IR 05000237/1990011
| ML17202L258 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/14/1990 |
| From: | Burgess S, Falevits Z, Jablonski F, Mendez R, Tella T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17202L256 | List: |
| References | |
| 50-237-90-11, 50-249-90-10, NUDOCS 9006060019 | |
| Download: ML17202L258 (17) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION II I Reports No. 50-237/900ll(DRS); 50-249/900010(DRS)
Docket Nos. 50-237; 50-249 Licenses No. DPR-19; DPR-25.
Licensee:
Commonwea.lth Edi son Company Post Office Box 767 Chicago~ IL 60690 Faci 1 ity Name:
Dresden Nuclear Power. Station - Units 2 and 3 Inspection At:
Morris, Illinois Inspection Conducted:
April 2-6, 1990 Inspectors: f~e0ftY~ /=
Team Leader Maintenance and Outage Section Inspection Summary
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5-14- -ro Date
£"- ttt-fO Date 5-14-10 Date 5'- I 9 -**c;o.
Date
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Date lns~ection on A~ril 2-6, and 12, 1990 (Report No. 50-237/900ll(DRS)
50- 49/900lO(DR )).
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Areas Inspected:
Routine announced followup inspection to evaluate the progress made to resolve problems identified during the maintenance team inspection {MTI)
documented in Inspection Reports 50-237/88029(DRS) and 50-249/88030(DRS).
Results:
In general, the licensee's actions to improve maintenance and address the violations* and unresolved item were acceptabl~. One_ violation was identified during this inspection with three examples of failure.to follow procedures; and three unreso*lved items were identified that pertained to the adequacy of thermal overload sizing, the safety significance of missing problem analysis data sheets, and the change to the circuitry of *a containment isolation valve without approved d~sign document *
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- DETAILS Persons Contacted Commonwealth Edison Company (CECo)
- E. Eenigenburg, Station Manager
- J. Achterberg, Assistant Superintendent, Work Plannin~*
- D. Booth, Master Electrician
- K. Brennan, Regulatory Assurance Administrator
- J. Coonan, Conduct of Maintenance Coordinator
- R. Geier, Master Mechanic
- L. Gerner, Technical Superintendent
- J. Kotowski, Production Superintendent
- L. Sues, Mainteriance Superintendent, Nuclear Engineering Department
- D. VanPelt; Assistant Superintendent, Maintenance U.S. Nuclear Regulatory Commission (NRC)
- F. Jablonski, Chief,. Maintenance and Outages Section
- S. DuPont, Senior Resident Inspector
- D. Hill, Resident Inspector
- M. Peck, Resident Inspector
- Denotes those present at the exit meeting on April 12, 1990.
Other licensee personnel were contacted as a matter of routine during the inspection~ Licensee Action on Previous Inspectirin Findings (Closed) Untesolved Item 237/88017-21; 249/88018-21 Corrective maintenance procedures were not established for important ~afety related and balance of plant (BOP) component Licensee action to address this issue was described in the Nuclear Tracking System (NTS) as 237-100-88-0172 and 249-100-88-018 In addition to writing 15 maintenance procedures on equipment identified by the Diagnostic Evaluation Team in 1988, the licensee reviewed other maintenance activities that were not governed by procedure This review resulted in 26 additional procedures being writte The licensee also developed and implemented a procedure writing guid This item ts close.2 (Closed) Unresolved Item 237/88029~01; 249/88030-01
- Trip armature travel measurements on safety-related 4 kV breakers were not performe Prior to Octobe~ 1988, the licensee performed trip latch clearance measurements as specified in the vendor manual issued in March 196 In 1973, the vendor.issued instruction GEI, 88710 which.required measur~ment of the trip armature-travel when preventive maintenance was performe However, -the licensee did not implement the change until October 198 At the time of the maintenance team inspection approximately two thirds of the Unit 2 breakers and most of the Unit 3 breakers had not been checked for proper trip armature trave The inspetto~s reviewed procedure SP 89-9-83, Inspection and Maintenance of
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General Elecfric 4 kV Magne-Blast Circuit Breakers Type AMH-4.75-250-00 11,
Revision 1, and verified that the procedure required trip armature travel measurements to be tak~n. Additionally, with the exception of three breakers, all breakers have beer:i measured for trip armature travel.. This item is close.3 (Cl6sed) Violation 237/88029-02; 249/88030-02 (Response to this violation was pro'vided to the NRC in a letter dated May 11, 1989.)
