IR 05000254/1989017
| ML19332E400 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 11/28/1989 |
| From: | Bell L, Ted Carter, Harper M, Mendez R, Miller D, Neisler J, Raleigh J, Tella T, Walker H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19332E395 | List: |
| References | |
| 50-254-89-17, 50-265-89-17, NUDOCS 8912070176 | |
| Download: ML19332E400 (54) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
,. Reports No. 50-254/8'9017(DRS); 50-265/39017(DRS)
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Docket Nos. 50-254; 50-265 Licenses No. DPR-29; DPR-30 l Licensee: Commonwralth Edison Company
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Post Office Box 767 Chicago, IL 60690
Facility Name: 1 7d Cities Nuclear Generating Station Units 1 arid 2 Inspection At:- Qvad Cities Site, Cordova, Illinois inf.cection Conducted:
Septembe 13-22, October 2-6 and 18, 1989
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~In s pr etors:
J. H. Neisler, Te e 4/4N
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M. Wastlund
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[D.Jablonski, Chief IINY/I)
Aoproved By:
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Maintenance and Outage Section Date P!A20gg; g gg;;g g Q
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I Inspection Summary
' Inspection on September 18-22, October 2-6, and 18, 1989 (Reports No.
50-254/59017(DR5); 50-265/89017)(DR5)
Areas Inspected:
Special announced team inspection of maintenance, support i-of. maintenance, and related management activities. The inspection was L
conducted utilizing Temporary Instruction 2515/97. the attached Maintenance v
Ynspection Tree, and selected portions of Inspection Modules 62700, 62702,
>62704, 62705, and 92702 to ascertain whether maintenance was effectively L
acconplished end assassed by tbs licensee, F
Resultsi Areas of strtn;ths and weaknesses were identified as discussed in'
the Executive Summary. Overall implementation of the licenst.e's maintenanca
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program is cynopsized in Section 4.0 and war, detennined to be -satisfactory.
.There.were two violations: four examples of fa11ure to follow procedures or inadequate procedures; and two examples of failure to tele tirrely correct've action or the corrective actions were inadequate.
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L CONTENTS Section M
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1.0 Persons Contacted.....................
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2 0-Licensee Action on Previous In:;pection Findings......
3.0 Introduction to the Evaluation and Assessment of
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Maintenance...,...................
3.1.
Performancy Data and System Selection...........
3.1.1 Historic Dt,ta
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3.1.2 System Selection...............,.....
3.2 Description of Maintenance Philosophy
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3.3 Observation of Current Plant Conditions and ongoing
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Work Activities.....................
3.3.1 Current Material Condition................
3.3.2 Ongoing Work Activities........
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3.3.2.1 Ongoing Electrical Maintenance..............
3.3.2.2 Ongoing Mechanical Maintenance..............
3 3.3.2.3 Ongoing Instrument and Control Maintenance........
3.3.3 Radiological Controls...................
3.3.4 Maintenance Facilities, Material Control, and Control of Tools and Measuring Equipment........
3.3.4.1 Facilities........................
3.3.4.2 Material, Equipment, and Tool Control...........
3.3.4.3 Control and Calibration of Measuring and Test Equipment..
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3.4 Review and Evaluation of Maintenance Accomplished.....
3.4.1 Backlog Assessment and Evaluation.............
l 3.4.1.1 Corrective Maintenance Backlog..............
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3.4.1.2 Preventive Maintenance Backlog............
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3.4.2
. Review and Evaluation of Completeo Maintenance....
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'Past Electri:a1 Maintenance.......
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3.4.2.0 Past Mechanichl liaintenance.............
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3.4.2.3^
?ast Instrument and Control Maintenance.......
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'3.4.2.4
' Post Maintenance Testing...............
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3.4.2.5 Vendor Manual Control................
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3.4.3.1 NPRDS........................
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3.4.3.2 Performance Measures / Maintenance Trending......
3.4.3.3 LER Program.....................
3.4.3.4 CFAR Program......................
j 3.4.3.5 Use of NRC Bulletins, Notices, and Other Vendor Information Letters
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3.5 Maintenance Work Control...............
3.6 Engineering Support of Maintenance..........
3.6.1 Engineering Support.................
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3. 6. 2.-
Technical Support..................
3.7 Maintenance and Support Personnel Control......
3.8 Review of Licensee's Assessment of Maintenance....
3.8.1 Review of QA Audits and Surveillances........
3. 8. 2.
Licensee's Self-Assessment and SSFIs.........
3.8.2.1 Self Assessment...................
3.8.2.2 Safety System Functional Inspections (SSFIs).....
3.8.3 Effectiveness of Corrective Action..........
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i Section Pm f
4.0 Synopsis.........................
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4.1 Overall Plant Performance..............._.
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4.1.1 Performance Indicators...................
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- Plant Walkdowns... -,.................
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4.2
.Managoment Surport of Maintenance.............
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Manareinnt Cemitmeric and Involvement...........
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4.2.2
- Managemert 4rganization and Administration........
j 4.2.3 (echnical Support....................
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4.3
_ Maintenance Implementation................
4.3.1 Work Control.......................
4.3.2 Plant Maintenance Organization..............
j 4.3.3 Maintenance Facilit'ies, Equipment, and Material Control.
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4.3.4 Personnel Control....................
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Exit Meeting..................._....
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Appendix A: Acronyms
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DETAILS 1.0 Persons Contacted i
Commonwealth Edison Company (CECO)
- D. Galle, Vice President, BWR Operations
- R. Kalivianakis, General Manager, BWR Operationt,
- R.lBax,, Station Manager
- D. Craddick, Master Electrical Mechanic h
- J. Dierbeck, Supervisor, Technical Staff
- J. Fish, Master Mechanic
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- D. Gibson, Supervisor, Regulatory Ass'irance 7?
- L. Petrie, I,ssistant Superintendent, Maintenane.o s
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- G. Price, Maintenarce Supervisor
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- D. Rajcevich, Master Instrument MeNar.ic cR. liobey, Technical Supertittendent
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- G. Spedi, Production Superintendent
- G. Vagnw, Nuclear Engincering Managar U. S. Nuclear Regulatory Commission (NRC)
- T. Martin, Deputy Director, Division of Reactor Safety
- R. Higgins Senior Resident Inspector
- F. Jablonski, Chief, Maintenance and Outage Section
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- W. Shafer, Chief, Reactor Projects Branch 1. Division of Reactor Projects
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- Denotes those present at the exit meeting on October 18, 1989.
Other licensee personnel were contacted as a matter of routine during the
inspection.
2.0 Licensee Action on Previous Inspection Findings
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2.1 (Closed) Violation (254/87009-01; 065/87009-01):
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Failure to determine the cause and take appropriate corrective action on licensee event reports (LERs). Licensee action to address this issue was described in the licensee's letter to the NRC dated May 20, 1987. The inspectors reviewed the methods currently in place for root cause determination and corrective action. Maintenance Department Memorandum No. 55 was issued August 1, 1989, to implement a pilot procedure entitled, " Maintenance Problem
Analysis Program." This procedure used a problem analysis data sheet (PADS)
form for root cause evaluation and determination of required corrective action.
The-inspectors reviewed this procedure and the PADS form; if properly implemen-ted, PADS has the potential to be an effective method for root cause analysis and correction.
This program was in the early stages of implementation and no actual root cause analyses were reviewed by the inspectors.
This item is considered closed.
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This violation addressed inadequate software control for the computer programs used for meeting Technical Specification recuirements. The licensee's response p
dated January 22, 1988, and NRC letter datec February 11, 1988, described
acceptable corrective actions for this viciation.
The inspector verified that hand calculations were made to verify the results L
of the resctivity anomaly as calculated by the programs '/sNOM' and "ANOMOP'
for the previous fuel cycles. The results were all within the limits specified
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by the Technical Specifications. 1he licensee also stated that since June 1989,
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both programs were controlled as per the applicable procedures.
The inspectors veriYted that the configurations of the programs 'ANOM' and 'ANOMOP' were being properly controlled.
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Thi'; tLem is considered closed.
2.3 (Clos,ed) Open Item (254/08007-02; 265/85008-02):
This item addressed possible procedure inadequacies in the perfermance of the suppression chamber water level indication calibration. The inspectors reviewed licensee action in response to this concern. Surveillance procedure QIP 1600-3,
" Suppression Chamber Water Level Indication Calibration," Revision 1 was reviewed and revised after the inspection. A system was established for feedback and comments from personnel utilizing the surveillance procedures.
This resulted.in revisions to approximately 230 surveillance procedures. Use of this feedback had recently been discontinued; however, comments from technicians were considered when problems with procedures were encountered.
This item is considered closed.
2.4 (Closed) Open Item (254/88011-01; 265/88012-01):
This item addressed the failure to have a method in place to identify the status and to track overdue PM items. The inspector interviewed the Station PM and Surveillance Coordinators and reviewed the procedure controlling the General Surveillance System which is being used to identify the status of PMs to management. A monthly report of PMs that were more than 2 weeks overdue was being issued by the Station Surveillance Coordinator to the cognizant assistant superintendent, superintendents, and the Station Manager. Missed PMs were also addressed in a semiannual report issued by the Station Surveillance Coordinator. The licensee was adequately addressing the issue of missed PMs.
This item is considered closed.
2.5 (Closed) Violation (254/86011-02A; 265/88012-02A):
Failure to provide a procedure for periodic lubrication of motor operated valve (MOV) actuators according to vendor recommendations Licensee action to resolve
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1988, as revised by a letter dated May 26, 1989. The inspectors reviewed scheduled PMs for motor operated valves (MOVs) and noted that periodic lubrications had been scheduled.
This' item is considered closed.
,_0ppnLViolation (254/88011-028); 265/68012B):
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Failure to periorm PMs on horizontal 4KV circuit breakers as required by procedure number QEMP200-1, Revision 3.
Licensee action to resolve this issue n
l was described. in licensee's letter to the NRC dated October 17, 1988, as revised by a letter dated May 26, 1989. The inspectors observed preventive
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maintenanco being performed on Unit 1 4KV breakers and noted that this work
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included a complete cleaning and overhaul of these breakers. After the overhnul was complete, the breaker was included in the PM progrrm and schW uled for periodic osintenance. Overhaul of Unit 1 breakers is scheduled to be completed during the current Unit 1 cutsge. Overhaul of Unit 2 breakers was
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scheduled to be completed during the Unit 2 outage, which was schedulo! to
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begin in Jcw ary 1990. This iton will tenin open pending ccmdeelvn of aaintenance on the Unit 2 breekers and hcharAcn of these breaws in the FM program.
2.7 (ClotoM On g Item (254/88011-03; 265/88012-03):
This item involved the failure to prioritize PMs resulting in the long term delay of PMs on significant safety related equipment. The inspectors reviewed the General Surveillance Request Form (GSRF) which was being used to prioritize PMs. The priority was based on possible contents of Technical Specification requirements Balance of Plant, or "Other" and assigned numerical numbers 1 through 4, respectively. Data entry and system update is authorized by the Station PM coordinator.
This item is considered closed.
2.8 (Closed) Open Item (254/88011-05; 265/88012-05)
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This item addressed possible inadequate maintenance work instructions. The inspectors reviewed NWR packages for 7 maintenance jobs in progress and 26 completed NWR packages and did not note any safety-related work packages which appeared to have inadequate work instructions.
This item is considered closed.
2.9 (Closed) Open Item (254/88011-09; 265/88012-09):
This item addressed the replacement of General Electric (GE) 12 CFD relays with Westinghouse type SA relays. The GE 12 CFD differential relays were replaced for Unit 2 and Unit 1/2 DGs during the Unit 2 outage. However, the licensee was planning to replace the Unit 1 DG GE 12 CFD differential relays during the Unit 1 outage. The inspectors were concerned that a potentially non-seismically qualified differential relay would be installed in Unit 1 DG until the Unit 1 outage.
During discussions between the licensee, NRC Region III, and NRR personnel, the following were agreed upon:
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A letter from the licensee's engin:ering organization will be placed
.in the modification packages M-4-1(2)-85-7 and M-4-1/2-85-26 stating that the installed GE 12 CFD differential relays would perform as
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required during a seismic event.
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The Unit 1 DG GE 12 CFD differential relays would be replaced with
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Westinghouse SA1 relays at the first opportunity instead of the Unit 1
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l-outage.
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i; The inspectors reviewed the ietter of performance for the GE 12 CF0 differential
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relays and considered it adequate. Also, a Work Request (WR) had been issued
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at the time of this inspection, being routed fre final approval fer installation.
Ws item is coasidered closed.
2.10 (00en) Violation-(254/88011-10B D 65/88012-10B:
Failure to provide timely corrective accion to ccrrect a 4KV latch mechanism problem. 'icensee action to resolve this issue was der:ribed in the licensee's letter to the NRC dated October 17, 1988, ac revised by a letter dated May 26, 1989. Specific action on preventive maintenance of 4KV breakers was addressed in Section 2.5 of this report.
Corrective action was addressed in Section 3.E.3 of this report. This item will remain open Sending completion of maintenance on the Unit 2 breakers, inclusion of t1ese breakers in the PM program, and satisfactory resolution of corrective action concerns.
