary measure, and withdrew five tubes to present a new surface at the wear locations, as indicated below:
Tubes Tubes Tubes Tubes Found Blocked Plugged Out of Service Withdrawn Unit 1
1
2 Unit'2
0
3 Total
1
5 There are a total of 50 tubes in each unit.
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The data provided by C&L was evaluated by W, who provided necessary safety
analysis. To date, there is no documented acceptance criteria, as each
' inspection was evaluated on a case by case basis. The licensee indicated that W was working on a acceptance criteria and basis document expected to be published as a WCAP document in December 1989.
Pending NRC review of the acceptance criteria and basis document this bulletin will remain open.
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96 5ECTION F
F0LLOWVP DN PREV 100S INSPECTION FINDINGS-l
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(Closed) Unresolved Item (URI) 50-364/89-09-02, " Fire Doors Left Open" This item concerns fire door no. 2315 to the Unit 2 cable spreading room, observed by an NRC inspector, blocked open with hourly coverage of the roving fire watch, which the licensee later determined to be contrary to FNP-0-50P-04. The licensee's operations personnel erroneously assigned a roving fire watch where full time fire watch was required. To determine whether this instance was an isolated occurrence or whether there was a programmatic breakdown in the system, the licensee compared the list of fire doors that require a continuous fire watch as specified by FNP-0-SOP-0.4 with the list of fire doors assigned a roving fire watch for both units for the period of the current Unit 2 outage.
There were approximately 100 cases where doors were assigned to the roving fire watch. No additional examples were identified where the roving fire watch was improperly assigned. Therefore, this matter appears to be an isolated personnel error and not a programmatic breakdown.
In view of the above, this matter is considered closed.
(Closed) -Inspector Followup Item (IFI)
50-348/89-09-01,
"Over Pressurization Door Left Open" This item concerns the fact that watertight door 330 to the Main Steam Valve Room (MSVR) was found open and unattended by an NRC inspector while the unit was at power.
Further investigation indicates that the watertight / pressure resistant door was specified based on original plant design of a closed MSVR. Currently, the MSVR are open to the atmosphere via grantings.
Therefore, the door design basis has changed.
This is supported by Bechtel Power Company (BPC) evaluation AP-16180.
Based on the above, there appears to be no regulatory implication to the open unattended door at power. The licensee indicated, to add an extra measure of safety and ensure the door is controlled, plant supervision has been instructed to have a person standing by when the door is open.
This person will assist personnel exiting the MSVR and ensure the door is
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closed in an emergency.
This information has been passed to on-shift
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crews as a night order. A standing order will be written to make this a permanent requirement. The team has no further questions. This matter is considered closed.
(Closed) IFI 50-348, 364/89-09-03, "ASME ISI Code of Record" This item concerned incorrect references to the Inservice Inspection (ISI)
code of record in procedures GW-001 and PMP-305, and a paragraph conflict in procedure GW-001. The licensee has issued FNP-0-SPP-GW-001 TCN 60 and FNP-0-PMP-305, Revision 1, TCN 1A, which corrected the above discrepancies.
The team has no further questions in this area. This matter is considered closed.
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SECTI0N G
EXIT INTERVIEW
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Exit Interview A preliminary inspection summary was conducted on May 12, 1989. A formal exit interview was conducted at the Farley site on June 29, 1989, with those persons indicated in Appendix 1.
The team leader described the areas inspected and discussed in detail the inspection results listed below. Although reviewed during this inspection, proprietary information is not contained in this report. Dissenting comments were not received from the licensee.
(0 pen) Violation 50-348,364/89-10-01:
" Failure to Provide and Follow Maintenance Procedures," Section Nos. B-6, C-1, C-5 and C-9.
(0 pen) Unresolved Item 50-348,364/89-10-02:
" Vendor. Drawing / Manual
. Control Program," Section B-6.
(0 pen) Inspector Follwoup Item 50-348,364/89-10-03:
" Adequacy of Action to Protect End - Use Devices from Poor Quality Instrument Ai r,"
Section C-3.
(0 pen) Inspector Followup Item 50-348,364/89-10-04: " Lack of Operability Requirements for Emergency Air Compressor," Section C-4.
(Open) Inspector Followup Item 50-48-364/89-10-05:
"ASME Section XI Procedure Interface," Section C-8.