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Maintenance on 15 Unit 2 and Unit 3 breakers was not performed at the required frequency, some for as long as 17 year In addi~ion, the cause of 4 kV breaker failures was inad~quately evaluated and the licensee failed to attribute the failures to improper maintenanc To date, three 4 kV breakers still remain to be overhaule A maintenance procedure was developed that included inputs from electricians, electrical maintenance supervision, and a vendor specialis Electricians interviewed during the inspection indicated that the overall electrical maintenance program and procedures were improved. No problems ~ere i~entified with the 4 kV breaker maih~enance program with the exception of frequ~ncy. The vendor manual recommerided maintenance on the breakers at six months, one year and five year intervals and dependent on frequency of breaker operatio However, PMs were scheduled on the'4 kV br!akers at five year intervals*
but without any evaluation or technical justificatio The licensee indicated that the frequency of PMs would*be reviewe This item is close PM had not been performed on the Unit 3 250V de motor control centers (MCCs) since 197 All 250V de MCCs now have been overhaule In addition, the maintenance procedure was complet~ly revised to.include additional vendor recommendations arid acceptance criteri The changes made to the
~rocedure were similar to those*made for the 4 kV breakeri and with. input from the electricians that performed the maintenance wor This item is close Auxiliary switches (SBM) for Unit 2 and Unit 3 4 kV breakers and cubicl.es were.not replaced even though the switches had a history* of failure since 1982 and were at end of lif To date, two safety related breakers still*
require SBM swi.tch ~eplacements. Although, the SBM switches had a useful life of 10-15 years, the maintenance procedure required changing the switches on a 5 year interva With respect to the SBM switches in the two*4 kV breakers, the licensee was uncertain of the status of the switches since the breaker serial numbers were not know The safety significance was low since the power supplies to the safety-related buses were both diverse and redundan This item is closed...Follow Up to Maintenance Team Inspection Thi~ inspection was conducted to ev~luate the progress that the licensee had made in the area of maintenance since the NRC maintenance team inspection (MTI)
in early 1989, which was documented in Inspection Reports 50-237/88029(DRS) and 50-249/88030(DRS).. The inspectors reviewed historic data and various improve-ment programs. *Some of the areas evaluated were planning and prioritization,
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system engineering and 'root cause analysis,*vendor manual c6ntrol and incorpora-tion of vendor requirements into procedures, histories of completed work requests, preventi~e maintenance, surveillances, and control of material At the beginning of this followup inspection, a walkdown of the plant was conducted to observe material conditions and upkeep of plant ~quipment and syste.ms ~
. Historic Data and Maintenance Philbsophy The inspectors reviewed the latest available plant operations historic data from March 1, 1989, to February 28, 199 Dresden Plant Status Reports dated December 1989 and February 1990 were reviewed to assess the effectiveness of the ongoing maintenance and improvement programs at Dresde Implementation of improvements were most notable with electrical maintenance, motor-operated valve overhauls, and theck valve inspection Plant performance related to the maintenance process was ~elatively consistent throughout 198 Set goals were met in areas relating to maintenance including forced outage rate and non-outage ~orrective backlo However, plant status reports for the months of January and February 1990 indicated a highet percentage of forced outage rate and derating than any month in 1989.. During Janua.ry and February 1990 there were four forced outages caused by equipment failure including three reactor scrams that were attributed to BOP components. Since March 1989 there were 24 Licensee Event Reports (LERs)
issued, which were classified by the licensee as.maintenance/surveillance
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related. During the period most scrams occu~red during periods of surveillanc As described above, the team determined that some recent component failur~s, on face value, would tend to indicate that the established maintenance improvement programs were not effective ye The team belleved this to be untrue; however, due to an apparent lack of direction from the Co~porate Nuclear Engineering Department on report contents, the annual licensee assessment ~eport of the ov~rall effectiveness of the *mai~tenance program had not been documented by the Assistant Superintendent of Maintenance (ASM) as required by Nuclear Operatons Directive, NOD-MA.2, Revision'O, Exhibit "A".
Therefore, based only on the obvious indications, there was insufficient information to adequately judge whether the maintenance improvement programs were totally effectiv.2 Maintenance Improvement Program (MIP)
The inspectors examined the MIP and its implementatio The MIP was established to upgrade and enhance the maintenance process and is divided into four phase Phase I Phase II Phase II I -
INPO Maintenance Assist Review Team (MART) and securit.
action plans have been.initiated to address findings of which 297 have been complete *
Conduct of Maintenance (COM) and 1988 assessments by INPO, NRC, and the license act~ons plans have been initiated of which 171 have been complete assessments by INPO, NRC and licensee including the MTI findings and the licensee iriitiated Time Series Analysis (TSA)
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(maintenance history review).
513 action plans have been initiated of which 215 have been close Phase IV 1990 assessments by the licensee and self imposed COM item action plaris have been initiated of which 28 have been closed.