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2.11 (Closed) Violation (254/88011-10D; 265/88012-10D):
Failure to promptly identify and correct inadequate work instructions and the verification of operability of butterfly valves. Licensee action to resolve this issue was described in the licensee's letter to the NRC dated October 17, 1988, as revised by a letter dated May 26, 1989. The inspectors reviewed work in progress on 21 work requests in the mechanical, electrical, and instrument and control areas; 46 completed work requests were reviewed; no significant
problems with inedequate proceduret were noted. The licensee had established
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a procedure review group to review all maintenance procedures for adequacy and consistency during the next two years. The licensee had established methods and
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short term schedules to verify proper operation of all safety-related butterfly valves for both units.
This item is considered closed.
, Closed) Unresolved Item (254/88011-11; 265/88012-11 (
2.12 This item concerned inadequate work instructions that failed to require verification of valve position prior to installing position indicators; also,
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l QC hold and witness points were primarily in the welding and fit-up area and
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did not seem to address the valve installation and connection. The inspectors i-verified that the licensee had issued instructions in the work requests for the installation and maintenance of butterfly valves for verification to ensure proper orientation of the valve pet tion and the position indicator.
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t 2.13 (Closed) Open Item (254/88011-12; 265/88012-12);
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This item addressed the failure to erform lubrication of electrical equipment.
L QA performed a surveillance (QAS-04 89-052) which was upgraded to an audit (QAA F
04-b9 42) in the area of equipment lubrication. The audit resulted in the i
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hiring of-a consultant to review the PM program, the development of a Lubrica-
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tion Program by a contractor, and modification of Electrical Maintenance (EM)
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procedures and application of the procedures. The inspector verified the i
implementation of a-lubrication program and reviewed the EM lubrication schedule.
Both lists were categorized as A-B-C priority lavels 3nd scheduled lubrication
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was 100% complete.
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2.14 (Closed) Violatinn (234/88011-13;_265f88012-13):
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This item concerned 0A audits to verify compliance with and to determine the
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effectiveness of the documented PM requirements. The inspector reviewed PM audit QAA 06 89-42. The audit documented two findings, three observations and cne open item. As a result of the audit, a PM coordinator was assigned to the maintenance staff PM procedure QAP 500-9 was revised to include assessment and trending of PMs. and a pilot program for site PM was implemented.
This item is considered closed.
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3.0 Introduction to the Evaluation and Assessment of Maintenance
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This inspection was conducted during the Unit 1 refueling and maintenance outage and while Unit 2 was at power to evaluate the extent that a maintenance program had been developed and implemented at Quad Cities Nuclear Station.
Three major areas were evaluated:
(1) overall plant performance as affected by
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maintenance; (2) management support of maintenance; and (3) maintenance implementation. This inspection was based on the guidance provided in NRC
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Temporary Instruction 2515/97, " Maintenance Inspection, and Drawing 425767-C,
" Maintenance Inspection Tree." The drawing, which is s.ttached to this report, was used as a visual aid during the exit meeting to depict the results of the
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inspection.
The goals of this inspection were to evaluate maintenance activities to determine if maintenance was accomplished, effective, and assessed by the licensee to assure the preservation or restoration of the availability and reliability of plant structures, systems, and components to operate on demand.
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Results of this inspection were derived from data obtained by observation of current plant' conditions and work in progress, by review of completed work, and by evaluation of the licensee's attempt at self assessment and correction of weaknesses. Major areas of interest included maintenance associated with electrical, niechanical, instrument and control (I&C), and the support areas of radiological control, engineering, quality control, training, procurement, and operations. Problems identified by the NRC inspectors were evaluated for effect on Technical Specification operability and technical or managerial weaknesses.
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3.1 Performance Data and System Selection 3.1.1 Historic Data
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The inspectors reviewea p ant operations history data for 1988 and available
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data for 1989 to assess the licensee's performance in meeting established t
goals. The data pertained to forced outage rates, unplanned reactor scrams, engineered safety feature (ESF) actuations, safety system actuations, LCOs entered because of equipment failures, licensee event reports (LERs),
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equivalent availability and collective radiation exposure. The licensee had established goals or targets in each of the above areas and the data reviewed
by the lespectors indicated that plant performance in 1989 was considerably
batter th m in previous years and :he trenos indice.ted that the improvement in plant perfomence was continubg. Of particular significance, was the reduction of 80 parcent in the number of personnel error deviation reports l
attributed to maintenance personnel.
3.1.2 System Selection The systems and components selected for this inspection were based on the probability risk assessment (FRA) stsdy f urniined tc the team by the Reliability Applicadons Section of the Office of Nuclear Reactor Regulation and review of LERs, Deviation Reports, Nuclear Power Reliability Data System (NPRDS) and discussions with the Senior Resident Inspector. The systems selected were:
AC Power System High Pressure Cnolant Injection (HPCI) System RHR Service Water System Core Spray System 3.2 Description of Haintenance Philosophy The inspecto-s reviewed plant policy statements, administrative procedures, organization charts, established goals, and documents that described improvement programs for the maintenance process. The licensee had a documented corporate maintenance plan, Conduct of Maintenance (COM), that included milestones and completion dates for improvement programs and goals. Discussions by the inspectors with selected managers and supervisors indicated that those personnel were knowledgeable and aware of the established performance goals.
The inspectors determined that the licensee's maintenance program was appropriately balanced with corrective maintenance (Cll) and preventive maintenance (PM). Performance monitoring in the areas of vibration analysis, lubricating oil sampling, and pipe erosion / corrosion monitoring were well established. A thermography program was being initiated, however, only baseline measurements on in-plant switchgear had been performed while the licensee was currently developing and expanding the program.
In those areas where the programs had been implemented, the predictive maintenance programs had been effective in improving the overall maintenance process at Quad Cities.
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The licensee's philosophy)of maintenance included the principles of relit.bility centered maintenance (RCH. The station is currently performing fault tree
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analyses on selected systems under their System Unavailability Monitoring Studies (SUMS) program to determine methods to improve system reliability and other " state of the art" upgrade programs such as improved MOV maintenance /
testing and new equipment alignment techniques.
3.3 Ubservations of Current Plant Conditions and Ongoing Work -Activities 3.3.1 Current Material Condition I'
The inspectors performed general plant as well as telected system and r,einponent walkdowns to assess the general and specific material condition of the plant to L
verify that work requests had bech initiated for identified equipment problems,
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and to evaluate housekeeping. The selected systems and components, based on a generic PRA study for Quad Cities performed by the Reliability Applications
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Section of the Office of Nuclear Reactor Regulation, are identified in Section
3.1.2 cf this report.
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Walkdowns included an assessment of the buildings, components, and systems for
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proper identificatica and tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and any unusual conditions.
Unurual conditions included but were not limited to water, oil, or other liquids on the floor or equipment; indications of leakage through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting. Results follow:
Housekeeping appeared to be good on Unit 2 which was in operation.
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Housekeeping was acceptable on Unit 1 considering the fact that the unit was in an outage and substantial maintenance work was being performed. Although small puddles of water and oil were noted in some areas, they did not appear to be excessive.
Small oil puddles were noted near all the three diesel generator
lube oil areas.
The inspectors noted that no deficiency tags or work requests were generated for Units 1 and 2.
After the walkdown, maintenance work requests were issued in these two areas.
In the case of the Unit 1/2 diesel engine lube oil leak, the inspectors observed a puddle of oil near the lube oil filter. The oil was immedictely removed by licensee personnel. A work request was prev.iously issued to correct this oil leak.
The inspectors noted that the service water pump motor ventilation
openings were clogged with insects, and service water pump 1B had an excessive shaft packing leak with water on the floor.
In addition, an oil spill was noted near the upper bearing of circulating water pump 10.
In areas of the Unit 2 Reactor Feed Pump Room, the inspectors noted
instances of packing leaks on all RFP MOV Discharge Valves. The licensee stated that these were expected leaks.
However, only one of the discharge MOV's had sufficient containment to prevent potentially contaminated water from leaking onto the floor and surrounding equipment.
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Identification of components and equipment was generally good and
was located on or near the equipment.
However, the inspectors noted that after a modification, an abandoned cable and piping were not adequately secured and marked as spares.
I A walkdown of the control room on both' Units 1 and 2 control panels
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Specifically, several position indicating lights of Unit 2 on the control
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rod drive position indication panel were out and numerous red-red rod
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out indicating lights were de-energized. When operators were questioned
about the lack of indication, they stated the indicating lights burn L
out frequently and lights were replaced when the need was felt.
During the walkdown of the control roem, the inspectors also noted
N that a number 6f large dispatcher " Hold" tags were used for Unit 1 which pertially obstrur;ted the operator's view of other panel meters and switches. ~ Licensee personnei stated that these were not tags controllod by plant personnel but were under the control of the CEC 0 load dispatchar. Licensee personnel submitted a written request to appropriato 'iicensee management personnel requesting that'a smaller tsg be developed fcr nuclear use.
Housekt.eping appeared to oc lax ia the electrical cabinets behind
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the control beards for both Units i and 2.
Heavy dust and dirt accumulations were noted on numerous components and electronic instrumentation ventilation filters in these cabinets.
The Control Block and Jumper log was reviewed. The inspector noted
that the log was not maintained properly. The licensee was able to trace back a few selected jumpers and control blocks, however, the time required to perform the task was unduly long.
The inspectors selected 11 tags from equipment in the plant to evaluate
the effectiveness of the licensee's deficiency identification program.
Open NWRs existed for six of the tags. For three of the tags, the work had been completed and the NWRs had been closed. However, the tags had not been removed as required.
The tags were removed ininediately.
No NWRs had been written for conditions noted on two of
'the tags. NWRs were written for the conditions noted on these tags immediately.
Based on the discrepancies noted, the maintenance tagging system is not considered to be effective.
The inspectors noted that two conduit penetrations in both the Unit 1
and Unit 2 battery rooms were open and were not sealed with fire barriers. A review of commitments made in the fire analysis report submitted to NRC for review in 1977 stated that cable penetrations in the battery room floors, walls and ceilings were scaled with fire barriers. As the battery rooms and battery charger rooms were in the same fire zone, there was no deviation from the fire barrier commitment.
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t During the walkdown of the Unit 1 turbine area, the inspectors i
observed a contractor worker lying on some bags on the turbine
deck.
The worker was noted to be inattentive. He was wearing
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protective clothing as required for work in that area. The licensee l
stated that the worker was on a break and should have left the work
. area if he wanted to lay down. The licensee mentioned that the
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i contractor workers were instructed to stop this practice.
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The inspectors observed a contractor worker cutting a flexible
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conduit with a hack saw, using the top of a motor operator of an MOV
p as a work bench in the reactor building. The work was in a contaminated radiation area. The workers did not have the work
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procedures at the job site. After the concern was expressed, the
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licensee esialained th:t the flex had to be measured in placa. The
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licensee stated that the flex should have been cut t.t a miMmum
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30 feet of the work. The licensee also stated that the contractor
workers were made aware of these regt.irements.
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During the walkdown of the torus area, the inspectors noticed various
small cracks in the concrete drywe'il pedestal of Unit 2, above elevation'554'. Most of the cracks showed mineral deposits, indicating
seepage over several years. Several cracks had moisture on them, even
though no water was observed to flow.
It appened that the licensee
was not aware of this conditbn, as no previous records existed on these r
cracks.
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After a concern was raised by the inspectors, the licensee requested their Architect-Engineers (A-E) to investigate the problem. The A-E investigated and submitted a report that about 30 vertical cracks exist on the Unit 2 drywell pedestal at about 5 foot intervals. The largest cracks were observed to be less than seven mils in width.
An analysis of the scepage water indicated that it could be ground water, as its radioactivity was observed to be same as background.
The A-E concluded that the present cracks would not affect the i
structural load carrying capability of the drywell pedestal. The
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licensee also informed the inspectors that through the revision of-procedure QTS 170/8, water from the drywell pedestal leaks would be analyzed when seepage is observed and that selected pedestal cracks would be monitored to determine if their widths were changing with time.
The components and equipment of Unit 1. Unit 2, and common to both
units were painted with unique color codes. The rooms in which they were located were also painted with uniquely identifiable color bars. This will prevent inadvertent maintenance on a wrong component and is considered a strength.
In general, the material condition was considered satisfactory to maintain operability of components at a level commensurate with the components'
function.
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3.3.2 Ongoing Work Activities The inspectors observed ongoing work in electrical I&C, and mechanical
maintenance areas. The inspectors selected these activities from the plan of the day listing, work assignments in individual maintenance shops, and through discussions with individual-foremen. Where possible, safety signficiant activities were chosen for review.
Maintenance activities were witnessed / observed to determine if those
activities were performed in accordance with required administrative and technical requirements. Work activities were assessed in the f011owing U
areas:.
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Administrative approval prior to start of work.
Equipment properly tagged.
Replacement 3 arts acceptable.
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Adequate worc int.tructier.ss Approved procedures avoilable and pro)erly implemented.
Work accomplished b3 experienced and (nowledgeable otreennel.
Appropriate post maintenance testing included and cor: ducted.