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APPENDIX
- PERSONS CONTACTED
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APPENDIX 1
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PERSONS CONTACTED l
W. Arens, MOV Coordinator R. Badham, ISI/IST Engineer B. Bell, Electrical Maintenance Sector Supervisor B. Berryhill, System Performance and Planning Manager
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S. Brooks, Storekeeper N. Brown, EDP Machine Operator
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C. Buck, Plant Modifications Manager l
K. Burkett, Mechanical Maintenance Foreman S. Burns, NED C. Cammack, I&C Foreman S. Casey, Systems Performance Supervisor
- T. Cherry, I&C Supervisor P. Carney, Mechanical Maintenance Foreman
- A. Davidson, Daily Planning Supervisor S. Duke, Licensing Engineer
.L. Enfinger, Administrative Manager i
H. Erbskorn, Mechanical Maintenance Sector Supervisor l
- R. Federico, Maintenance Engineer I
- S. Fulmer, Supervisor, Safety Audit and Engineering Review
- H. Gariand, Mechanical Maintenance Supervisor C. Garrison, Maintenance and Operations Support Engineer S. Gates, Senior Nuclear Specialist
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J. Green, Mechanical Maintenance Foreman J. Hagie, Mechanical Maintenance Foreman J. Hancock, Mechanical Maintenance Sector Supervisor A. Hankins, GPTS Engineer D. Hartline, ISI/IST Supervisor
- R. Hill, Assistant General Manager Operations J. Hudsepth, Document Control Supervisor
- K. Jones, Material Department Supervisor M. Maddox, Senior Instructor, Technical Training D. Mansfield, NED D. Martz, Maintenance Engineer B. McKenzie, NDE Specialist D. McKnight, NDE Specialist
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- M. Mitchell, Health Physics Supervisor S. Mask, Nuclear Specialist
- D. Morey, General Manager-Nuclear Plant l
D. Morrow, Mechanical Maintenance Foreman
S. Norman, Snubber Coordinator l
J. Odom, Unit Supervisor - Unit 1 l
- J. Osterholtz, Operations Manager
- M. Pilcher, SAER Auditor P. Pollan, ALARA Specialist D. Pcpe, Electrical Maintenance Foreman
- R. Rogers, CS Supervisor
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Appendix 1
W. Sanders, Mechanical Maintenance Foreman A. Sorenson, Mechanical Maintenance Daily Planner W. Sparkman, Maintenance and Operations Support Engineer T. Sprayberry, Warehouseman E. Stephenson III, Coop Student E. Stephenson, SEE-IN Coordinator M. Stinson, Assistant General Manager Plant Support R. Swift Unit Supervisor - Administrative R. Taylor, Plant Operator
- D, Tedin, Sector Supervisor, Technical Training
- J. Thomas, Maintenance Manager P. Trotter, General Plant Technical Services Engineer
- W. Vanlandingham, Unit Supervisor - Unit 2 B. Veazey, Mechanical Maintenance Foremar.
W. Ware, Quality Cont o1 Supervisor J. Wheeler, Electrical Maintenance Foreman L. Williams, Training Manager
~#R. Winkler, GPE Supervisor B. Wood, Plant Chemist
- J. Woodard, Vice President, Nuclear
- R. Yance, Electrical Maintenance supervisor i
NRC Personnel
- E. Adensam, Director, Project Directorate II, NRR
- F. Cantrell, Chief, Reactor Projects Section IB
- S. Ebneter, Regional Administrator
- A. Gibson, Director, Division of Reactor Safety
- G. Maxwell, Senior Resident Inspector (SRI)
W. Miller, Resident Inspector
- E. Reeves, Senior Pro,iect Manager, NRR
- Attended Inspection Summary May 12, 1989
- Attended Exit Interview June 29, 1989
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APPENDIX
Af30NYMS AND INITIALISMS
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L APPENDIX 2 ACRONYMS AND INITIALISMS l
AEOD NRC Office of Analysis and Evaluation of Operating Data
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As Low As Reasonably Achievable
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ANII
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Authorized Nuclear Inservice Inspector
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ANS7 American National Standards Institute
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ASME American Society of Mechanical Engineers
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CCW Component Cooling Water
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CFR Code of Federal Regulations
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CS-Containment Spray
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DG Diesel Generator
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EMPs
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Electrical Maintenance Procedures EPRI Electric Power Research Institute
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Flow Control Valve FNP Farley Nuclear Plant