. For the MTI findings, the licensee initiated 53 action items; 43,have been complete The team reviewed the licensee's MIP process and selected action plan Based on the review, the team concluded that the licensee has established a good tracking program to address the various findings in the maintenance are However, the following concerns were noted:
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0.1 Numerous action items initiated by the licensee to address findings by NRC, corporate and plant self assessments, mock SALP, and others were not consolidated and assigned to a single individua For example, at least eight action items were wtitien to address deficiencies with Problem Analysis Data Sheets (PADS), but assignments were made to different individuals for independent resolutio Feedbac~ was not well established from maintenance supervisors *to plant managers on status of maintenance i*ssue Several action items were considered complete by the site personnel but were not yet *fully implemente For e~ample, some items were transferred to corporate for resolution but were incorrectly noted as 100% complet Review of Maintenance Related Corrective Actions Augmented Inspection Team (AIT) Report No. 50-237/90004 The inspectors reviewed the following actions taken in response to the NRC AIT Report No. 50-237/9000 The inspectors noted that the licensee's corrective actions for several items identified in the AIT were still in progres As the results of some invesiigation reports were to be received late in.1990, it would be appropriate for the NRC to further verify the licensee's corrective actions for these items at the end of 1990 or early 199 Some prelimi~ary re~ults are described belo. Failure of Condensate/Booster Pump Motor A fire in the 2B condensate/booster pump motor caused the pump to trip, which along with other failures, led to a reactor scra The failed motor was replace The initial report issued on April 3, 1990, indicated that the cause of the
.motor failure was significant dirt in th~ coil However, a final joint report of the licensee and General Electric Company was* expected to be issued by August 1, 199 Units 2*and 3 condensate/booster pump motors were cleaned except for 3D, which was scheduled for cleaning by April 23, 199 The maintenance department will. continue to measure the polarization index of large motor A temporary procedure was issued to clarify the insulation resistance/polarization index acceptance criteri The permanent procedure is expected to be revised by June 30, 199. Failure of Condensate/Booster Pump 28 to Automatically Start A modification to address the reactor feed pump suction head~r pressure recovery issue is being developed fcir possible implementation in 1992:
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- Failure of Reserve Auxiliary Transformer, TR22 The ttansfofmer was re~laced but th~:causes fo~ the failur~ were still being investigate A final report -is expected to. be issued by June l, 199. Closure of Outboard Main Steam.Isolation Valve (MSIV) 2C The MSIV solenoid electrically failed open.* The solenoid was last replaced on February 11, 1989, in accordance with the PM requirement to replace solenoids every third refueling outag The licensee stated that the failure of solenoids was not a recurring problem, and this was considered a random failur The licensee was developing a surveillance procedure for these solenoids and was
~xpected to be issued by July 1, 199 *
4.1. 5 Failure of Electromatic Relief Valve Open Indicator Lamp Socke The failed lamp socket was replace The failure was traced to dirt in the lamp socket The lamp sockets were periodically vacuume The licensee planed to develop a procedure to.prevent lamp socket failures by May 1, 1990, which will be implem~nted by September 199 *.1. 6 Failure of Main Generator to Trip on Rev~rse Power Conditions The re~erse power relays were replace The licensee stated that no simil~r events were reported from the licensee's other plants, where similar reverse power relays were use However, f~rther testing of these relays would continue regarding the effect of reactive power on the operation of these relay A finaJ report is expected to be issued by June 29, 199.1. 7 Failure of 28 Shut Do.wn Cooling Pump Di sch a rge Valve to Open The cause for the valve failure was traced to a broken motor pinion gear key, which was replace A similar failure occurred earlier on Unit The gear keys in the motor operators on the shut dowh cooling pump valv~s will be
- replaced by June 30, 199 The licensee also stated that similar improvement on other valves in the plant would be completed by December 199.2 Licen~ee Event Reports (LERs)
The inspectors reveiewed LERS that appeared to be maintenance relate The inspector also rev{ewed corrective actions committed to in eight other LERs of events that 6ccurred from January to March 1989 and found that in four of the LERs, the licensee had not completed corrective action Many of the commitments made* in the LERs were procedural changes; however, timely corrective actions were not eviden LER 237-89001 - The LER was issued because of a Unit 2 inadvertent engineered safety feature actuation on January 21, 1989, which was due to an improper setting of an overcurrent relay by the Operational Analysis Department (OAD).
- The licensee committed to revise the relay setting procedur During the week of April 2, 1990,* the inspector reviewed corrective actions but found that OAD had not completed the procedure revisio LER 237-89019 - A.Unit 2 reactor scram and a primary containment Group I isolation occurred on July(12, 198 One cause for these events was a spurious main steam line area high temperat~re trip due to instrument drift of temperature switches, ~hich were replace A new c~libration method was being used to reduce the possibility of set point drif The licensee was also considering a modification to imptove the performance of these temperature s~itches. The other cause for these trips.was the difficulty in resetting the 11A11 main steam line (MSL) logarithmic radiation monitor, which was replace The defective monitors were sent to the vendor for further evaluatio The vendor's report has not yet been receive LER 249-89001 ~ A Unit 3 reactor scram bccurred on March 25, 1989, due to a reactor water level transient and a turbine tri Several equipment failures and malfunctions caused this even The corrective actions taken were reviewe The licensee replaced a fail~d condenser and mounted it externally on the 4 kV breaker; the breakers were cleaned on a five year cycle; a modification was d6ne to improve the feedwater control; a modification to provide diesel driven pump to supply the isolation condenser was expected to be completed in 1992; and procedures were revised to correct the high pressure core injection (HPCI)
oil cooling problem and the primary containment oxygen analyze Other proposed corrective actfons were being appropriately_tracke LER 249-89002 - A scram occurred on March 30, 1989, due to a spurious trip of the electrical protection assembly (EPA) breaker and a current lock up condition of a MSL radiation monito The co~rective actions included replacing th~ EPA breaker and resetting and upgrading of the MSL radiation monitor The EPA logic card was sent to the vendor for testin Oth~r corrective actions for this incident included revision ~f procedures, incorporation of caution regarding MSL radiation monitors, and revision to the DAD reverse power relays procedures that is expected to be completed by June 1, * 199.3 Observation -of Material Condition The inspectors performed a plant walkd6wn that included an assessment of the systems and components for proper identification arid tagging, and any unusual conditions such as water or oil on the floo The.areas inspected were generally clean and well maintaine However, the following were noted:
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The glass on Unit 2 drywell pneumatic backup supply pressure indicator gauge in the reactor building was broken and the pointer w~s ben No deficiency or work request tag was foun Later a work request was generate *
The licensee made good progress in the painting and labeling progra On April 2, 1990, during a walkdown of the reactor building, the inspectors observed a handwritten note, dated March 27, 1990, which stated that the Unit 2 250V de ground det~ctor strip chart recorder was not functiona The inspectors noted that a work request tag had not been placed near the vicinity of the recorde The licensee was notified and at approximately
0 1:00 p.m., an instrume~t mechanic (IM) foreman arrived at the recorder and turned the recorder switch o~.