3.3.2.1 Onooing Electrical Maintenance
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-The-inspectors observed )ortiers of electrical maintenance activities.
Electrical maintenance caserved was as follows:
NWR Q 1526-1 - Celibration of Main Steam Line Teraperature Switch -
Change of Fuses
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NWR Q 69655 - Replacement of 125 Volt DC Cable NWR Q 69856 - Replacement of cable for M0-1-1001-47 NWR Q 71909 - Cleaning and Inspection of 4 KV Bus 13 NWR Q 72657 - Preventive Maintenance on RHR pump 1B Motor NWR Q 76908 - Cleaning and Preventive Maintenance on 345 KV Breaker B-T 7-8 NWR Q 77936 - Replacement of Cable and Fuses on EHC Panel NWR Q 78050 - V0TES Testing of Valves 1-1001-23A Electrical Tests of Main Generator rotor for the 5 year PM Inspection LLRT of Electrical Penetration QTS 100-2 Preventive Maintenance QEMP 200-1, Overhaul of 4 KV breaker The inspectors concluded that the performance of electrical maintenance activities was satisfactorily accomplished by skilled maintenance personnel.
Maintenance personnel appeared competent and were knowledgeable of the work performed. However, concerns were identified in the observation of the following work:
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During walkdown of the control room panels on September 20, 1989,
i the. inspectors compared fuse sizes egainst operator aid sheets
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for panel 901-15. Operator aid sheets are controlled documents 4'
l used to assist operators as described in procedure QAP 300-33.
Fuses under master out-of-service card 1971-83 and WR Q 1526-1 were taken out of service for a surveillance calibration on main steam j
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line temperature switches. These switches are part of the primary
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containment isolation system. Fuse 595-7010, #12, was rated at 15
amp instead of the 5 amp rated fuse listed on the operator aid sheet, p
Drawing 4E-1502A, Revision AC, shows a 5 amp rated fuse installed at 595-7010. The inspectors' walkdown of other control room panels did not-identify any other instances of oversized fuses installed that
differed from design ratings.
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The licensee replaced the oversized fuse but on Octcher 2, 1989, had
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not documented the oversize fuse and the corrective rction on a
ciscrepancy report (DR) as required by procedure GAP 1220-1,
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~': Discrepancy Report Procedure," Revision 18.
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Licensee personnel stated that their present system did not require documentation when discrepancies such as wrong size fuses were
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identified. This statement was not consistent with Action Item
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s Request (AIR) 4-88-37 requirenents that discrept.ncies in fuse sizes
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be documented so that an evalut. tion could be performed.
Criterion XVI, Appendix B,10 Ci'R 50, requires that measures be I
established to assure that conditions adverse to quality, such as deficiencies, deveintions, and nonconformances be promptly identified and corrected. Critorion XVI further requires that causes for the
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condition shall be determined and corrective action to preclude
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h repetition shall be documented. The failure to identify and document
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the nonconforming condition regarding the installation of oversized fuses during and prior to this inspection, in spite of having resolved an action item request in 1988 pertaining to this same issue, is considered a violation of 10 CFR 50, Appendix B, Criterion XVI (254/89017-02A,265/89017-02A).
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On October 5, 1989, the licensee issued Discrepancy Record (DR)
89-3461 which identified and documented the incorrect fuse in panel 901-15. The evaluation pursuant to this DR will include root cause
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determination and formulation of corrective action to 3reclude recurrence; additionally, the licensee will evaluate tie safety ramifications of the installation of the oversized fuse in the RPS circuit. The licensee stated that fuses found to be incorrectly sized in the future will be documented on DR's.
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The inspectors reviewed the licensee's fuse control program during the current maintenance outage. The licensee does not consistently t
place out of service tags on fuses when electrical equipment is taken out of service. For example, the inspector ooserved three 5 amps fuses lying in panel 901-36 with no out of service tags; however, fuse holders with the designations TB-B, TB-D, and TB-F each had an out of service tag hanging from the fuse holder.
In most other cases, the out of service tag was attached to the fuse and not the
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F fuse holder. The~ inspectors' review-of the licensee's Procedure QAP f
300-14,!Ecuipment-Out-of-Service," Revision 20, determined that the
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n procedure did not address fuse tagging The inspectors found four 5
F amp. fuses lying in panel 901-l'/ but only one out of service tag was E
observed to be physically attv:hed to one of the fuses.
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j licensee removed the extra three fuses from the panel. With respect to the above inconsistencies, the inspectors.noted that the licensee did not follow the guidance of a Daily Order-issued by the Operations
. Staff (Daily: orders were documents retained by the station but were i
F not-controlled.) On September 22, 1989, a Daily Order was issued by.
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the station's.0perations Staff and signed by all Senior Reactor c
Operators (SR0's).on shift. The Daily Order stated that two out-of-service cards were to be used, one with a red dummy fuse on g'
L the, fuse clia and-the other to be attached to the actual fuse..The inspectors ciecked master:out of service cards 2088, 2143, 2210 and
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k-2236 (issued after. September 22,1989) which were placed on seven
fuses and found that only the fuse pertaining to 2088 contained an
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out of service card both on the red dunny fuse and on the fuse itself.
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None of the other fuse holders were observed to have the red dummy fuse. On October 5, 1989,-the licensee revised the Equipment
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.0ut-of-Service procedure and' incorporated the Daily Order for the use of the dunny fuse and two out of service card requirements.
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Action Item Request 4-88-37-was issued in October 1988 to consolidate discrepancies between field installations and the drawings, to evaluate the overall. adequacy of the manufacturer's data relative to
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time vs. current characteristics and national standards. On July-17, 1989, the licensee's A-E completed a drawing review of schematic and wiring diagrams and developed a Master Fuse List (MFL). The licensee found that of the 1369 fuses reviewed, 42 lacked fuse size information and 575 fuses did not have an assigned Equipment Identification (EIO)
number. Additionelly, the A-E performed a preliminary walkdown of 113
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panels which were examined for the presence of fuses. The licensee
. plans to complete the remaining field panels and a walkdown which would include pulling fuses to record name31 ate data. A final Master
i-Fuse List program had not been formulated )ut was planned for the near
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future.
NWR Q69856 was issued to replace cable #12466 for M0-1-1001-47, with an environmentally qualified cable. On October 4, 1989, the licensee's contractor was in the process of preparing to pull four cables through a conduit. A review of the work package indicated
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L that the calculated values for pull tensions were high. The maximum y
allowable tension calculated by the licensee's contractor was 3193
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lbs. The licensee's procedure permits pulling the cable without f
recording or monitoring the pull tension, but limits the pull tension l
to the value that is equal to or less than the manufacturer's maximum i
pull tension.
Page 21 of the licensee's Nuclear Station Work Procedure NSWP E-01, " Electrical Cable Installation and Inspection,"
Revision 1, stated that breakaway links were an alternative to the use of a dynamometer; however, a dynamometer was preferred. The licensee planned to use approximately 30 pull links, each with a break tension of 100 lbs. This would have limited the pull tension y
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to about 3000 lbs. or'less.than the maximum calculated value of 3193
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lb s ~. However, the inspector noted that the licensee's contractor had
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not correctly implemented this cable pulling procedure and, as a consecuence, had not properly calculated the maximum pulling tension.
Appencix I of procedure NSWP-E-01, requires that for multi-cable
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. pulls in a conduit, the pulling tension shall not exceed the lower of i
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two values, the lesser of the specified maximum pull tension or the
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product AxR, where A is the sidewall pressure and R is the radius of conduit: bend in feet.
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Tha licensee's contractor was not aware-of the criteria to account for the sidewall pressure consequently, the calculation required by
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procedure NSWP-E-01 had not been performed. The licensee
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recalculated the pull tension for cables pulled under NWR Q69856 and found'that when the sidewall pressure limit was-factored <into the 1 calculation, the. actual allowable maximum pulling tension was 467
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lbs. instead of 3193 lbs. A reserve DC feed which was to be pulled i
under work request Q69854 was also re-calculated, resulting in the
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calculated maximum pull tension being reduced from 7000 to 1558 pounds.. The licensee used caution and decided not to pull on schedule the cables under work requests Q69854 and Q69856.
Further' discussions with the licensee indicated that they had not previously accounted for or specified the side wall pressure acceptance criteria in their.past procedures. The licensee's present electrical cable procedure NSWP-E-01 was issued on March 8, 1989, to update the cable pulling requirements. However, the previous procedures (before March 8, 1989) did not account for sidewall pressure, although the
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cable manufacturer (0konite) clearly delineated this requirement in Table A of their cable pulling criteria tables. The licensee
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informed the inspectors that they have pulled several Okonite cables
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with a different electrical contractor during the last two previous outages-(1988-Unit 2 and 1987-Unit 1). The licensee did not provide the pull tensions of cables pulled in 1987 and 1988, and stated that the cable pulling acceptance criteria specWied by the manufacturer i;
v.as not implemented. This failure by the licensee to assure that
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procedures were correct and adequately followed is considered a
violation of 10 CFR 50, Appendix B, Criterion V (254/89017-01A; 265/89017-01A).
During a review of work requests Q69854 and Q69856, the inspectors
noted that power and control cables were being routed in the same conduits. The inspectors discussed work request Q69854 and agreed with the licensee that the safety significance was minimal since power and control cables were DC. However, with respect to work request Q69856, two number 14 control cables (120V) were to be routed with a 1/0 power cable (480V). The maximum current rating for a 1/0 is 175 amps and for a #14 is 15 amps. The licensee intended to pull the cables but attempted to first resolve the pull tension questions raised by the inspectors. These cables were subsequently pulled. The inspectors discussed the issue with the licensee and found that routhg of power cables with control cables
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uy was fairly common at Quad Cities. The licensee stated that Quad I
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Cities was built before many of the regulations or IEEE standards j
went into effect. However, the licensee's procedure QEMP 700-1,
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" Quality Electrical Maintenance Procedure" Revision 1, endorsed IEEE f
p 422-1977.
IEEE 422 prohibits the routing of medium voltage cable with control cables. The consideration for not routing control
cables with power cables is mninly to prevent electromagnetic-l
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interference (noise) to the ccntrol cables and thereby prevent
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inadvertent operations. =This matter will be pursued further with the Office of Nuclear Reactor Regulation to clarify the applicability of
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IEEE 422 to Quad Cities and the acceptability of routing control
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cables with power cables.
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-WR Q77936 - A number 22 AWG conductor supplying power to an electro-
hydraulic control (EHC) test circuit burned through during testing.
The number 22 conductor was changed to a number 14 and the 20 amp fuse in the circuit was replaced.
However, Table 310-17, ampacities of single insulated conductors in the National Electric Code (NEC)
stated that the overcurrent protection for a number 14 AWG conductor shall not exceed 15 amperes. The licensee stated that the power
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supply to the EHC test circuits was divided among four circuits and it was unlikely the current would reach 20 amperes. However, the licensee did not state or calculate the actual current that would flow through the 20 amp fuse, nor did the licensee provide information on the_ voltage drop and its effect on the circuit. Although, the testing circuit was non-safety related, the licensee's corrective actions on WR-Q77936 appeared to be poor.
NWR Q69855 - The work performed under NWR Q69855 involved re) lacing
the main feed to the Reactor Building 125 V DC Distribution
'anel with environmentally qualified cables. On June 30, 1987, the licensee
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discovered that the control cables for several components had polyethylene insulation.
The licensee, however, did not have supporting documentation stating that cables with polyethylene
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insulation were qualified. The licensee subsequently issued Deviation i
Report 4-1-87-059 co initiate action to replace the polyethylene L
insulated cables with qualified cross-linked polyethylene insulated cables. A justification for continued operation was issued by the E
licensee on August 21, 1987. On October 3, 1989, the inspector witnessed portions of a 350 MCM cable termination in the 125V DC
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distribution panel performed by the licensee's electrical contractor.
After the electrical contractor completed the termination, the inspector noted that the QC hold point to verify the expiration date
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for the insulating tape had not been checked. The electrical QC inspector had not verified the expiration date of the tape prior to the taping of the electrical terminatlon in the distribution panel.
The licensee's procedure No. QAP 900-6, " Quality Control Inspection Points and Dimensional Verification", Revision 7, stated that a " Hold Point" was a designated stopping place to verify that the activity was performed correctly and completely. The QC inspection procedure further stated that work cannot be done on this step in the work procedure until the quality group establishing the hold point was
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. notified.and; initiated the inspection activity. The QC inspector
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verified-that the expiration date for the tape had not expired only
after the it.e allation activity was complete.
In this instance, verifying hoio points after the work activity was complete was a' poor
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practice.
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.NWR Q72657 - The work performed under MWR Q72657 involved, in part,
replacing the existing lugs on the RHR pump 1B motor leads. The
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licensee found a problem with the motor lugs due to an unrelated problem. On September 27 1989, during the inspection of RHR aump 1B, the= licensee found metal shavings in the motor housing. T 1e licensee determined that the metal shavings were not due to degradation of the motor bearings but to a threaded guide drilled t
into the outer shell of-the motor. The licensee conservatively
= decided to inspect the entire motor. As part of the inspection, the licensee removed the insulation on the motor leads and pulled on the motor lugs as required by their procedure. When one of the motor leads was pulled by hand, the lug came off completely. The inspector asked the licensee whether this problem was common to other HKV ECCS motors. The inspector was informed that the motor for RHR pump 1B was received from Monticello plant and that it was unlikely that y
other: motors at Quad Cities had problems with poorly crimped lugs.