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FNPIMS Farley Nuclear Plant Information Managen.2nt System
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FSAR Final Safety Analysis Report
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GL Generic Letter
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GMPs General Maintenance Procedures
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HX Heat Exchanger
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IAS Instrument Air System
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IN Information Notice (NRC)
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INP0
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Institute of Nuclear Power Operations LCO Limiting Condition for Operation
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Licensee Event Report LER
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LOCA Loss of Coolant Accident
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MIC Microbiologically Induced Corrosion
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MSIV Main Steam Isolation Valve
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MOV Motor Operated Valve
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MOVATS Motor Operated Valve Actuator Test System
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Maintenance Procedures MWR Maintenance Work Request
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NPRDS Nuclear Plant Reliability Data System
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PCN Plant Change Notice
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PORV Power Operated Relief Valve
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Preventive Maintenance PMT Post-Maintenance Test
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QA Quality Assurance
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QC Quality Control
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Radiation Controlled Area RWST
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Refueling Water Storage Tank SAER Safety Audit and Engineering Review
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SAT Spray Additive Tank
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'4 Appendix 2
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Southern Company Services SEE-IN -
Significant Event Evaluation and Information Network
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SER Significant Event Report
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SOER Significant Operating Experience Report
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SPG S,s.; t t. Performance Group
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SSPS Suito State Protection System
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STPs S e*: rs11ance Test Procedures
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SV S3;enoid Valve
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TIN Temporary Change Notice
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TDAFP Turbine Driven Auxiliary Feedwater Pump
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TPNS Total Plant Numbering System
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TS Technical Specifications
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Work Authorization
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i-I APPENDIX
PROCEDURES REVIEWED
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PROCEDURES REVIEWED
' Identification Title FNP-0-M-015, Rev. 17 Master Training Plan FNP-0-M-49, Rev.-1 Chemical Product Control Program FNP-0-SOP-62.'0,.Rev. 6 Emergency Air System FNP-0-SPP-GW-001, Rev. 6 General Welding Standard for Repairs, i
Replacements and Modifications
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FNP-1-A0P-6.0, Rev, 11 Loss of Instrument Air FNP-2-A0P-6.0, Rev, 6 Loss of Instrument Air FNP-1-FRP-H.1, Rev. 7 Response to Loss of Secondary Heat Sink FNP-1-SOP-50.5, Rev. 12 Liquid Waste Processing System - Turbine Building Sump Operation APC Chlorine Concentration and Exposure Tice Necessary for Micro Invertebrate (Corbicula) Control Buckman Laboratories BULAB-6002 Molluscicide for the Control of Corbicula University of Texas (UT) Primer on the Asian Clam Corbicula Fluminea UT Field and Laboratory Studies of the Efficiency of Poly
[0xyethylene (Demethyliminio) - Ethylene (Dimethyliminio) Ethylene Dichloride] Biocide Against the Asian Clam Corbicula Fluminea l
APC (Revised) May 1987 - Master Plan for Chemical Control of Corbicula at Farley Nuclear Plant APC Results and Recommendations from the Unit 2.