The IM foreman mistakenly believed that the problem was corrected. At about 4:30 p.m., the inspector noted that the chart had not move The licensee was notified again and during the evening, blanket WR 00166 was issued and corrective maintenance was performe The inspectors were concerned about the lack of prompt correc-tive action to repair the above proble Battery ground surveillances were performed once a shift (three per day) but none of the high voltage operators who performed the surveillance either wrote a work request or attempted to determine if a work request was issue The licensee's procedure entitled, "High Voltage Operators Round Book" required that abnormal conditions either be corrected or reported to the Shift Supervisor and work requests init{ated: *The concern was that the operations personnel h~d not properly followed up on*a known discrepant condition for approxi-mately eight days until notified, by the inspector This failure to follow the High Voltage Operators' procedure was considered to be a weaknes Several control rod drive (CRD) position lights in Units 2 and 3 vertical panels were. not properly indicating control r6d position Approximately 25% of the rod position lights were affected yet only one maintenance ta was note The unit operators stated that the operators do not depend on the vertical panel lights for a review of rod positions but would look at the screen of the rod worth minimizer or select a rod by the rod selector
.switch and obtain the rod positio The shift control room engineer confirmed the above statement The inspector noted that the rod worth m1n1m1zer screen was rather small and was intended for prevention of inadvertent withdrawal of control _rods out of sequence.* *Dresden Procedure DGP 3-2, "Normal Control Room Inspection",
Revision 6, stated that, 11 *** verify that all control rod position indications are normal on the vertical panel matri Check with computer print out 00-7.
. In addition, Procedure OAP 7-2, "Conduct of Shift Operations", Revision 15, also required* that the nuclear station operator complete a degraded equipment.log on each shift, with notation of any equipment in a degraded condition and/or which may require further actio The control room operators did not include the malfunctioning CRD position lights on the vertical panels in the degraded equipment log as required by*
the above procedure. The burned out CRD position indication lights appeared to be a long standing problem. Failure of the licensee to follow the station procedure and to verify that all control rod position indications were functioning and normal was c~nsidered an example of a violation of 10 CFR 50, Appendix B, Criterion V (237/90011-0lA(DRS); 249/90010-0lA(DRS)).
The inspectors observed that eight of ten thermal overloads associated with the
- Unit 3 HPCI 250V de MCCi were set differently than required by procedure DEP 040-6, "Safety-Related Motor Operated Valves Data and Settings", Revision 5, Section D, which stated that The data on the lists cannot be changed without approval from the Nuclear Engineering Department NED. 11 The back of the proce--
dure listed a table ~ith the required thermal overload setting However~ the licensee did not have a method to verify that the settings were correc Consequently, the following thermal ov~rloads were observed to be improperly se *
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Required Actua 1 Valve N Setting Setting 1001-2A
- i049C 1049A 1001-28 1049C 1049 c 1049C 1049A 1201-3 10360 10368 1301-2 1040C 10400 1301-10 10238 1023A 2301-3 10360 1035A(+), 8(-)
2301-14 10340 1034C In seven of eight cases listed.above, the thermal overload settings wer non-conservative (the yalve motor would trip earlier than required).
- Other problems were noted, such as for valve *2301-3 where the positive and negative side5 we~e set differently and for valve 1301-3 where the setting was not listed in the procedur The f~ilure to follow procedure DEP 040-6 was considered an example of a violation of 10 CFR 50, Appendix 8, Criterion V (237/90011-018(DRS); 249/90010-018(0RS)).
The inspectors determined that the. 250V de MCC th~rmal o~erloads had not been tested since Urrit 3 became operationa In add~tion, the vendor manual had an apparent discr~pancy between the thermal overload tables and the full load current rating of valve motor For safety-related valve 1201-3, the rated full load current was 16.5 amperes but the thermal overload for a sfze 11 2 11 starter, coil number 10177Hl036A, was rated
- between 8.32 - 8.56 amperes. -The vendor manual for ~oil numbers prefixed by 10177H stated, that 11 *** coils selected from this table will allow a maximum of approximately 125~~ of rated current.
It should be* noted that the vendor information applied to continuous duty motor However, using the above information the motor for valve 1201-3, if operated for several minutes, would have tripped at approximately 63% of full load curren The licensee stated that the thermal overload sizes were based on locked rotor current (LRC) not full load current because the valve wa~ intermitt-ently use The "current versus time curve" for coi 1 number 10177H1036A indicated that the specific time response curve for the coil was different than the generic curve provided by the vendo For example, the generic curve indicated that at 125% of nameplate current the.motor would tri in about 35 seconds, which does not take into* a*ccount LRC. * (The motor would trip in less than 35 seconds if LRC was considered).