The inspector reviewed the receipt ins?ection records and the work request which required that the motor 3e installed on July 22, 1985,.
per NWR Q43490. A review of work request Q43490 and the associated parts list indicated that the original motor lugs were not replaced i
when the motor was installed at Quad Cities. The licensee has, however, committed to inspecting the connections of RHR motor 1C and to report the results to NRC.
On October 4, 1989, during a r'eview of the work package in the field, the inspector asked the licensee's QC inspector for the expiration
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.date of.the tape, the wiring diagram number, and the revision, and the correct crimp tool number and its calibration due date. All the-above were required QC hold points or witness points. The QC inspector and a licensee QA individual could not locate the tape expiration date, the drawing number, or the crimp tool information.
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The QA individual decided to stop the installation activities until the above questions were answered. The inspector was later informed that information regarding the tape, drawing, and crimp tool were available at the job site and that the licensee's QC inspector was unable to locate the correct work package. However, the QC inspector was unaware that a compression test was required for the crimp tool prior to its use. Additionally, the QC inspector had not checked whether the compression test was current prior to witnessing the motor termination.
The NRC inspectors reviewed the training records and experience of the QC inspector and found that the QC inspector appeared to have enough experience and training to be a qualified QC inspector.
However, the NRC inspector found that the licensee's QC inspecters normally did not follow or track a given work request from beginning
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to end, nor did the_QC inspectors know what particular work activity
was being performed on a given day.
Instead, a QC inspector was
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given a few minutes to' appear'at the work site and then familiarize himself/herself with the installation activities. hold points, and
witness points. -This was cons _idered-to be a weakness in the licensee's QC inspection _ program.
During the review of work utilizing procedure QEPM 200-1 for
Inspection and Maintenance of 4KV Horizontal Circuit Breakers, the inspectors noted that the procedure contained the following note.
- Steps may be )erformed in any order. Sequencing of the steps shall i
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~be determined )y the cognizant supervisor.".This statement would a
allow critical steps such as post maintenance testing to be performed
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at inappropriate times such as before maintenance work was completed.
L This same statement was found in a number of other procedures reviewee during the inspection. A commitment was made by the licensee to.
delete or clarify this type of statement in the current review of maintenance procedures.
i The inspe'ctors noted that a tube of unmarked lubricant was being used
for lubrication of internal 4KV' breaker parts. Procedure QEPH 200-1 specified the lubricant to be used as GE D50H47 grease.
In discussicas
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with the craftsman, the inspectors were told the grease was GE D50H47 and the tube was-appro)riately marked when it was checked out for use at the start of the jo).
Use of cleaning solvents for cleaning the breaker had resulted in the removal of the marking on'the-tube.
3.3.2.2 Ongoing Mechanical Maintenance The' inspectors observed portions of nine mechanical maintenance activities as discussed below:-
NWR Q67433 - lA Preheater Relief Valve Pressure Setting NWR Q67929~- Inspection and Repair of EHC Pumps NWR Q68947 - Installation of MOV, M01-1402-3A
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NWR Q69270 - Rebuilding of M0V, M01-1301-62
NWR Q70942 - Rebuilding of MOV, H01-1301-22
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NWR Q73343 - Replacement of BWR Chemistry Panel NWR Q75938 - Replacement of RHR Service Water Supply Piping
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NWR Q78451 - Maintenance of Service Water Pump 2B D
NWR Q78761 - Replacement of HVAC Supply Fan Belt l
The inspectors-concluded that mechanical maintenance activities were adequate
- and accomplished by skilled maintenance personnel. Maintenance personnel appeared to be knowledgeable and well trained in the work performed.
In a few cases, the checklists were not followed in strict order, but this did not affect the performance of the work.
The Quality Control hold points were properly observed.
The vendor representatives were observed on a few jobs where necessary. The maintenance foremen were observed at the work sites supervising the crews. However, concerns were identified during the observation of the following work:
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A NWR Q67929 - The inspectors observed that the maintenance work; package
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for the repair of EHC pumps did not include any procedures or vendor manual. The inspectors specifically inquired about the torque settings
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for the pump bolts when reassembled. The vendor representative who
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was present did not have an equipment manual.- On inquiry by the
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inspectors, the vendor representative stated that the torque settings-
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were 850 ft.-lb...which was confirmed later by reference to the vendor.
manual.- The licensee perhaps did not include the necessary procedures /
q documents in this work package, as it pertained to non-safety related
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work. The inspectors pointed out that the failure of EHC pumps could cause a turbine trip and thereby a reactor trip, and hence, is i
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important to safety.
The licensee stated that they were currently Ji in the process of reviewing procedures QAP 1500-13 and QAP 1500-14 for revision in an effort to improve the non-safety-related work packages.
The inspectors reviewed corrective maintenance on the licensee's
feedwater check valves. Both the inboard and the outboard feedwater loop B valves failed the local leak rate test (LLRT). The leakage rate of the two valves in series was in excess of the licensee's Technical Specification limits. The licensee had experienced problems in both units with the feedwater check valves for approximately the last ten years. During the last outage, the licensee revised proce-dure QMMP-3200-1, "Feedwater Check Valve Disassembly, Inspection Test and Reassembly," to improve the performance of the valves. Revision of the procedure apparently did not result in better' valve performance.
During.this outage, the licensee received a new 18" tilting check valve, which-is presently the same feedwater valve in use at Dresden.
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This new valve was bench tested but failed the leak test. The
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l licensee found that a low spot on the clapper caused the valve to fail. The licensee's corrective action was to grind and re-cut the seals. The new check valve subsequently passed the bench test.
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The licensee discussed the failure of the valve with the manufacturer.
The manufacturer's representative stated that all new check valves l=
(including the one that failed) have a pivot pin retaining device H
which should help in passing the LLRT's. The licensee found on older l-valves, that wear on the clapper bushing and pin caused the clapper to come out of alignment and consequently resulted in failed LLRT's.
The licensee's solution was to make the pin and bushing out of harder materials to reduce wear of the mating surfaces. The licensee D
appeared to be resolving this issue; however, prompt corrective (-
maintenance had not been evident in this case. However, the inspectors reviewed the licensee's overall check valve program and determined that this program was acceptable.
3;3.2.3 Ongoing Instrument and Control Maintenance L
The inspectors observed portions of Quad Cities I&C maintenance activities as discussed below:
NWR Q33055
"RPIS Power Supply Preventive Maintenance and Adjustment,"
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NWR Q67191'- Troublesho6 ting spike alarm turbine vibration monitor Unit 1 NWR,Q76949 - CRD M-11 (46-43) indication troubleshooting
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-NWR Q77609 - CRD L-3 (42-11) indication troubleshooting
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lQlP 263-1-S2 " Jet Pump Calibration" The inspectors concluded that I&C maintenance activities were satisfactorily
' accomplished by skilled maintenance personnel. The maintenance personnel
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appeared _ conscientious and knowledgeable of the work performed. However, concerns were identified during the observation of the following work:
NWR Q33056 issued for the PM of the RPIS power supply included a procedure QIP
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280-4, "RPIS Power Supply Preventive Maintenance and Adjustment," Revision 1 which states that " Disconnect the power supply (supplies) leads, as per Q1P 100-13." Procedure QIP 100-13. "I.M. Department Routine Maintenance and Troubleshooting Documentation Procedure," Revision 2, required that if a
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circuit wiring was disconnected for troubleshooting or calibration, all lifted leads should be documented on the lifted lead Documentation Sheet QlP 100-S14.
Contrary to the requirements of QlP 280-4, the Control Systems Technician
' performing the PM did_not have the forms 100-13, or QIP 100-S14, at the job site. This confirmed that the lifted leads had not been properly documented as required on Form QIP 100-S14. This could lead to compromising the 3 roper control rod. position indication after reconnecti.ng the leads. Althougl verification of alarms, indications and operations is accomplished through post maintenance functional testing, failure to follow administrative procedures QIP'280-4 and QIP 100-13 is considered an example of the identified weakness in procedure adherence at Quad Cities.
The licensee took immediate corrective actions, stopped the work and produced
.QIP 100-S14. "I.M. Department Lifted Lead Documentation Sheet" on the job site, although no discrepancy record was initiated. Corre iye actions by the licensee included training the I&C staff on proper use of 11fte3 lead documentation during maintenance and troubleshooting activities and procedural compliance.
The inspectors determined that the licensee's imediate corrective actions and followup-training were adequate to prevent recurrence.
Surveillance actions were observed during the performance of QlP 263-1-S2,
" Jet Pump Calibration," Revision 2.
All actions were carried out professionally and procedures were followed. However, prior to close out of the panels, the
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inspectors noted two leads protruding from the others, jumpered together, and taped.- When questioned about the reason for the tape and jumper, the licensee explained that this modification was for jumpering out jet pump number eight.
The licensee stated that this jet pump had been jumpered out since the startup of Unit 1 and attempts for the last 17 years to change the Technical Specification requirements stating that 20 jet pumps shall be operable prior to startup have been unsuccessful. NRR was aware of this problem.
3.3.3 Radiological Controls Maintenance work was observed in contaminated and radiation areas as were movements of tools / equipment to and from these areas; interactions of maintenance and other workers with radiological protection personnel were also observed.
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Cleanliness and housekeeping appeared generally good for outage conditions.
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Radiological controls apu posting and labeling were good.
-Through observations of work in progress and discussions with licensee personnel, the inspectors. determined that radiological controls were integrated'into the maintenance process as evidenced by:
.The "As low As Reasonably Achievable"-.(ALARA) staff appeared to'have
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the necessary^ size.. expertise, experience, and dedication to implement effective ALARA oversight of maintenance activities. The
- ALARA staff included a representative in the mechanical maintenance.
-department;.this representative had maintenance and radiation protection experience.. The ALARA staff had strong management support.
Members of the ALARA staff attended planning meetings, administered
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the shielding program,' conducted pre and post-job meetings, and l
collated and tracked the station's person-rem performance. The ALARA staff performed, or directed performance of, pre-job surveys;-the ALARA staff wrote the Radiation Work Permits (RWPs).
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i Proposed facility changes were reviewed by the ALARA staff,
The= licensee was developing job history files, and used these files and previous work packages to factor lessons learned into the t
planning process.
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Dose savings were achieved through extensive use of shielding,
mockups during pre-job training, and by making use of previous-lessons learned.
- Audits were performed by the onsite QA organization and the corporate
office.of the radiation protection program including ALARA; findings were properly addressed by station personnel, q
. Station dose goals were established and met, and work group doses I
were tracked.
Monitoring to support RWP issuance, RWP job coverage, and use of
dosimetry appeared to be good. On high dose or dose rate jobs, the RWPs were adequately developed through comunications between the affected departments, including planning; the RWP and/or the work order and procedure were adequately detailed to assure adequate job coverage, and enough advance notice was given to the radiation protection department so that adequate radiation protection technician support was available.
The inspectors noted that further improvements in the following areas were needed:
Work order packages, for work in radiologically significant areas,
did not always contain tool / equipment / staging lists / requirements;
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therefore, unnecessary dose could be received in such areas because
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. of inefficiency. ^A program existed to record tool / equipment,'used
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for a specific task, for later use when performing the same task.--
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recently completed work order packages, tool / equipment lists were
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- apparently not being generated for a significant percentage of work.
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orders (preventative.and corrective) completed.in radiologically significant areas.
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In. general; for jobs in radiation areas that were not on the' critical i
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path and would not result in-high total dose, the radiation i
protection. department was-not always given adequate prior notification before the job was to begin. As a result, overall ALARA pre-job planning may be rushed, and radiation protection technician support may not be available; consequently, unnecessary radiation dose may
be received and work may be inefficiently performed.
Cumulative-whole body dose for 1980 was 827 person-rem. The goal was 600 person-rem. The average cumulative whole body dose for 1986, 1987, and 1988
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was 416 person-rem'per reactor while the industry average was 565 person-rem.
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=The-whole body dose had exceeded the licensee's aggressive goals the last two years; however, the average cumulative whole body doses were less than the industry averages.
Reductions in personal doses,. personal contamination events, and the extent of contaminated areas over the past few years was evidence of management support for the-radiological control and ALARA programs. Enhancements such as more extensive planning, spaco management during major outages, and advanced / enhanced radworker training appear necessary to effect further reductions.
l 3.3.4 Maintenance Facilities, Material Control, and Control of Tools and Measuring Equipment
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-The inspectors reviewed the licensee's activities in the areas of facilities, equipment,'and material control to assess support given to the maintenance
_ process.~ Interviews were conducted with various maintenance management and
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-craft-personnel to determine the policies, goals, and objectives; and l
follow-up observations were performed to determine the extent to which the plant practices, procedures, equipment, and layout supported the maintenance
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L 3.3.4.1 Facilities The inspector was concerned that the remoteness cf the master electrician's
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office to the shop could pose some problems in coordination and communication.