Chlorination at Farley Nuclear Plant, April 7 - May 7, 1987 FNP-0-DOS-1, Rev. 6 Personnel Monitoring FNP-0-MP-28.137, Rev. 10 Limitorque - MOV Inspection and Adjustment (Electrical Maintenance)
FNP-0-MP-7.1, Rev. 6 Repair of Auxiliary Feedwater Pump i
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Appendix 3
1 Identification Title FNP-0-MP-7.1, Rev. 7 Disassembly, Inspection and Reassembly of
Auxiliary Feedwater Pumps FNP-0-M-064, Rev. O Writer's Guide for Maintenance Procedures FNP-0-AP-52, Rev. 14 Equipment Status Control and Maintenance l
Authorization
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FNP-0-M-028, Rev. 4 SEE-IN Procedures Manual FNP-0-AP-0001, Rev. 24 Development Review and approval of Plant Procedures FNP-0-AP-0005, Rev. 12 Surveillance Program Administrative Control FNP-0-AP-0008, Rev. 13 Design Modification Control FNP-0-AP-0009, Rev. 14 Procurement and Procurement Document Control FNP-0-AP-0011, Rev. 8 Control and Calibration of Test Equipment and Instrumentation
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FNP-0-AP-0012, Rev. 6 Control of Special Processes During Operation FNP-0-AP-0014, Rev. 10 Safety Clearance and Tagging FNP-0-AP-0015 Rev. Il Maintenance Conduct of Operations FNP-0-AP-0016, Rev. 18A Conduct of Operation - Operation Group q
FNP-0-AP-0025, Rev. 3 Equipment Identification FNP-0-AP-0028, Rev. 8 Plant Lubrication Program FNP-0-AP-0031, Rev. 9A Quality Control Measures FNP-0-AP-0045, Rev. 8 Farley Nuclear Plant Training Plan
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FNP-0-AP-0051, Rev. 8 Instrumentation and Control Group Conduct of Operations FNP-0-AP-0053, Rev. 4 Preventive Maintenance Program
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FNP-0-AP-0063, Rev. 4 Conduct of Operations Systems-Performance Group l
FNP-0-AP-0054, Rev. 5 FNP Nuclear Experience Evaluation Program l
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Identification Title FNP-0-CCP-0201, Rev. 20A Schedule.- Chemistry and Water Treatment Plant Activities
' FNP-0-CCP-0202, Rev. 19 Water Chemistry Specifications FNP-0-CCP-0532, Rev. 13 NPDES Sampling and Shipping FNP-0-CCP-0708, Rev. 8A Chlorine Dioxide Addition to the Service Water System j
FNP-0-ETP-4251, Rev. 4 Inspection Procedure for Type "V" Raychem Heat Shrink Connection FNP-0-ETP-4306, Rev. I Performance Test for Units 1 and 2 Safety-Related Room Coolers FNP-1-ETP-0240, Rev. 3 Containment Spray Leakage Assessment FNP-2-ETP-0253, Rev. 4 Containment Spray Leakage Assessment FNP-0-EMP-1213.03, Rev. 1 Maintenance of Siemens-Allis 4.16 kV Circuit Breakers Types FA-350 and MA-350 FNP-0-EMP-1313.04, Rev. O Maintenance of Siemens-Allis 4.16 kV Metal-Clad Switchgear FNP-0-EMP-1313.02, Rev. O Maintenance of General Electric 4.16 kV Metal-Clad Switchgear Type M-26 FNP-1-EMP-1341.00, Rev. O Placement of Installed Auxiliary Building Battery Q1R42E002A (125V DC Battery 1A) or 01442E002B (125V DC Battery 18)
FNP-2-EMP-1343.01, Rev. O Cooling Tower Battery Weekly Battery Inspection FNP-1-EMP-1343.01, Rev. O Cooling Tower Battery Weekly Battery Inspection FNP-1-EMP-1343.02, Rev. 1 Cooling Tower Battery Monthly Inspection FNo-2-EMP-1343,02, Rev. 1 Cooling Tower Battery Monthly Inspection FNP-2-EMP-1344.01, Rev. O Turbine Building Battery Weekly Battery Inspection FNP-2-EMP-1344.02, Rev. 2 Turbine Building Battery Monthly Inspection i
FNP-0-EMP-1346.02, Rev. O Fire Pump Diesel Battery Inspection (Monthly)
l FNP-2-EMP-1352.01, Rev. O TDAFW UPS Battery Weekly Battery Inspection FNP-1-EMP-1352.02, Rev. 1 TDAFW UPS Battery Monthly Inspection i
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Appendix 3
_4 Identification Title
- FNP-2-EMP-1352.02, Rev. 1 TDAFW UPS Battery Monthly Inspection l
FNP-1-EMP-1353.01, Rev. O Computer UPS (SPDS) Weekly Battery Inspection
l FNP-2-EMP-135.2.01, Rev. O Computer UPS (SPDS) Weekly Battery Inspection i
FNP-1-EMP-1353.02, Rev. 1 Computer UPS (SPDS) Battery Monthly Inspection