Valve 1201-3 stroked from fully closed to fully open in 33 second The curve indicated that th~rmal overload 10177H1036A would trip in 160 seconds at approximately 125% of the rating for motor operated valve i201-3. This item is unresolved pending review by the vendor to determine if the time versus curve for coil 10177H1036A was correct to within the vendor limits (237/90011-02(0RS);
249/90010-02(0RS)).
.. Completed Work Packages and.Work Histories The inspecior reviewed eight co~pleted work packages to dete~~ine if maintenance work was accomplished and docume~ted: One problem was identifie The inspector noted that the post verification test required under Nuclear Work Request (NWR) 086234 and procedure OEP 040-12, "General
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Electric 480 Volt Circuit Breaker.Series Overcurrent Trip De_vice Te5t, 11 Step F.2.0, was documented as not applicable for the A and C phase The licensee stat~d that the tests were p~rformed but that.the work analyst was unable to read th~ original data sheets and gave the work package back to the e 1 ectri cal forem*a The foreman fi 11 ed out the data sheet and
~outed the work package through Q The QC supervisor signed off the package without noticing that at least two tests we~e not documerite The failur~by the ~ark analyst to review the work package the second time result~d in missed documentation of the p6st verification 300% breaker trip test for the A and B phase Procedure OAP 15-01, "Initiating and Processing a Work Request 11, Revision 22, Section 9, required the work analyst to review the packag Failure of the licensee to follow procedure OAP 15-01, is an example of a violation of 10 CFR 50, Appe~dix B, Criterion V (237/90011-0lC(DRS); 249/90010-0lC(DRS)).
The licensee maintains the work histories by the Total Job Management (TJM)
~rogram. After the MTI, the licensee issued a maintenance memorandum No. 51,
"Preparing Work Requests for TJM History, 11 on June 9, 1989, which included a detailed work request checkli~t, to.be completed by the maintenance foreman, after the work was complete The inspector not~d that the check list was being used and was included in the WR package The licensee initiated a program for upgr.ading the data base of equipment identification on the TJM system and system walkdowns were being performed to complete associated r~cords. Walkdowns were completed on 15 systems of Unit 2 and in various stages of completion on 15 systems of Unit Progress in equipment identification appeared slo Of approximately 14,000 station instruments, only about 4,000 had the stati~n equipment identification numbers attache The licensee stated that.it would take about.another two years to co~plete the tas *
. Work Planning and Prioritization The planning department consisted of two groups for work planning, one group for outage planning and the 6ther ~roup for daily work plannin Procedures for the work planning organization a~d daily planning were in preparation and were expected to. be issued in about a m6nt In addition to planning for the outages, this department prepares a two week look ahead schedule that consists of surveillances and other WRs based on prioritie Planning department personnel attended the daily and weekly planning meetings and updated the work schedules as necessar The i.nspector also discussed the planning and scheduling with th~ instrument department lead schedule Work planning in this department included walkdowns, planning and the preparation of ~ork packages, assignments of work, and review of work packages after completion of wor The work was prioritized and taken up according to the priority~ Backlog of Maintenance 4. Corrective Maintenance Backlog
- The MTI had previously idehtified a weakness in the prioritization of B2 WRs, which resulted in a large backlog of B2 WRs older than fiv~ day The licensee
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revised the.WR prioritization -process to agree with the Ccinduct of Maintenance (COM) and as~ result the majority of the WRs were prioritized as B All B2 WRs were reviewed and were scheduled within five day The TJM coordinator sends a weekly list of all WRs prioritized as A, Bl, and B2 to the Assistant Superintendent of Maintenance and to t~e master mechanics for review and schedulin This considerabl~ reduced the backlog of Bl and B2.WR The backlog of Bl WRs was almost eliminate There were only three instrument WRs prioritized as B2 pending on March 31, 199 The inspectors determined that on April 3, 1990, the non~outage CMWR backlog was 587 for mechanical maintenance, 163 for electrical maintenance, and 172 for instrumentation maintenanc The CM backlog had increased by 33 CMWRs since the previous MT! in February 198 The inspectors concluded that the* increase was not significant and the total backlog was slightly above the corporate goa The inspectors reviewed several CMWRs and determined that* n6ne had impact on operabilit The inspectors noted that the licensee had made improve-ments in estimating manhours required for each work reques The February 1989 MT! reported that the actual hours was twice the estimated hour This inspection noted that the actual manhours required w~s apprbximatel~ 20% over the estimate *
4. Preventive Maintenance Backlog Based on review of licensee* records, the inspectors determined that on April 3, 1990, the total PM backlog was 57 This included periodic, planned, and predictive maintenance WRs:
This backlog was considered to be within the current maintenance staff capabilitie The ratio of PM hours to total maintenance hours averaged ~5% during 1989, which was higher than the plant goal of 42%.