The electric shop provided very little space to work on equipment or available storage.
The radioactive decontamination area for the shops did not have a roof. This
situation could contribute to the spread of contamination.
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Mechanical maintenance facilities were adequate. The foremen's offices were clocated close to the mechanical sho) and the tool room. The licensee procured several machine tools recently whici made the machine shop somewhat cramped,
>The licensee stated that the new facilities being built will accommodate the
- machine shop and:all the new tools.
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I&C maintenance facilitics were centrally located aroviding easy access to the.
plantiand auxiliary electrical equipment rooms. T1e shop was clean and well i
lit. 'However..the shop was crowded with instruments awaiting calibration or repair and spare instrument parts indicative of the need for a larger service
.and storage area. The foreman's office was located in the same general shop area'and.the Master Instrument Mechanics's office was in very close proximity
- to the. shop. All surveillance records, vendor manuals, and system print
. microfiche files were located within the shop area providing easy access and
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use. A program updating the manuals and microfiche was employed and used well, preventing.the inadvertent use of-outdated prints and manuals, j
3.3~4.2.-
Material, Equipment, and Tool Control
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The warehouse facility included good Level A and Level B storage spaces.
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Physical control of access to the warehouse facility was good, environmental
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controls were effective, cleanliness and housekeeping aspects were very good.
Policies and procedures were documented and implemented for procurement of parts.and' materials. Guidelines were established and effectively implemented to address lead time for procurement, specification for parts and materials, documentation requirements, testing,-inspections, acceptance records, and l
stock' quantities. Guidelines were also established to expedite emergency j
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. procurement through the Pool Inventory Management System-(PIMS). -Reorder
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points were set by the Maintenance Department but controlled by the
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warehouse.-
I A'" Physical Inventory List" was generated by computer and used by the inspectors to assess controls and identification of material. The Inventory List described the item, identification number, physical location, date last
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inventoried, and shelf life. Shelf' life controls were in effect as well as controls for consumable materials such as solvents, lubricants, gasket i
- materials, and welding rods. A separate storage facility was established for i
flammable material and other materials that required special handling.
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Guidelines and controls were established for the issuance and return, of
unused materials.
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The. inspectors reviewed the procurement process by selecting a few purchase orders (P0s) including 315694, 501959QC67, 502413QC14, and 502413XX419. The inspectors verified that the vendor was an approved source; reviewed the method utilized for acceptance of the procured item; and ascertained that the correct quality and technical requirements were in the Purchase Order. No problems were identified, except in the case of the purchase of HPCI booster pump
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impe11ers. Some comments on the procurement process and tool control follow:
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The license'e decided to replace the impellers of the HPCI Booster
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Pumps (in both units), as these pumps were experiencing (excessive-N
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vibration levels.. The original equipment manufacturer Borg-Warner j-pumps) recommended'to' change the impeller from the original bronze four-vane' design to stainless steel five-vane design to reduce the
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vibration.
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The originalLimpe11ers for these pumps were supplied pursuant to GE purchase specification 21A5759 (Rev. 5) which specified the seismic criteria'ap311 cable to the HPCI aumps. -However, the current Commonwealti Edison Company purciase order (No. 315694) (originally-issued on July 22.-1987, and reissued for the changed impeller on
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December 28, 1987) did not specify any seismic criteria, nor was a condition specified that the alternate pump parts (impeller and shaft) shall meet the original design criteria for these pumps.
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.The safety evaluation'made for the changes made on the impeller
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design did not address the seismic acceptability of the new impeller, due to its change.in material and weight. The licensee could not produce any documentation to prove that the pump (with the new impeller) would be operable in case of a seismic event as required by the original pump specification and the Master Equipment List (MEL).
Subsequently, on licensee's request, the vendor provided a letter on October 4, 1989, to the licensee that the HPCI pump with the new impeller meets the original seismic spectra.
The inspectors reviewed several other purchases of mechanical spare
' parts and determined that the procurement actions were adequate.
The licensee also stated that they were currently revising the procurement procedures and checklists for parts replacement to ensure the suitability of replacement parts for seismic, EQ, and other criteria.
The inspectors reviewed a printout of NWRs on hold for_ parts.
- Some electrical items on hold were reviewed for safety impact and
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importance to safety. A few items, such as parts for the
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24/48 VDC battery chargers, appeared to have safety significance and had been on order for an extended period of time. Licensee personnel stated that this was due to the unavailability of parts.
These NWRs did not have a high priority and the licensee's expediting was not effective in cases of low priority work.
The inspectors did not evaluate the licensee's tool and equipment control in detail. However, the ispectors noted that the mechanical tool room had adequate _ tools that were controlled properly. The licensee did not have a complete list of all the mechanical tools on hand. A program had been initiated to list all the tools available in the mechanical tool room. The inspectors determined that the tools at the plant were adequately controlled.
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t 3.3.4.3-Control and Calibration of Measuring and Test Equipment (M&TE)
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' Control of-M&TE-was good in that defective or " calibration due" instruments were stored-in a separate room, away-from those that were in calibration and acceptable.for use.
Procedures were well developed and were implemented for the issue, return, and recall of M&TE. The_ individual checking out an instrument; the work order, procedure, or location where used; date out and date returned were recorded for. permanent records. Control of M&TE issuance was considered good.
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A strength _noted by the inspectors was the use of detailed records of M&TE in that a procedure was in place requiring a trace back of test equipment that
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had failed its normal calibration cycle with Systems Operations Analysis
' Department (SOAD). Records history (WR's, surveillances, etc.) was reviewed
- and balanced against all test equipment on_which a failed M&TE was used to-reverify the operability of safety-related equipment. A root cause determination of the failure was attempted and previous calibration records through three cycles were reviewed.to detect an out of tolerance trend. A large percentage of the certified test equipment was sent off-site to SOAD for calibration.
The: mechanical M&TE such as micrometers, calipers, torque wrenches, test gages, etc. were stored and controlled properly. Quick calibration was facilitated-by-in situ calibration facilities. The inspectors verified several' pieces of mechanical M&TE, which were all found to have been calibrated and had calibration stickers.
The M&TE Laboratory utilized trained and experienced personnel, procedures for calibration, ranges, accuracies, and acceptance criteria-for-each instrument
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.and. scale as appropriate or required. Each piece of M&TE was identified with a unique identifier. The date calibrated and date due was identified on the instrument and'in the record files, the calibration process was recorded and documented,',the calibration was traceable to national standards, and the individuals organizations, and companies performing calibration were documented.
The licensee presented the' inspectors an overview of a new calibration system
. scheduled for completion in 1994. The following highlighted the new program:
Master Equipment Index maintained on computer data base.
L Calibrations scheduled on a detailed evaluation basis for BOP items.
Use of history records on safety-related and non-safety-related
equipment important to plant reliability for improved response to equipment found out of tolerance.
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Cross-reference employee information, M&TE equipment history, and o
work orders for tracking and reporting.
Trend M&TE and Permanent Plant Instrumentation using history files
created on instrument drift charts.
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-The inspectors < concluded that the use of this program had the potential to improve the calibration system and trending of M&TE and permanent plant
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instrumentation'.
The-licensee's activities and records.related to control, calibration, and management of M&TE met program requirements and commitments.
In general, the s
licensee's maintenance facilities, equipment storage, and material controls
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appeared to be-good.
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3.4 Review and Evaluation ~of Maintenance Accomplished
.3.4.1
' Backlog-Assessment and Evaluatio_n
-The: inspectors reviewed the amount of work accomplished as compared to the amount of work scheduled. Emphasis was placed on work that could affect the operability of safety-related equipment or equipment considered important to safety, which included some balance of plant components. Maintenance work backlogs were evaluated for cause and impact on safety.
3.4.1.1 Corrective Maintenance Backlog
~The majority of non-outage corrective maintenance NWRs were arioritized B2, which was defined in the Conduct of Maintenance (COM) as wor < that must be scheduled within five days. Priority B1 non-outage.NWRs, defined as work to be' scheduled within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, constituted approximately 10% of the backlog.
As a result of discussions with the licensee and review of HWRs, the inspectors determined that none of the backlogged NWRs affected plant
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. operability and did not need to be reclassifed to a higher priority.
-The backlog of both outage and non-outage NWRs was tracked by the maintenance department by use of a computerized system. Backlog information could be obtained from~the computer at any time. A tracking report was. issued monthly to management on the status of the backlogs. The current as well as previous month _'s backlogs.were listed so changes were readily apparent. The report also indicated the percentage of NWRs which were open for more than three months.
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Since June 1988, Quad Cities had reduced its non-outage backlog to well below the goal set by the licensee's corporate office.
The-inspectors determined that on September 27, 1989, the non-outage corrective maintenance (CM) backlog was 253 for mechanical maintenance (HM),
294 for electrical maintenance (EN), and 409 for instrumentation maintenance (IM). The.CM backlog was low and within the capabilities of current staff.
Based on the number of craftsmen and on average manhours per NWR completion,
-there was approximately 12 weeks of CM Lacklog.
3.4.1.2 Preventive Maintenance Backlog Preventive Maintenance (PM) NWRs were also tracked by a computerized system.
PMs were accomplished by non-scheduled NWRs and by scheduled PMs, which were mostly accomplished using procedures rather than work requests. The scheduled PMs were tracked by the General Surveillance Program.
Based on review of licensee records, the inspectors determined that as of September 27, 1989, the non-outage PM backlog was 463.
This backlog represented approximately 12 weeks work.
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- Aireview of the. outage and non-outage backlog-of-PM NWRs did not identify any.
that could adversely affect operability.-
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3.4.2
- Review and Evaluation of Completed Maintenance
. The inspectors selected-some_ completed maintenance tasks on the equipment and systems identified in Section 3.1.2 of this report for further review. The
. purpose of this review was to determine'if specified electrical, mechanical, and I&C maintenance on.those seleted systems / components was accomplished as required. This-review included:
Application of risk-based' priority to the performance and intent of maintenance.
Evaluation ~to determine the extent that Reliability Centered Maintenance (RCM)
was: factored into the established maintenance process.
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Evaluation of the extent that vendor manual recommendations, NRC Bulletins,
- NRC Notices, Service.Information Letter (SILs), Significant Operating Experience' Reports (SOERs), and other outside source information was utilized.
Evaluation of the. extent that maintenance histories, Nuclear Plant Reliability Data System (NPRDS) information, LERs, negative trends, rework, extended time-for outage, frequency of maintenance', and results of diagnostic examinations
- was analyzed-for trends and root causes for modification of the PM process to preclude recurrence of equipment or component failures.
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Evaluation of completed cms and PMs for use of qualified personnel, proper
- prioritization, Quality Control (QC) involvement, quality of documentation for machinery history, description of problems and resolutions, and post maintenance testing.
Evaluation of work procedures for inclusion of QC hold points, acceptance criteria, user friendliness, and general conformance to NUREG/CR-1369.
~ Backlogs for selected components.
- 3.4.2.1 Past Electrical liaintenance
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The: inspectors reviewed 26 completed electrical NWRs to verify that adequate e-work instructions were provided, work was completed as described and that appropriate reviews and approvals were obtained as required. This included both safety-related and non-safety-related NWRs. Work instructions appeared to be adequate and work was completed as described.
In most cases,
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appropriate reviews and approvals were obtained; however, in two cases the
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authorization from operations to start work was not signed on the NWRs.
- Both cases involved non-safety-related work. Procedures permitted non-safety-related maintenance which did not affect operability of equipment to be performed without. plant operations approval. This appeared to be a weakness, since errors could be made that would affect control room indicators such as annunciators and the operators would not be aware that work was being performed on the equipment.
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The licensee had-implemented a program for utilizing the Electrical-
Load Monitoring System (ELMS) to control and track all electrical load additions, deletions, or transfers on the DC and AC' emergency power supplies. As'a check, the inspectors took nameplate data from the RHR pumps 1A and 1B motors and compared the information with the AC. emergency diesel generator ELMS logbook. The inspectors compared the nameplate voltage, full load amps, horsepower rating and locked rotor current. -The ELMS logbook had correctly reflected the nameplate:value. The inspectors' review of the ELMS logbook for the Unit 1 and Unit 2,125V de batteries indicated that the load profiles for the batteries were current and accurate. The licensee's program-for tracking ~ electrical load' transfers was a strength.
3.4.2.2 Past Hechanical Maintenance The inspectors reviewed 24 completed mechanical work packages. The inspectors
- noted that in most cases, the work packages indicated that prior approvals for the~ work were obtained, QC hold points were noted, necessary procedures
'were included and the calibration status of the M&TE was noted. The maintenance problems and resolutions.were documented.
The inspectors noted
-some deficiencies in the documentation of root causes and the post maintenance
tests (PMT) performed.
In some cases the checklists used for PMTs were not included with the work packages.
The inspectors determined that although the mechanical maintenance philosophy
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did not include the concept of RCH in the past, the licensee had initiated a program based on RCM. The licensee selected 28 systems in the plant for a-detailed evaluation of the maintenance needs based on RCH and equipment history.
..The inspectors noted that the licensee used an extensive vibration analysis program for predicting the reliability of the rotating equipment at the station.