'FNP-1-EMP-1354.02,.Rev. O AMSAC UPS Battery NIC3.7.001-N (Monthly Inspection)
FNP-1-EMP-1355.02, Rev. 1 Containment Emergency Lighting Battery Monthly Inspection FNP 0-GMP-0002, Rev. 1A Repair and Replacement Instructions for ASME Classes'1, 2 and 3 Components FNP-0-GMP-0001, Rev. 10 Preventive Maintenance Procedure FNP-0-GMP-0027, Rev. 6 Disassembly and Reassembly of Nonsafety related Valves FNP-0-GMP-0052, Rev. 6 Monthly Battery Verification FNP-0-GMP-0052.01, Rev. 6 Weekly Battery Check FNP-0-GMP-0052.02, Rev. 3 Monthly Battery Inspection of Tech Spec Batteries FNP-0-GMP-0052.03, Rev. 3 Replacement of Individual Battery Cells in Existing Batteries FNP-0-GMP-0052.07, Rev. 1 Switchhouse Battery Performance Test FNP-0-GMP-0052.08, Rev. 3 Battery Equalization Charging FNP-0-GMP-0052.09, Rev. 3 Monthly Battery Inspection of Fire Pump Diesel Starting Battery FNP-0-GMP-0052.10, Rev. 1 Battery Capacity Calculation Under Emergency Discharge Conditions FNP-0-GMP-0052.11, Rev. 2 Battery Safety Equipment Check FNP-0-GMP-0052.12, Rev. 1 Hydrometer Calibration FNP-0-GMP-0057, Rev. 4 Annual Inspection and Load Test of Slings FNP-0-GMP-0058, Rev. 2 Annual Inspection and Load Test of Hand-Operated Chain Heists FNP-1-GMP-0052.01, Rev. 2 Weekly Battery Check
_ _ _ _
_
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j
.
Appendix 3
,
Identification Title
]
l FNP-1-GMP-0052.04, Rev. 1A Turbine Building Battery Performance Test j
i FNP-1-GMP-0052.05, Rev. 1 Cooling Tower Battery Performance Test
]
I FNP-1-GMP-0052.05, Rev. IA Cooling Tower Battery Performance Test l
FNP-1-GMP-0052.02, Rev. 2 Monthly Battery Inspection of Auxiliary Building Batteries (Electrical Maintenance)
l FNP-2-GMP-0052.02, Rev. 2 Monthly Battery Inspection of Auxiliary Building Batteries FNP-1-GMP-0052.04, Rev. 1 Turbine Building Battery Performance Test (Electrical Maintenance)
!
FNP-2-GMP-0052.04, Rev. 1 Turbine Building Battery Performance Test
!
(Electrical Maintenance)
i FNP-2-GMP-0052.05, Rev. 1 Cooling Tower Battery Performance Test (Electrical Maintenance)
FNP-0-IMP-0, Rev. 5 General Instrumentation and Controls Precautions and Limitations FNP-1-IMP-0011. Rev. 4 Instrument Airline and Pressure Regulator Preventive Maintenance Procedure FNP-0-MP-0028.0137, Rev. 10 Limitorque - Type SMP MOV Inspection and Adjustment FNP-0-MP-0028.0194, Rev. 1 General Electric 4.16 kV Circuit Breakers FNP-0-MP-0045, Rev. 6 Limitorque Operator Removal and Installation Models SMP-000 Thru SMP-4 FNP-0-MP-0063.0004, Rev. O Inspection and Rework of Accumulator Discharge Check Valves FNP-0-MP-0091, Rev. 2 Termination of Environmental Qualified Motors i
'
Usino Raychem Motor Connection Kit FNP-0-RCP-0002, Rev. IB Radiatron Work Permit FNP-0-RCP-0016, Rev. 5 Schedule ALARA Activities FNP-0-RCi'-0019, Rev. 2 Pre and Post Job Planning for Work in Radiation Controlled Areas of the Plant
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.. _ _ _ _ _
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..
i.
.
^
Appendix 3
Identification Title FNP-0-RCP-0026, Rev. 11 Radiological Surveys and Monitoring FNP-0-RCP-0029, Rev. 13 Contamination Guidelines FNP-0-RCP-0190, Rev. 2 Skin Dose Assessment Due to Contamination of Personnel Skin or Clothing FNP-1-STP-0016.0007, Rev. 13A Containment Spray System Valve Inservice Test FNP-1-STP-0016.0010, Rev. 2 Containment Spray System Check Valves ? low Test-A Train FNP-1-STP-0021.0001, Rev. 14 Main Steam-Line Isolation Valve Operability Test FNP-1-STP-0021.0002, Rev. 4 MSIV Air System Leak Test FNP-1-STP-0022.0020 Rev. 5 TDAFW Pump Steam Admission Valves Ai. Accumulator Test FNP-1-STP-0065.0001, Rev. 2 Emergency Air Compressor IA Operability Test FNP-1-STP-0065.0LO2, Rev. 2 Emergency Air Compressor IB Operability Test FNP-0-STP-0606.0001, Rev. 8 Service Water Building Battery Performance Test FNP-0-STP-0606.0003, Rev. 12 Service Water Building Battery Quarterly Verification FNP-0-STP-0606.0004, Rev. 8 Service Water Building Bad
.srvice Test
.