A review of the scheduled PMWRs *
backlog identified a few isolated misclassifications of CMs as PMs; however, the inspectors noted a good improvement in correct CM/PM classification. This was identified as a Weakness in the 1989 MT!. Post Maintenance Testing (PMT)
Due to time con~traints the tea~ was not able to co~duct a comprehensive review of the pos~ maintenance testing program and implementatior However, the team noted that several licensee action items relative to PMT still remain ope Open Action Item NUS EVAL. 04.00, initiated September 1989, identified a need to monitor the PM program by reviewing the work performed against the PMT specified in order to assess the effectiveness of the PMT progra Also, Licensee Open Action Item Corp. Assess. 04.02 initiated December 1989, requested that work packages be revie~ed.to insure the latest PMT requirements are in the packages prior to be1ng sent to the fiel During the MTI inspection, the team id~ntified weaknesses in the post maintenance testing progra Subsequently, an interim post maintenance testing program was develope The interim program was implemented by work analysts who reviewed each work package and identified the post maintenance verification or test to be accomplishe The work analyst used a matrix that outlined each major component type and the test to be performe The inspector reviewed several work packages and noted that adequate post maintenance te~ting was performed.
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The licen~ee planned to use the interim program until a formal program is to be developed~and approve ~.*
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! Preventive Maintenance and Survei 11 ance A study c~nducted i~ 1988 by a contractor identified 15 systems for~ detailed evaluation of maintenance requirements, based on the previous problem A system unavailability study was conducted i11. January 1990 on four systems; high pressure core injection, diesel generators, low pressure core injection, arid ac/dc distribution systems.. The licensee was currently.reviewing the contr.actor's recommendation It appeared that BOP ccimponents have not been maintain~d with the same vi go~ as safety-related component For example, only 97 of 332 BOP MOVs have been overhauled and not all BOP valves were in the General Surveillance (GSERV)
Progra Also, 480 Vac BOP MCCs.have not been put in GSERV for periodic PM activitie A weakness was observe9 in sizing of thermal overloads on BOP motor operated valves fed from the HPCI MCC The thermal overload size and position were not documeted, as a result, it is unknown if proper design consideration was given to these BOP valves.* In addition, progress with BOP surveillances appeared to be laggin As of January 31, 1990, out of 485 surveillances in the non Technical Specification or rion-EQ related areas, 79 were past due which was 16% against the goal of 6%.
The team concluded that a need exists to priorttize maintenance on BOP components and base it.on the component's failure affect on safety-related system.. Technical Support System Engineers
_The system engineers concept was started about ~wo years ag Currently, the station has 31 system enginee~~. with experience ranging between two months and six years, The system engineef concept has not yet taken root. In general, the system engineers did not appear to be involved with equipment failure and root cause analysi The system engineers neither received completed work requests, nor maintained system "Note Books."
The technical staff supervisor stated that there were plans to develop a
"Conduct 6J Tech Staff" similar to the "Conduct of Maintenance" including a detailed program and procedur.es for implementing the "System Engineer", which would be developed after the issue of "Conduct of Tech Staff" in September 199. Problem Analysis Data Sheet (PADS) Program The licensee had implemented a generic program foi the identification and resolution of maintenance' probl.ems by use of a PAD The program was somewhat controlled by Maintenance Memorandum No. 38, "Implementation of Draft Procedure, Analysis of Mai nte.nance Prob 1 ems," dated September 1.5, 198 PADS were used to evaluate root cause*and corrective-action if safety-related equipment failed a surveillance or post maintenance operability test, was declared inciperable, demonstrated a set number of failures over a specified time period, or exceeded a predetermined number of manhours to repair, The 1989 MT! *identified a weakness in the slow progress in the resolution of PADS in that only 13 of 185 had 12 *
been resolve During this inspection it was noted that 248 of 432 PADS had been complete However, upon further review, it was noted that 78 PADS were
"missing"; 35 from 1988 and 43 from 198 The licensee was aware of those PADS but had not taken a~y action to locate or reconstruct them in *order to complete a root cause analy~is. At the completion of this inspect~on, the licensee deve16ped an action pl~n for the missing PADS, which consisted of: (1) reviewihg the list of missing PADS to determine if ~ny were* covered on a duplicate PADS, a~d (2) reviewtrg the remaining PADS and determining if reconstruction of the PADS was warranted.** If so, a new PADS would be written; if not, the justification would be documented:* Neither the inspectors or the litensee could determine
_the safety significance of the missing PADS; therefore, this item is considered to be unresolved until a review of the reconstructed PADS is conducted (~37/90011-03(DRS); 249/90010-03(DRS)).. *
The inspectors also reviewed the timeli~ess of resolution for a sample of 83 open PADS given to Technical Staff the ~eek of March 26, 199 (According to MM-38, the PADS were required to be: (1) signed by the Master Mechanic/
Electrician/I&C after completion of maintenance and initial root cause determi-nation; (2) the PADS were then given to the PADS Coordinator; and (3) then assigned to the Technical Staff for final root cause and corrective action.)