The licensee had an extensive MOV diagnostic testing program, using the ' VOTES'
system. The inspectors evaluated the extent that vendor recommendations, NRC Bulletins, NRC Notices, SOERs, General Electric SIls, and other outside source-information was utilized in the mechanical maintenance of the systems selected.
The. inspectors reviewed the following Quad Cities procedures used for maintenance activities for completeness, necessary approvals, adequacy of work instructions, user friendliness, inclusion of QC hold points, and acceptance criteria, when applicable:
QAP 500-15, " Conduct of Maintenance," Revision 3 QAP 1500-2, " Work Request Procedure for Station Maintenance," Revision 36 QEMMP 1525-1, "Limitorque Type SMB Valve Operator Removal," Revision 2
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QEMMP 1525-4, "Limitorque Type SMB Installation Procedure," Revision 2
.QMSS 6600-1-54, " Diesel Inspection - Refueling Outage Checklist," Revision 2
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QMP 1500-34, "In-process Maintenance Cleanliness," Revision 3 LQMP 3900-1, " Removal of Worthington Model 20 QL-26 Service Water Pump,"
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QMP 3900-2, "Insta11ation'of Worthington Model 20 QL-26 Service Water Pump,"
Revision:1-u q
QOS.2300-1, "HPCI Monthly and Quarterly Test," Revision 17
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QOS,2300-7, High Pressure Coolant Injection System Turbine Overspeed Test,"
Revision 3-i The inspectors determined that the procedures reviewed were generally
- adequate. However. the inspectors noted that some Quad Cities procedures did not include adequate-acceptance criteria as noted below:
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Quad _ Cities procedure No. QMMS 6600-1-S4 " Diesel Inspection - Refueling
Outage Checklist," Revision 2, (issued in March 1988) was used for
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verification of the overspeed trip tests conducted on Unit 1/2 diesel i
- on May-7, 1988, and Unit 2 diesel on June 9, 1988. This procedure included a QA hold point for checking the setting of the overspeed trip... However,_the acceptance criteria _for the trip setting or a-space for documenting the actual as-tripped overspeed setting were not included in these checklists.
The Emergency Diesel Generator vendor manual specified a setting-of 990 to 1005 RPM for the overspeed trip setting..The previous issue of this checklist, QMS 200-S6'(Rev. 6, issued in April 1985) also did not contain the acceptance criteria for the diesel overspeed trip setting, but
provided a space for filling in the as-found overspeed trip setting.
- On inquiry, the licensee was unable to provide the as-found overspeed trip settings for the two overspeed trip tests conducted on diesel generators 1/2 and 2.
The failure to provide adequate acceptance i
criteria in the work instructions for the testing of safety-related
equipment is considered to be an example of a violation of 10 CFR 50, i
Appendix B, Criterion V, (254/89017-01B; 265/89017-01B).
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At the end of the inspection, the licensee revised this procedure.
This_ revised procedure included the acceptance criteria of 990-1005
rpm and a space for recording the as-found trip setting.
Quad Cities procedure No. QOS 2300-7, "High Pressure Coolant
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Injection (HPCI) System Turbine overspeed test", Revision 3, issued in March 1987 did not include the acceptance criteria for the HPCI turbine overspeed trip tests. The vendor for the HPCI turbine (GE)
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specified an overspeed trip setting of 4900-5100 rpm. The inspectors noted that the actual overspeed trip settings for tests conducted arior to 1986 could not be located and hence could not be verified w1 ether they were within the acceptable limits. Failure to arovide adequate acceptance criteria in the test procedure for the iPCI turbine is considered to be an example of a violation of 10 CFR 50, Appendix B, Criterion V.
(254/89017-01C; 265/89017-01C).
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Procedure QOS 2300-7, Revision 3, also did not provide a space for
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u recording the as-found set speed for the overspeed trip test and for the signatures of the persons conducting the test. On inquiry from
the inspectors,-the licensee provided'the overspeed trip settings (actual) obtained from the operator logs, as no specific checklists'
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F were used for these tests.
Unit 1 HPCI turbine tripped on overspeed
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-tests at 4951 rpm on December 29,~1987, and,at 4896. rpm January'5,.
.1986. --The.overspeed settings of Unit-1 prior to 1986 could not be produced.
Similarly, the Unit.2 HPCI turbine tripped on an overspeed trip test at 4999 rpm on June 25, 1988. The results of previous overspeed trip: tests of Unit 2 also could not-be produced.
The inspectors-determined that the lack of overspeed trip test data could be traced to the inadequate procedure-QOS 2300-7, which did not 3rovide the space for documenting the overspeed trip settings for the iPCI turbines.
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Failure _to provide adequate spaces for documenting the actual overspeed trip setting and for signatures in the test procedure i
for.the HPCI turbine is considered to be an example of a violation of
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W CFR 50, Appendix B, Criterion V.
(254/89017-OlD; 265/89017-010)
The inspectors evaluated the extent that vendor _ recommendations, NRC Bulletins,
-NRC Notices, and vendor information bulletins or letters were utilized in the maintenance of the components selected, including HPCI and RCIC turbines.
Vendor Manuals reviewed were as follows:
VETI-Manual No.'C 0030A, "RHR Service Water Pumps, Ingersoll Rand Pumps,"
Revision 3 l
1VETI Manual No. C 0040B, "HPCI Pump - Byron Jackson Pumps," Revision 1
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L VETI Manual No. C0107C, "HPCI Turbine " Revision 2 VETI Manual No. C 01862C, "RCIC Turbine," Revision 0
Vendor Manual No. 00894, " Service Water Pumps," Revision 11/77-The inspectors verified the extent to which vendor recommendations were incorporated into the licensee's PM program; the following discrepancies were noted:
Vendor Manual VETI No. C 0107C, "HPCI Turbines," Revision 2,
included recommendations that:
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"a) The overspeed governor and tripping mechanism should be tested once every 3 months, as conditions permit, by means of oil suppressed trip valve"
"b) At least once a year, test the emergency governor by overspeeding the turbine"
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The' licensee has been performing the HPCI Turbine overspeed trip test once every refueling outage. However, the recommended quarterly mechanical trip test was never included in the PM program. The -
i failure'to include this'important vendor recommendation for testing safety-related equipment and failure to develop a test procedure
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in'about 17 years of operation is considered to be a weakness.
However, the inspectors noted that this lack of PM on the HPCI-
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turbine did not affect the operability of the HPCI system over these years-.
Vendor Manual VETI No. C 0182C, "RCIC Turbines," Revision 0, l
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-included recommendations for its GIMPEL Trip and throttle valve that:
"b. The valve should be exercised at least once/ week by' turning the handwheel in the closing direction."
"c. The valve be inspected and lubricated periodically."
- The licensee had not periodically tested these valves on both the units and did not include these vendor recommendations in their PM
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program; nor did the licensee develop any test or inspection proceduire for implementing these vendor recommendations for a period of over 17 years.
.The-licensee submitted an LER No.86-023 during 1986 as the RCIC system
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became inoperable due to tripping of the RCIC turbine several times on overspeed. The cause for-these overspeed trips was stated to be the trip linkage being out of adjustment.
In spite of this event, the licensee did not incorporate the vendor recommendations in their PM
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Program. Failure to provide adequate and timely corrective action on a' problem identified in 1986, in incorporating the vendor recommenda-tion in the licensee's PM program and in not periodically inspecting and testing the RCIC turbine trip valves is considered to be a violation of 10 CFR 50, Appendix B, Criterion XVI (254/89017-02B; 265/89017-02B).
3.4.2.3 Past Instrument and Control Maintenance The inspectors determined that the I&C maintenance philosophy did include the concept of RCM.
I&C maintenance was primarily based on vendor manuals and previous maintenance history.
The inspectors evaluated the extent that vendor recommendations, NRC Bulletins and Notices, SILs,-and other outside source information were utilized in I&C maintenance for the components selected including Rosemount, Inc. pressure transmitters. The inspectors reviewed the following documents during the evaluation:
10 CFR 21 report from Rosemount, Inc., dated February 9, 1989 I
IEN 89-42, " Failure of Rosemount Models 1153 and 1154 Transmitters" L
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Q1P_150-S28. "Rosemount 1153 Transmitter Maintenance and Surveillance Data Sheet," Revision 5 Vendor Manual 4302,"Model 1153 Series B Alphaline Pressure Transmitters for
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. Nuclear Service," Revision E The-10 CFR 21 report by Rosemount, Inc. details degraded response time over full range, rendering an increased overall response time. The licensee had
. reviewed the problems associated with these models of transmitters and determined that instrument drift charts already in effect were adequate to L'
identify any potential problems. All necessary actions had been or are being carried out with these transmitters.
The inspectors reviewed the component failure history for the I&C components and systems selected to determine whether methods had been established and implemented for detecting repetitive failures and adverse quality trends, and whether appropriate corrective action had been taken to address adverse trends. The inspectors also utilized NPRDS and LERs in the review to ascertain the effectiveness of the licensee's trend analysis and root cause analysis.
As a result of this review, the inspectors identified concerns with the licensee's root cause analysis and trending which are discussed in detail later in this report.
The inspectors-reviewed completed cms and PMs for use of qualified personnel, 3 roper prioritization, QC involvement, quality of documentation for work listory and understanding of problems and post maintenance testing. The
' inspectors identified the.following concerns:
Post Maintenance Testing was insufficiently specified, poorly documented and not performed routinely following maintenance activities that could affect equipment reliability. A program did not exist to compare post maintenance equipment parameters with those attained during previous tests to ensure that the equipment had not degraded significantly.
QC hold points were only included in specially prepared corrective
maintenance procedures. QC hold points in station standing procedures were included as a last step after the work had been accomplished, rather than during the maintenance action.
Thirty-seven completed I&C corrective maintenance NWRs were reviewed to ascertain the plant's determination and effectiveness of rework to failed corrective maintenance. The Quad Cities " Rework" program was in accordance with Chapter 16 of the " Conduct of Maintenance".
Based on the inspector's review, it did not appear that Quad Cities Rework program was effectively used to track, trend, or otherwise perform root cause analysis of failed I&C equipment. A management approach to effectively implement the rework program is necessary to ensure reliability of safety-related and non-safety-related components and systems.
The inspectors reviewed the following procedures for inclusion of QC hold points, acceptance criteria, and user friendliness:
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QIS'27-1, "HPCI Turbine Area-High Temperature Isolation Calibration,"
Revision 8
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'i iQIP 150-4, " United Electric Switch EQ Maintenance and Surveillance Procedure",
Revision 1-QIP 150-7, "ITT Barton Model 764 EQ Maintenance and Surveillance Procedure",
Revision 2 QIP 150-11. "Rosemount 353C1 Conduit Seal EQ Maintenance and Surveillance Procedure", Revision 1 QIP_150-S8, ' United Electric Temperature Switch Maintenance and Surveillance Dt.ta Sheet". Revision 2 QIP1150-S28, "Rosemount 1153 Transmitter Maintenance and Surveillance Data Sheet" Revision 5 QIP 150-532, "Rosemo'nt 353C1 Conduit Seal Maintenance and Surveillance Data u
Sheet", Revision 3 The procedures were detailed, contained vendor recommendations, and acceptance criteria. However, only one of the I&C procedures reviewed contained a QC witness point, which was at the end of the procedure. Management attention to adequate QC coverage is necessary to assure independent verification of EQ
'and safety-related maintenance activities.
The inspectors reviewed the current maintenance' backlog for the specified I&C components to determine if maintenance had been accomplished. Specifically.
the inspectors assessed the backlog of open NWRs for HPCI instrumentation. The inspectors determined that maintenance was adequately accomplished and there was no backlog that could affect the operability of the systems reviewed.
Based on the review of completed cms, backlog, and work history of the selected comaonents, maintenance procedures, and the licensee's actions on documents
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suc1 as NRC Bulletins and Notices,-the inspectors concluded that past performed
.I&C maintenance had been accomplished in a satisfactory manner.
3.4.2.4 Post Maintenance Testing l
The inspectors reviewed 87 completed NWRs and noted that post maintenance testing (PMT) did not appear to be adequately documented.
In most cases, some type of PMT was required by the NWR but the only evidence that the testing had been completed was signed block 24 on Form QAP 1500-S1 which was entitled
" Test Complete." On.two of the NWRs, specific references were made to test records which were not included in the NWR packages. During discussions on the matter, licensee personnel stated that a pilot procedure for PMT was issued on September 4, 1989. The inspector reviewed flaintenance Department Memorandum No. 38, which issued the pilot procedure entitled, " Post Maintenance Test / Verification Program" for use and noted that it provided substantial improvements in the designating and recording of PMT. This procedure provided
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for a computerized matrix for use in determining the specific Pt1T required for designated repairs. This would eliminate the need to determine required tests each time repetitive type repairs were made. This matrix was not complete but the inspectors were told that new areas would be developed as specific repairs were encountered. The procedure was not expected to be completely developed and implemented until 1992,
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The inspectors-reviewed the work requests,where PHTs were specified and conducted.
r-The inspectors noted that in some earlier cases, the manufacturer's acceptance criteria were not-included in the work packages. However, review of recent
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work packages reflected-the inclusion of acceptance criteria.