FNP-1-STP-0605.0002, Rev. 9 Auxiliary Building Battery Performance Test FNP-1-STP-0605.0004, Rev. 13 Auxiliary Building Battery Quarterly Verification
,
l FNP-2-STP-605.4, Rev. 7 Auxiliary Building Battery Nos. 2A and 2B Quarterly Verification (Electrical Maintenance)
FNP-1-STP-905.0, Rev. O Auxiliary Building 3attery Inspection (Electrical Maintenance)
FNP-2-STP-905.0, Rev. 0 Auxiliary Building Battery Inspection (Electrical Maintenance)
FNP-1-STP-905.1, Rev. O Auxiliary Building Battery Service Test (Equivalent Load Profile Method) (Electrical Maintenance)
FNP-2-STP-905.1, Rev. O Auxiliary Building Battery Service Test (Equivalent Load Profile Method)
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-
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. - _ _ _ _ _ _ _ _ _ _ _ -
I
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.
1.
l
.
Appendix 3
.
Identification Title
)
FNP-2-STP-905.2, Rev. O Auxiliary Building Battery Performance Test (Electrical Maintenance)
{
FNP-2-STP-905.03, Rev. O Auxiliary Building Battery Weekly Verification FNP-0-STP-906, Rev. O Service Water Building Battery Inspection (Electrical Maintenance)
J
!
FNP-2-STP-914, Rev. 1 Auxiliary Building Battery Charger Load Test l
FNP-0-STP-919, Rev. 1 Fire Pump Diesel Starting Battery Weekly i
Inspection (Electrical Maintenance)
{
l FNP-0-STP-920, Rev. O Fire Pump Diesel Starting Battery Three Month Inspection (Electrical Maintenance)
FNP-0-STP-921, Rev. O Fire Pump Diesel Starting Battery Inspection (18
,
Months) (Electrical Maintenance)
FNP-0-PMP-0305, Rev. IA Preparation of Form NIS-2 Owner's Report for Repairs or Replacements FNP-0-PMP-0503, Rev. 5 Installation and Inspection of Mechanical Equipment l
FNP-0-PMP-0504, Rev. 11 Installation and Inspection of Piping and Tubing Systems FNP-2-STP-0157, Rev. 6 Inservice Inspection of Classes I and 2 Systems and Components FNP-2-STP-0641, Rev. 5 Spray Additive Tank Discharge Check Valve Full Stroke Test FNP-2-STP-0644.0007, Rev. O HHSI/CVCS Accumulator Tank Discharge Check Valve Full Stroke Test l
!
l
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i APPENDIX
MAINTENANCE WORK REQUESTS REVIEWED (MWR)
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Appendix 4 Maintenance Work Requests Reviewed MWR Work Description
. M001 42737 4160 V Bus did not fast transfer 85377 2C SWP Breaker DK-05, spring will not charge 64515 Charger motor will not stop after spring charges SWP-1B 84230 Charger motor will not stop after spring charges CCWP-2A 87936 Charger motor will not stop after spring charges RHRP-2A 73914 The breaker spring would not discharge when breaker was pulled from cubicle SWP-2E
!