There were 13 PADS greater than 18 months old, 32 were 12 to 18 months old, 23 were 6 to 12 months old, and 15 were less than 6 months ol These PADS had be.en held at various poi.nts along the process path and the 1 icensee did not know the reason for the untimeliness of the Technical Staff's receipt of the PAD The inspectors concluded that th~ use of MM-38, which essentially was a draft procedure, contributed to. personnel involved in the PADS process treating the PADS program as a "trial" program and therefore exhibited less concern and stringent contr61s on the tracking and processing of the outstanding PAD The licensee established a Technical Staff backlog goal of 10 to 15 PADS 'but the current backlog was 15 There*were 27 engineers that evaluated PADS who were also responsible for the evaluation of Deviation Reports; modifications, and other day-to-day system activities. The inspectors were tbld that th~
engineers worked appro~imately 1a to 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> of overtime per week in order to keep pace with the work.load even without the recent increase in the backlog of PADS. Based on current circumstances the inspectors concluded that the licensee's backlog goal was not realistic nor achievabl. Trending and Predictive Maintenance The maintenance trending program, based on work history, was improvin Equipment/
component history relied heavily on Total Job Management (TJM) "header" record data; therefore, improvements in thi~ area ultimately led to im~roved and accurate maintenance trending dat From March 1989 to February 1990, approxi-mately 23;000 header records data had been added to the TJ Fifteen systems were identified as priority for complete TJM maintenance histor Header records for the 15 systems were completed for Unit 2 and 60% were completed for Unit 3, which should be completed by December 199 The MT! identified that Maximum Occurrence Reports were i~sued when two corrective WRs were written on a documen Because of the improved and detailed header records for components, Maximum Occurrence Reports were decreasin Items were
-~.
no 1 anger 11dumped 11 into a generic equipment i dent if i cation (EID) for 1 ack of an accurate EID for th~t particular componen.9. Thermography During the MTI, the licensee indicated that a program to implement predictive maintenance, including a thermography device to detect lobse electrical connections, would b~ initiate Currently, no formal program has bee *initiated for thermograph In October 1989, the licensee hired a contractor for two days to take baseline data of some electrical components including the 110 11 condensate/booster pump motor that failed in January 1990 and indirectly caused a reactor scram. Although not conclusive, indications were that the 11011 condensate pump motor was reading 30°F higher than the other three pump motors.*
On April 3, 1990, the licensee received a thermographic device and indicated that a thermography program would be initiate. 9.. 3. 2 Lube Oil Trending During the MTI la~k of a comprehensive oil trendi~g program was identifie Currently, various oil sampling and analysis techniques are utilized with the intent to choose one program for oil all.analysis and trending.* The licensee is approximately 30% complete with this corrective action; therefore, the inspectors could not asses~ the progres The current practice includes sending samples offsite for spectrochemical analysi Results were tracked, distributed to the system engineer, and recommendations from the contracted analysis was incorporated.
A new equipment trending program will be utilized to tr~nd and consolidate all vibration, oil analysis, IST, and ther~ography results over many years and use the high and low alarm points as acceptance criteri This data will be given to the system engineeri for evaluation of trends on a monthly basi This new program was in the initial stages of implementation and could not be assessed by the inspectors~ Currently, the licensee trends and distributes vibration data to the system engineer for revie..9. Valve Testing*
MOV Overhauls The licensee overhauled. 100% of the EQ safety-related valves, 100% of non-EQ safety-related valves (increased from 76%), and 29% of the BOP MOVs (increased from 10%).
Many of the Unit 2 BOP MOVs are s~heduled for overhaul during the fall 1990 outag All BOP MOVs are to be completed by June 199 Diagnostic testing was comp1eted on 65 valves with 50 scheduled fbr the Unit 2 refueling outage and 50 scheduled. for the Unit 3 refueling outag The licensee showed continued progress in the completion of the MOV improvement program; MOV failures have steadily decreas*ed over the past three year.9. Check Valves A check valve inspection program was implemented that included the periodic inspections necessary to ensure that check valve internals were intact and not experiencing abnormal wea The scope of the program was much broader than that required in Significant Dperating Event Report (SOER) 86-03 because
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Dresden had included* check valves measuring two inches and unde To d~te,.115 of 205. check val~es.have *b~en inspecte When abnormal wear was identified another check valve in the same category was also inspected to evaluate the pervasiveness of the anomalies'.
The increased.scope and investigation of common mode failu~e technique was considered a strengt. Vendor Manual *Control and Incorporation of Vendor Requirements
- into Procedures
- Only limited improvement was noted in the area of vendor manual control since the MT! was complete The vendor.manuals available for work at the station cover about 1025 models, of which only 424 (16%) were controlle Out of an
- *o.estimated 850 safety-related equipment models only 101 {11.9%) had controlled
. vendor manuals avail.abl The inspector reviewed seven controlled vendor manuals. selected at rando~ and no problems were identified.** However, the applicable equipment was no indicated on the manuals and there was no cross ref~rence to the procedures that the vendor manuals were use As a result of discussions with the system and maintenance engineers, the inspector concluded that a detailed evaluation of the ~ender manuals was not
- done to include the applicable vendor recommendations in the station procedure The lic~nsee stated that a corporate vendor contact program ii being established and is expected to commence in July 199 Th~ corporate office will contact the v~ndors on behalf of all the CECo nuclear p~ants. Jhe licensee al~o stated that the vend6r manuals at each of the stations would be sent to the corporate office for a detailed revie It appeared that the complete implementation of this program would take several years before the results of such detailed reviews would enable the vendor recommendations to be incorporated into the appropriate station procedure~.