3.4.2.5 Vendor Manual. Control r
The vendor _-manuals at Quad Cities had not been adequately controlled in the past. As a response to NRC Generic Letter 83-28, issued following the Salem
~ATWS incident, regarding the vendor manual control, the licensee participated as a member of the Nuclear Utility Task-Action Committee (NUTAC) in developing i
a connon plan for the vendor information control. The licensee initiated a VETIP program and assigned a VETIP coordinator. The implementation of this s
program appeared to be slow and weak. The licensee stated that work on all
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safety-related vendor manuals would be completed by mid 1990. The work on
.non-safty-related vendor manuals would not be completed until the end of 1991.
As indicated in other sections of this report, inadquate control of vendor manuals, and inadequate implementation of the vendor recommendations could result in unreliability of some vital equipment.
3.4.3 Application of Industry Initiatives 3.4.3.1 NPRDS
The inspectors interviewed the NPRDS Coordinator to determine the extent of HPRDS reporting.- From these interviews, it appeared that NPRDS reporting was being performed well. Quad Cities had been reporting to NPRDS since 1983.
Reporting was done on a site (both ur.its) basis. The present NPRDS coordinator had been in this posit. ion at Quad Ci n es for over two years, and spent over 70 percent of-her-time on NPRDS reporting or searching. A procedure was in place
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(QTP 500-13, Revision 1 September 1988) for NPRDS work. All work requests were reviewed by the NPRDS coordinator for reportability. Only a small fraction of these work requests resulted in NPRDS reports. The final determination of u
reportability rested with the NPRDS coordinator alone. There did not appear to l
be.any QA audits of the NPRDS coordinator's work.
l Incipient failures (which could be reported voluntarily under NPRDS guidance)
were'not reported by Quad Cities. Although Quad Cities appeared to be
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reporting failures as required, they were not reporting as many events in the
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" gray areas" compared to another Commonwealth plant, Byron. For instance, at Quad Cities, if a problem was found at one unit, the other unit was checked for the same failure.
If a problem with a component was found at the second unit, l
but the component could still perform its function, it was fixed or replaced, L
but was not reported to NPRDS because it was considered as a preventive maintenance.
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As_a partial check for NPRDS reporting at Quad Cities, 57 LERs for which the box for " reportable:to NPRDS" was marked "yes" were checked to see if an NPRDS report was submitted.
In the vast majority of cases, a report was submitted.
In a few cases, the system engineers who wrote the LERs checked the box for non-reportable systems (RWCU, for instance) or nonreportable components within reportable systems.
In one case, an NPRDS report was,not submitted that should
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have been (Unit 2 LER 88-005).
'As a second check on NPRDS reporting, feedwater system work requests for 1988 were reviewed for NPRDS reporting. Work requests did not include sufficient information to. determine reportability. Part of the process of determining reportability at' Quad Cities included discussions between the NPRDS coordinator
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and the work analysts or foremen to determine if_the component was still able to perform its function. This dicussion was not recorded on the work request.
'It appeared that reporting was generally being done as required. There was some. gray area (especially in what is wear out, failure, or preventive maintenance)
that involved some judgement, but there did not appear to be any overall problem.
One minor discrepancy found was that the number of engineering records for the
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feedwater system was not the same for both units, as would be expected.
Some
' engineering records for circuit breakers entered for Unit 1 have not yet been entered for Unit 2.
The licensee informed that these would be entered as part
- of an ongoing update.
-Quad Cities is making good use of NPRDS information for plant specific issues.
All modifications required an NPRDS search, and engineering records must be updated if components were changed.
In addition, NPRDS searches were required for_all deviation reports with components failures, and for all problem reports to corporate headquarters. The inspectors noted that NPRDS had been searched in several LERs examined, and the results of the search and its relation to the
_LER were discussed at the end of the LER text. The maintenance department also
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asked for NPRDS searches for work packages where they felt it necessary. The licensee stated that system engineers made use of NPRDS reports for trending; however, the system engineers interviewed did not appear to use NPRDS extensively.
Quad Cities is also actively using the Component Failure Analysis Report (CFAR),
an NPRDS report that highlighted component failures for a plant if that plant's failure rate was significantly higher than the industry average for that component.
Problem areas that made use of CFAR at Quad Cities were contactors in motor control centers and safety system relays.
3.4.3.2 Performance Measures / Maintenance Trending Root Cause Analysis Weaknesses exist in root cause analysis of problems at Quad Cities. Work analysts pre)ared work requests for each item of a maintenance job. The WR included worc to be done, required tools, post-maintenance tests and drawings.
'The completed work requests contained some relevant history, but the root cause would often get a superficial treatment.
System engineers were usually not involved in root cause determination or verification as they received only a copy of the initial work requests but not the completed work package.
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.A review of the'NPRDS' report narratives indicated that there was very little i
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b-meaningful root cause~ analysis, with most failures categorized as wear out or having: unknown failure mechanisms.
'The licensee-initiated' a~ pilot program called Problem Analysis and data Systems (PADS) to improve the root cuase analysis and to document root causes for
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- failures'in.12 systems. Anyone in the plant could initiate a PADS analysis, but the principal initiators were the work analysts. System engineers have the-primary responsibility for closing out PADS reports. Due to the limited scope of this program, it would be some time before the root cause analysis program is fully, implemented at Quad Cities, f
3.4.3.3~
LER ' Program Total LERs at Quad-Cities came down considerably in 1989. Equipment failures were the highest root cause for these events.
Over the years, most LERs were submitted
~due to the' actuation of an Engineered Safety Feature. Total personnel errors also came down in 1989. There were no personnel errors in all the maintenance
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-groups so far-in'1989.
There were only 17 LERs (for both units) in 1989 against a licensee's goal:
of_35. -.The goals for LERs.are inappropriate because they could be misinterpreted and could present an appearance that LER reporting is to be discouraged.
3.4.3.4 CFAR Program The licensee initiated the Component Failure Analysis Report-(CFAR) program to compare the failure rate at Quad Cities of the selected 328 components with r
'all the other units in the NPRDS data base..While the data base was updated
.once a week, the CFAR report was issued quarterly. Significant failures flagged by this -]rogram were radiation monitor transmitters, pumps, medium voltagecircuitbreakers,andCRDHCV'sincaseofUnit1;andvalveoperators,
. instrument bistables, medium voltage circuit breakers, radiation n.onitor
' transmitters, and pumps in case of Unit 2.
Based on these reports, action plans were developed for testing of these components.
3.4.3.5 Use of NRC Bulletins and Notices, and other Vendor Information Letters The inspectors reviewed the licensee's practices in reviewing and responding to the NRC Bulletins and Notices, Service Information Letters (Sits), Significant Operating Experience Reports (SOERs), and other industry information notices.
The' licensee's Regulatory Assurance group handled all the NRC Bulletins / Notices and other industry inputs. A computerized tracking system was developed to a
keep:a complete history on each document. Each document was initially reviewed by the Regulatory Assurance Group and sent to appropriate station personnel for review, response, and followup actions. These were generally addressed well within the stipulated time limits, except in the case of one SIL received from GE.
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.The inspector selected a sample of six GE SILs to verify the licensee
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actions on vendor recommendation letters. Generally, the SILs were
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responded to well. SIL No. 477 received in February 1989 was sent to 4aintenance and later to Tech Staff, whose response was due on i
September 11,.1989, but was not received until the inspection date of
' October-5,11989. SIL No; 477 was a priority 1 report pertaining to-Main-Steam Isolation Valve closure. As the air line.got disconnected and the MSIVs did not-close on spring pressure alone at a BWR plant, GE issued the SIL to all BWR Owners, to perform some tests and to modify the FSAR, if.necessary.
GE stated in a letter dated February 5, 1973, to Quad Cities Station that for Priority 1 SIL reports, GE needed a feedback within 30 days.
GE also recomended implementation of changes for Priority 1 SILs within a 3 month period. However, the Quad Cities Station did not provide any feedback to GE on SIL No. 477, nor was it implemented even after a period of.seven months. The licensee was still in the process of reviewing the SIL. The. inspectors noted, however, that the licensee, in general, was responding to GE priority 1 SILs in.
time.
3.5 Maintenance Work Control The inspectors reviewed several maintenance activities to evaluate the effectiveness of the maintenance work control process to assure that plant safety, operability, and reliability ware maintained. Areas evaluated were control of maintenance work orders, equipment maintenance records, job planning,.prioritization and scheduling of work, control of backlog, procedures,
. post maintenance testing, completed documentation, and review of work in progress.- Preparation, prioritization, scheduling, implementation, and post maintenance review of WRs was described in Procedure QAP 1500-2, " Work Request Procedures for Station Maintenance," Revision 35.
Quad Cities Memo No. 53, " Standardization of Work Packages," provided the guidelines to the work analysts.for preparation of work packages. A work package standard matrix was also provided to help standardize work packages.
The work planning group at Quad Cities consisted of a supervisor and 8 work planners, who included persons from Rad Protection, QC, mechanical, electrical, a Rcactor Operator, and a former shift engineer. The work analysts. attended the plan of the day meetings, parts meetings, and were involved in planning for all maintenance jobs.
The inspectors reviewed the method used by the licensee to schedule and prioritize maintenance work. The inspectors discussed the matter with work
. scheduling personnel and reviewed the work scheduling process. Work Requests were routed to Operations who prioritized the work. Scheduling personnel used work schedules that depicted equipment " windows of opportunity" and personnel availability charts that indicated the availability of all disciplines of maintenance personnel and health physicists. Replacement parts availabilty was verified and the work schedules were adjusted as necessary.
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i During review of procedures and completed work requests,-the inspectors noted
adequate QC coverage.
However,'during the: inspection of electrical and I&C jobs in progress, QC~ involvement was inadequate, even though some jobs were
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significant.
The inspectors' reviewed the' licensee's Total Job Management (TJM), a computerized
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maintenance history program, which was utilized to identify adverse trends in equpment performance. The inspectors determined that this program was an' asset to improve the plant' maintenance. However, as the detailed failure modes were not entered in this system, the failure analysis could not be performed effectively.
-Quad Cities Station had a procedure for rework (previously issued as Memo
~No. 46'. dated March 11, 1987). Rework was also covered in Chapter 16-of the
" Conduct of Maintenance" (COM). The licensee's current memo No. 55 includes rework.. The maintenance department maintained a rework log. The rework
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control at Quad Cities appeared to be satisfactory. The inspectors noted that the rework was not excessive.
3.6'
Engineering Support of Maintenance The inspectors evaluated the extent to which engineering principles and evaluations were integrated irto the maintenance process. This was
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accomplished by review of maintenance work orders, activities associated with failure analysis, and other maintenance activities to evaluate the effect of engineering-support.. Areas reviewed were engineering support to PM, material qualifications, compliance with codes and regulations, system engineering concepts, industrial initiatives, and post-maintenance testing.
3.6.1 Engineering Support Engineering staff at the-Quad Cities plant includes a technical staff supervisor, seven group leaders, three assistant technical staff supervisors, and 42 engineers. An additional 14 contractor personnel were also utilized in the Tech Staff area. The staff appears to be adequate to meet the station engineering needs, including the assistance to maintenance.
The' system engineer concept had been introduced at Quad Cities Station about 1 1/2 years ago. Several system engineers were relatively new and did not possess any substantial nuclear power plant and systems experience to be effective as " System Engineers".
A Station Procedure QTP 010-5, " Duties and Responsibilities of System
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Engineers," Revision 2, was issued in July 1988. This procedure clearly defined the educational (a degree in engineering) and other requirements for a system engineer. This procedure also specified the various duties of the system engineers as discussed below:
The procedure required that each system engineer maintain a system notebook. The inspectors noted that such notebooks were maintained but the information contained was not complete in several cases.
The books were expected to be completed by early 1990.
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-The procedure. stated that the number of systems. assigned to any one
. person would be limited to 4 to 6 systems, depending on the
. experience.of the individual. However.-the A.C. systems engineer
'had 22 systemz assigned to'him.
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The system engineers did not review vendor manuals for verification i
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of inspection and PM requirements.-
The system: engineers _did not perform any failure analysis or trending i
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of equipment failures in.their assigned systems. The system engineers got a copy of the initial maintenance work request, but did not get._the completed work request. Unless the system engineer-specifically requested a completed work request or monitored the TJM,
-he did'not get-the information on the components failed or the actual
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. maintenance performed on the equipment in the systems assigned to
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-The procedure stated that the system engineers should review results
'of the vibrational analysis program.. However, the system engineerr, j-did not receive the vibration data, unless it exceeded alert or etion limits.
As.specified in the procedure, the system engineers were being given formal training in.the system design basis, FShR, and Technical Specification requirements and system interfaces.
Based on the inspectors' review, the program appears to be conceptually adequate, however, management attention needs to be strengthened to ensure
' implementation.
-The engineering support to the maintenance organization appeared to be weak
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in some areas. A few examples were:
-A safety review made for the impeller change on the HPCI Booster
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Pump did not include seismic evaluation, even though the original equipment was designed for specific seismic criteria.