79447 When racking'out breaker DK-05 charging spring would not
'
discharge SWP-1C 84207 Charging spring motor running continuously LC-IL 80716 Spring will not charge SWP-2C 73243 4160 V breaker DD-01 won't close with synch switch in manual or bypass 65802 DB-03 would not trip from MCB-RCP-2B 82949 DK-05 upon manual starting, failed to start 77073 DB-04 breaker for CWP-1B won't close 75823 Indicator lights for breaker DH-02 is very dim (open or close lights) LC-2H 69719 Breaker won't indicate or operate from MCB RCP-2A l
81121 Breaker DG-04 failed to close when MCB handswitch was cycled l
several times CCWP-1A 90776 Replace relay cover on phase 2 50/51 relay, glass broken 183004 Overhaul TDAFW Pump
'
(In process)
I 166599 Repair Valve Q2E13-V005A (Q2E13MOV8820A)
j (In process)
l l
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a Appendix 4
MWR Work Description 194251 Perform STP-641.0 on Valve Q2E13-V007A (Q2E138839A)
171444 Investigate and Repair loose valve yoke on valve Q1E13-V005B (Complete)
170109 Investigate and Repair Packing Leak on Valve N2E13-V003A 170111 Investigate and Repair Packing Leak on Valve N2E13-V001 (Complete)
170110 Investigate and Repair Packing Leak on Valve N2L 23-V003B (Complete)
170114'
Investigate and Repair Packing Leak on Valve Q2E13-V012A (Complete)
188437 Perform torque switch insepction and replacement for valve 02E13MOV8836A 192157 Repair body to bonnet leak on valve Q2E13-V021B (Q2E13MOV8836B)
148453 Repair loud grinding noise in valve operator for valve Q1E13-V005A 198522 Inspect service water strainer top flange bolts for proper thread engagement 198579 Check end bell bolting for minimum thread engagement (CCW Heat Exchanger)
198580 Check end bell bolting for minimum thread engagement (CCW Heat Exchanger)
198581 Check end bell bolting for minimum thread engagement (CCW Heat Exchanger)
194793 Loosen and adjust studs for proper thread engagement (cont.
spray pump suction flange)
198523 Inspect service water strainer top flange for proper thread engagement 198519 Inspect service water stainer top flange bolts for proper thread engagement 198583 Check end bell bolting for minimum thread engagement (CCW Heat Exchanger)
198584 Check end bell bolt'ng for minimum thread engagement (CCW Heat
- _ __-_ -_ _ _ - _
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _
...
.
.
ApperJix 4
..
Exchanger)
MWR Work Description 198582 Check end bell bolting for minimum thread engagement (CCW Heat Exchanger)
196355 Repair leak to 2C D/G lube oil strainer outlet flange 170109 BCR to provide descriptions of these MWRs 134712 SSPS NTC card replaced for U2 CS Pressure Transmitter PT-950 137915 SSPS NLP card bad - U2 CS PT-950 172964 SSPS NLP card bad - U2 CS Pt-950 138535 U1 CS Pump 1A vibration in alert range perform evaluation 166799 U2 CS 8817B - replace bad overloads and blown fuse in MCC 177510 U1 CS 8817A check and tighten yoke to bonnet bolts 89236 U1 CS 8826B repair loose electrical connection of torque sw 112285 U1 CS 8820B leaks by seat (written 5/14/85 closed 5/5/89)
89236 U1 CS 8826B repair loose electrical connection of torque sw 136909 8/4/87 Support lube schedule -
change filter and clean sump
strainer on ID station air compressor 148092 7/31/87 Noise coming from head of ID air compressor.
Investigate and repair 148464 5/3/87 Maintenance support to clean oil sump strainer and change oil filter on compressor C0001A 148832 10/10/87 Air leaking by shaf t seal on IC Air compressor 148848 10/15/87 011 press. gage oscillating excessively on 1C comp.
(added shim to work relief spring)
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,
Appendix 4
'
MWR-Work Description 148848A 10/18/87 011 press, gage oscillating excessively (complete actions directed by sector supervisor and identified gage-as deficient.
Replace gage)
149402 9/9/87 Support lube schedule clean oil sump strainer and change oil on IC compressor
.
151727 3/29/87 Press, gage on 1C air comp.
reads 38 psig when shutdown and 55 psig when running 164400 2/2/88 Clean oil sump strainer and replace oil filter on IB service air compressor 165727 2/2/88 Clean oil sump strainer and replace oil filter on ID station air compressor
,166906 11/4/87 Replace oil filter and clear sump strainer on IA station air compressor 166907 11/4/87 Replace oil filter and clean sump strainer on IB station air compressor 166908 11/4/87 Replace oil filter and clean sump strainer on ID station air compressor-168464 12/31/87 011 leaks around filter fittingr on ID station air compressor (tightened gasket nut and all fittings)
168464A 1/4/88 011 still leaking at bottom of filter on ID station air compressor (replace damaged fittings with new fittings)
177427 5/6/88 Change oil filter and clear wmp strainer on IB service air compressor
=
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.; -
.