4-10 Station QA Audits and Surveillances of Maintenance Activities The team reviewed the audits and surveillances performed by the lic~nsee since February 1989 in the maintenance area to determine the effectiveness in identifying maintenance related problems:
Four audits and a number of surveillances were
. completed by the licensee since February 198 No adve.rse findings were identified by the licensee even during a period.when otherassessments of main-tenance ide~tified numerous* problems specifically in electrical maintenanc ~he inspectors determined that QA audit reports 12-89-36, 12-89-37, 12-89-38 and 12-89-42 were narrow, shallow, and compliance oriente For example, QA Audit QM-12-89-42, Question 8,.required the auditor to verify that the PM recommendations from the vendor equipment manuals were reflected in the mainten-a~ce procedure To accomplish this, the auditor merely verified that the procedures referenced the vendor manuals without checking that the procedures actually contained the vendor reco~mendations. To correct *this, the team was informed that for audits conducted in 1990, an improved "Standard Audit Checklist" and other improvement~, such as longer time for audits and use of mainten~nce experts as.Buditors, will be institute QA surveillance item QAS 12-89-111, written August 8, 1989, identified that work was performed outside the stope of WR 8153 The WR, dated in January 1989, stated to troubleshoot safety-related containment isolation valve MOV-2-1201-The work performed Section of.th~ WR stated that a wire was removed from a terminal block and taped u This was done by a craftsman
i **
..
- contrary to the desigh drawing, which indicated that the wire was to be terminated* on th~ terminal block, sealing in the valve opening.circui A~ a result, the sealed-in opening circuit of the valve was removed and made into a throttling circuit 6n an open signa The same unapproved change appa~ently ~as performed on Unit 3 MOV-3-1201-The licensee stated that the Unit 2 circuit has been modified to seal-in o.n open and the Unit 3 open circuit will be modified to its original configuration during the ne~t refueli~g outag It should be noted that both valves would still perform the closed isolation function on deman The team had two concerns: (1) that an electrician could perfor~ a functio~al logic change to the valve**s circuitry without going through the design change process, specifically the 10 CFR 50:59 review; and (2) QC did not discover the design change during the QC release and final review stages in February 198 A DR was not written until August 1989 and itill remained open at the time of this inspectio Also, the package went through all the approval cycles and was being completed and signed off without a concern being raise This item unresolved (237/90011-04(DRS); 249/90010-04(DRS)).
Since the team was not able to observe ongoing maintenance activities during this inspection, QC involvement during maintenance activities could not be examine This was identified as a concern during the MT!.
The ihspectors noted, however, that *licensee Action Item CORP. ASSESS.01.00 requested that this area be examined during the upcoming corporate maintenance assessment in June 199.11 Control of Materials and Parts The MTI report stated that safety-relat~d it~ms were procured from a vendcir not listed on the quality approved bidders lis The licensee stated that all Dresden BWR engineering procurements were now being routed through the station store keeper for a proper processing.* The inspector did not identify any recent procurements from ~napproved vendor *
The MTI report also stated that materials delivered to a contractor's hold area were picked up and mispl~ced. The licen~ee stated that a new contractor now maintained a hold area and maintained all the documentation for rec~ipt inspection for items stored.in the contractor's warehouses or the items were immediately forwarded to station Engineering Construction Group~at the station, thereby reducing the possibility of a 11 loss 11 of materia The inspector reviewed the contractor's ho'ld area and warehouse facilitie Procedure SP-lX-02, "Material and Equipment Identification and Inspection Statu~ Control,
11 Revision* August 25, 1989, required that identification of
. quality related material be maintained during ~torage, and procedure SP-lX-03,
"Material and Equipment Storage and Control," Revision August 30, 1989, required that care *be taken in storage areas to ensure compliance with safety policies and procedure Contrary to the above, on April 4, 1990, 'the inspecfor observed that four, one inch sealing locknuts were stored in safety related storage area No. 30 without*
any identification markings~ Failure to follow procedures to cont~ol the storage of safety related materials is considered a violation of Criterion V of 10 CFR 50, Appendix 8 (237/90011-05(DRS>; 249/90010-05(DRS)).
)..
- However, the violation was not cited because the criteria specified in Section V.A of the Enforcement Policy were satisfie The violation would normally be classified as a Severity Level V and was an isolated instance; the violation was promptly corrected, by discarding the sealing rings; and adequate adminis-trative controls were in place to prevent recurrenc.0 Unresolved Items Unresolved item~ are matters about which more information is required in order to ascertain whether they are ~cceptable items, violati~ns, or deviation Unresolved items disclosed *during this inspection are included in Paragraph 4.3, 4.9.*2, and 4.10 of this repor.0 Exit Meeting The inspectors met with licensee representatives (denoted in Paragraph 1) on
- April 12, 1990, at the Dresden Plant and summarized the purpose, scope, and.
findings of the inspectio The inspectors discussed the likely informational content of the inspection repo~t with regard to documents or processes review~d by the inspectors during the inspectio The licensee did not identify any such docum~nts or processes as proprietary.
17