Several as-built drawings in the communications center were illegible, even though several approval signatures were found on these updated (hand corrected to include up-to-date ECNs/DCRs/DCNs) drawings used for reference by the operations and other station personnel. After the inspector's concern, the licensee issued a change to procedure QDM-13, requiring a check for legibility and a biannual audit by the Tech Staff supervisor.
Engineering support in the area of procedure reviews for adequacy of
acceptance criteria appeared to be weak, as evidenced by the findings on the overspeed trip tests on diesel and HPCI turbines. Even though station procedures were prepared by various groups, the Technical Staff had the responsibility of reviewing the procedures.
The licensee's program to review and control station procedures appeared to be adequate. The licensee initiated a program recently to review and update all the station procedures.
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3.6.2 Technical Support Component trending was provided by Quad Cities' TJM system.
Station personnel
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Excessive component failures (over 2 in a 12 month 3eriod) were forwarded to
the PADS Coordinator for evaluation, snd to the Tecinical Staff, if further analysis was required.
The PADS had been developed by the licensee to document failure analysis. The
_ program was.in its initial stages and would take some time before it could be
a effective. The licensee was in the process of issuing a QCAP arocedure on i
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" Root Cause Investigation Program". The inspectors reviewed tais program and
concluded that_if implemented properly, it would be a good tool for the root I
cause analysis and corrective actions.
l Trending programs were uncoordinated. TJM, NPRDS, PADS, CFAR programs did not-
appear to be well coordinated in projecting trends.
I 3.7 Maintenance and Support Personnel Control The inspectors did not review the licensee's staffing cor. trol and needs in detail. However, based on the observations of maintenance work activities and
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discussions with plant personnel, it appeared that Quad Cities Station had adequate staff in the maintenance and supporting areas. The station had a i
large contingent of contractor personnel at the site'for the outage work.
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The plant personnel and management-interviewed appeared to be knowledgeable.
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The inspectors did not evaluate in detail the-various contractor groups working
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at the site for the outage. The licensee indicated that the,:ontractor personnel were used mostly on non-safety-related jobs and were being supervised by the ENC group of CECO. Some contractors were using their own procedures with their own QA/QC controls, which were approved by the licensee. As mentioned in the
previous ~ sections of this report, some problems were noticed in the performance of work by contractor personnel at Quad Cities.
The inspectors reviewed the licensee's training program, which was good. The
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training records of selected maintenance personnel indicated that they
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received site specific security and radiological training. Quad Cities maintenance training program was accredited by INP0 in January 1987.
The inspectors reviewed the licensee's maintenance training facilities, which included several mockups. The training facilities appeared to be adequate.
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3.8 Review of Licensee's Assessment of Maintenance The inspectors briefly evaluated the licensee's quality verification process in the maintenance-area by the review of QA audit reports, surveillance reports, corrective action documents, the maintenance self-assessment, and Safety l
System Functional Inspection (SSFI) Reports. The documents were reviewed to assess technical adequacy, root cause analysis, timeliness of corrective action, and justification for closecut of corrective action documents.
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3.8.1l Review of-QA~ Audits and Surveillances-
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2Thefinspec'torsreviewedthelicensee's12QAauditsand-10-QAsurveillancesof i
, maintenance activities conducted during 1988 and 1989. Some of these audits
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were' product audits covering specific aspects of maintenance-such as lifted leads and; jumper controls, and electrical modifications. One audit was on the PN program._.Only one audit (QAA-04-89-27) conducted in July-August 1989 was on
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the entire maintenance program. There were no findings.(non-conformances) as
- a result;of this audit. The observations noted~as'a result of this audit'
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- included problems such as. cleanliness, vendor manual classification, completion of EQ blocks on NWRs,'etc. 'The findings indicated that this maintenance audit
was'not performance based and no significant hardware problems were identified.
The licensee's QA' Group-also performed 256 surveillances during 1988 and 183
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surveillances so far in 1989. in the areas reviewed. These surveillances appeared to be well conducted and effective. The-licensee classified their QA--
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. findings in accordance with 10 CFR 50, Appendix B criteria and trended them.
An apparent trend of weakness was noted in the implementation of Criterion V, Instructions, Procedures, and Drawings. The QA findings were tracked by
. computer..A quarterly printout described the problem, root cause code,
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. auditor's response and current status. The followup of corrective actions
'to QA findings appeared to be adequate.
3.8.2-Licensee's-Self Assessment and SSFI's
13. 8. 2.1' ~ Self Assessment The' inspectors reviewed the report of the licensee's self assessment of
' maintenance, conducted in April 1989. The Assessment Team consisted'of personnel from CECO's Production Services Department. The weaknesses identified'by the team were in the areas of work request packages, inadequate procedure adherence, and feedback.
The current maintenance team inspection found similar weaknesses in the Quad Cities maintenance implementation in the areas of work request packages for j
non-safety related work, and inadequate procedure adherence. This was an indication of inadequate corrective actions to the licensee's self assessment i
inspections.
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~This maintenance self-assessment program was considered generally effective but.the licensee's corrective actions appeared to be lagging.
3.8.2.2 Safety Syst'em Functional Inspections (SSFI)
- The inspectors reviewed the reports of two licensee-initiated SSFIs to ascertain whether the SSFIs included verification of maintenance and whether any maintenance problems were found and dealt with appropriately. One SSFI was on Unit 2;High Pressure Injection System (HPCI) conducted in May 1987. A supplemental report was issued in December 1987 to cover all aspects of an SSFI. Five concerns and two open items were issued as a result of this inspection.
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The concerns were in the areas of:
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Ability to retrieve startup data for HPCI system
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Capability of HPCI system to cold start in le:e than 25 seconds i
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Artificial modifications of environment around temperature
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Discrepancies between FSAR and Fast Start Surveillance (45 seconds
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vs. 25 seconds)
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Spurious isolation problems The open items addressed steam side packing leaks and frequent MOV problems.
The inspection report ircluded curret status of the corrective actions taken to close the concerns. All concerns were closed except concern No. 5, which involved a temperature switch problem; this concern remained open as of March 9, 1989. A modification to correct this problem was included for the next refuel outage of Unit 2.
From a review of the above SSFI report, it was apparent that the problems identified by the current Maintenance Team Inspection, i.e., no quarterly testing of HPCI turbine overspeed trip linkage (as recomended by the vendor)
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and no acceptance criteria for the overspeed trip settings in the test procedure were not identified by the SSFl.
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The second SSF1 was performed by the licensee on the i/2 (comon) Emergency Diesel Generator during February-May 1989. The inspection included implementation of vendor manuals, testing of components and correctness and
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clarity of nation procedures. This inspection identified some problems in the maintenance areas such as:
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Various maintenance procedures needed improvements.
(Lack of acceptance criteria)
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1hermostatic valves and lube oil cooler did not have maintenance procedures 3)
Inadequate test data for trending on diesel start times, load sequence times, and setpoints for 4KV undervoltage relays.
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Inadequate control of vendor manuals
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Inadequate calibration of instruments.
l One concern issued in this SSFI report included several examples of deficiencies identified in the station procedures including QMS 6600-1-S4, " Diesel Inspection
- Refueling Outage Checklist". The SSFI report, however, did not identify the deficiency noted by this Maintenance Team Inspection that this procedure lacked
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.the acceptance criteria for the overspeed trip setting of the diesel. The
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report identified the problems of inadequate vendor manual control, as noted
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t in this report. This also indicatW that the licensee did not take adequate i
corrective actions for a previous 1) identified problem.
3.9.3 Effectiveness of Corrective Action All the QA findings including the open items were tracked by computer. The status of completion of corrective actions were periodically verified and the data updated. The audit findings were closed when all proposed corrective ll actions were completed, i
Overall, the licensee's self-assessment of maintenance activities was
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considered adequate.
More independent inspections similar to SSFI's should help in further improvement of maintenance at the Quad Cities station.
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4.0 Synopsis 4.1 Overall Plant Performance 4.1.1 Performance Indicators The historical data indicated that the overall plant performance improved considerably in 1989 over the previous years. Engineered safety feature actuations and personnel error DVRs had reduced gradually. The personnel error DVRs attributed to maintenance personnel were reduced by 80 percent since 1988.
4.1.2 Plant Walkdowns A few important items noticed were:
Housekeeping was considered good, ir view cf the fact that one unit
was in on outage.
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Several small cracks in the Unit 2 drywell pedestal, with moisture and
mineral deposits.
About one third of the control rod position indications in the
Control Room of Ur,it 2 (operating unit) were not functioning.
Heavy dust was observed on electrical cabinets k hind control boards
in the control room.
Service water pump motor ventilation openings were completely
blocked by bugs.
Color coded markings of Unit 1. Unit 2 and common equipment and
rooms were considered a strength.
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4.2 Management Support of Maintenance 4.2.1.
Management Committment and Involvement i
Management was actively comitted to improve maintenance activities at Quad Cities as-indicated by the work in progress on assigned sections of the
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" Conduct of Maintenance" (COM) program of CECO. However, the implementation of the COM appeared to be lagging.
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Management was vigorously committed to the improvement of the maintenance
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Commitment for an aggressive implementation of the numerous new
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maintenance related programs started at Quad Cities had improved system reliability.
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Commitment to reliability centered maintenance study of 28 systems.
Aggressive a)proach to implement several predictive maintenance
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programs suc1 as laser aligr, ment of rotating equiament, use of an
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advanced testing system for MOVs, MOV Limit Switc1 Bench Tester, CRD
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position indication tester, and extensive use of vibration analysis.
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Geod communications of management goals and policies, industry
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practices and initiatives through the Maintex program and tailgate sessions in the maintenance shops.
Based on weaknesses identified during this inspection, it was apparent that
continued involvement and strong commitment by management is necessary.
Areas in need of management attention are:
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Procedures control Corrective actions
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Root cause determinations
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Implementation of system engineer program
Contractor control
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Vendor manual control 4.2.2 Management Organization and Administration The inspection indicated satisfactory performance of the managment organization l
in the administration of the maintenance program. The station performance.
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particularly in the areas of ESF actuations and personnel error DVRs had
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improved considerably over the previous years.
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4.2.3 Technical Support
The licensee's technical support of maintenance was considered satisfactory; however, significant weaknesses were noted with the System Engineering program,
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including:
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System Engineers appeared to be relatively inexperienced for the
roles assigned, as exhibited by, in some instances, a lack of a complete understanding of the assigned systems.
It appeared that some system engineers had to handle a large number
of systems, making the engineers less effective.
t System engineers did not review the vendor manuals for inspection and i
PH requirements.
System engineers did not review completed work requests for failure
analysis and trending.
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System engineers did not receive the vibration analysis, unless
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alert / action levels were exceeded.
Engineering support appeared to be inadequate in procedure review.
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Some procedures lacked acceptance criteria.
Technical reviews for the HPCI Booster pump impeller were
incomplete.
Root cause analysis and failure trending were uncoordinated.
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4.3 flaintenance Implementation
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4.3.1 Work Control The licenpe's work control activities were considered satisfactory. The
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following comments apply:
The inspectors noted the following weaknesses:
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Failure to follow procedures as indicated by undocumented lifted
leads, poor fuse control, and poor implementation of vendor recommendations.
Detailed work instructions not provided for non-safety related work
requests, as evidenced by lack of torquing requirements for EHC pumps.
Work controls by contractors, such as erroneous cable pull
calculations, work packages not at job sites, not following procedures, misuse of plant equipment, and inattention in a radiation control area.
Quality control, as evidenced by lack of QC coverage in the electrical
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and I&C Areas.
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always contain tool / equipment / staging lists requirements, and could cause unnecessary additional radiation exposures because of lack of these details.
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For non-critical path maintenance jobs in radiation areas, adequate
notice to HP was not always given for pre-job planning. As a result, a rush ALARA planning could result in higher radiation exposures.
4.3.2 Plant Maintenance Organization The licensee's performance in this area was considered good. However, some improvements are warranted in the areas of work packages for non-safety related activities, and adherence and imprevements to procedures.
L 4.3.3 Maintenance Facilitics, Equipment, and Material Control The inspectors considered the licensee's perform *ince in this area satisfactory.
The following weakness was identified:
Some facilities such as open top decontanination areas and cramped
shop areas were considered less than optinal. This shoulo improve after the new maintenance facility is comp?eted.
The following strength was also noted:
M&TE control was good in that the licensee had procedures in place,
calibrations were traceable to national standards and well documented, and M&TE Labs had experienced and trained personnel.
4.3.4 Personnel Control A detailed evaluation of personnel control at Quad Cities was not made during this inspection. However, from the observations of the inspectors, it was evident that the management personnel were knowledgeable of responsibilities and accountability.
Staffing and training of maintenance groups for non-outage work appeared to be adequate.
5.0 Exit Meeting The inspectors met with licensee representatives (denoted in Paragraph 1) on October 18, 1989, at Quad Cities Nuclear Generating Station, and summarized the purpose, scope, and findings of the inspection. The inspectors discussed the likely informational centent of the inspection report with regard to documents i
or processes reviewed by the inspectors during the inspection. The licensee i
did not identify any such documents or processes as proprietary.
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ADS Automatic Depressurization System o
,.ALARA As low As Reasonably Achieveable
BOP Balance of Plant
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