Appendix-4
MWR Work Description-177428 5/6/88 Change oil filter and clean sump strainer on 10 station l
air compressor l-178171 6/1/88 Air compressor C001C, intercooler press. gage stuck on 20 psi. (installed new gage)
178171A 6/30/88 Gage reads 10# at full comp.
load low spec. is 23# (I&C-activities to veri fy that PI-0551 is functioning properly)
178171B 7/3/88 Intercooler press out of spec. I&C has calibrated and replaced gage.
Investigate and repair (replace LP and HP valves using new assemblings)
178171C 7/8/88 1C air comp. low out-of-spec.
(found new valves not seating lapp cleaned and reassembled)
180969 10/19/88 Retorque HP Head of 10 station air comp, due to torque wrench FNP-STW-6805 out of tolerance at time of initial torquing 187100 1/13/89 1A air comp. unloader valve sticking causing loud noise and high intercooler press when comp.
unloaded (tightened set screws on valves and unloader line)
187100A 1/17/89 1A compressor still making noise and air is bleeding thru.
(removed HP suction and discharge valves, lapped seats, installed new plates, springs and gaskets reinstalled)
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c-
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Appendix'4
MWR Work Description 187100B 1/18/89 1A compressor still making noise and ' air bleeding thru (removed HP valves and reinstalled using all new assemblies)
187124-1/9/89-1A service air camp - oil
,
press. gage sticking 187187 2/1/89 1A service air c.ap - HP and LP piston rings worn below min specs. (completed major rebuild)
1871545 7/23/88 Automatic drain valve on IB instrument air dryer inlet filter sticking open 186916 2/19/89 1A instrument air dryer moisture indicator.
grey again-suspect dryer dessicant (inspected dessicant and found okay - replaced moisture indicator)
195852 2/22/89 1A instrument air dryer dessicant depleted as indicated by grey color (replaced dessicant)
159140 7/11/87 IB air comp.
intercooler press. indicator reads 23#
when comp. loaded, unloaded or off (completed-I&C actions to replace with new calibrated gage)
159140A 7/13/87 IB A/C intercooler press.
gage still does not properly indicate.
(rebuilt LP suction and discharge valve)
148055 7/6/87 Auto drain valve for IC air comp. moisture separate is not working (replaced auto drain valve)
l l
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-
,_
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l c
a s
Appendix 4'
MWR'
Work Description 148055A 7/8/87 Auto drain valve for 1G air i
comp.
moisture separator still
'doesn't operate
'
properly (replaced auto drain valve and cleaned 176722 7/1/88 There is loose valves in HP cylinder for 2B service air comp. (found no loose parts but much rust.
Removed valves, rebuilt and reinstalled)
176722A 7/2/88 Air comp. still knocking and intercooler relief lifting (removed HP valves and found dampening plate off guide bushing in one valve.
Recentered plate.
Reassembled and reinstalled valves)
168731-12/4/87 2B comp. moisture separator keeps filling up with water.
Replace auto blowdown valve (found diaphragm valve detective repaired)
182235 8/13/88 2C comp, moisture separator auto drain valve not operating properly (replaced tubing and rebuilt valve)
182235A 8/14/88 2C comp. moisture separator autodrain still not functioning properly (disassembled valve-found diaphragm rupture due to return to service i.e. valved in too quickly - replaced diaphragm and 0-ring)
192013 12/20/88 28 air comp auto drain valve has
' ailed (replaced
[
diaphragm, spring and 0-ring
'
in valve)
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l
_
=
'
Appendix 4
.
MWR Work Description 180013A 12/24/88 2B air comp auto drain valve inoperable (found water on top of diaphragm 191303 Pump repacked 179860 Pump flow in alert range evaluate 179859 Pump flow in alert range evaluate 174222 Pump vibration in alert range evaluate 143878 Rebuild pump 191252 Evaluate high pump flow 168967 Flow element repair 186767 Pump flow high evaluate 176865 Evaluate low pump flow 175674 Evaluate low pump flow 139418 Repair motor operated valve (MOV)
139143A Repair MOV 139135 Determinate valve motor leads 139135A Repair MOV 180911 Repack strainer 152661 Repair control valve 152721 Repair control valve 154042 Repair control valve 165675 Evaluate incorrect MOV torque switch setting
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