IR 05000315/1990024
| ML17328A851 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 01/04/1991 |
| From: | Falevits Z, Gainty C, Mendez R, Slover W, Walker H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A848 | List: |
| References | |
| 50-315-90-24, 50-316-90-24, NUDOCS 9101150033 | |
| Download: ML17328A851 (18) | |
Text
U.S NUCLEAR REGULATORY COMMISSION
REGION III
Report No: 50-315/90024(DRS);
50-316/90024(DRS)
Docket No:
50-315; 50-316 License No: DPR-58; DPR-74 Licensee:
Indiana Hichigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Station, Units
8
'Inspection at:
Bridgeman, HI 49106 Inspectors:
der ainty R.
Mendez W. Slover Inspection Conducted:
Decemb 3-7, 1990 Z. Falevits, Team Leader
/-e-9I Date Date i/~ l~ i Date 9l Date Approved By:
H A. Walker, Acting Chief Maintenance 5 Outage Section AA Date Ins ection Summar Ins ection on December 3 throu h
1990 Re ort No. 50-315 90024 DRS 50-
~2 Areas Ins ected:
Routine announced follow up inspection to assess the effectiveness of corrective action programs planned or implemented to address weaknesses noted during the maintenance team inspection (HTI) documented in Inspection Report 50-315/89031(DRS);
50-316/89031(DRS),
This inspection was conducted using Temporary Instruction 2515/108.
Specific areas evaluated were limited to management involvement, maintenance program coverage and requirements, performance measurements, work in progress, electrical maintenance, engineering support, deficiency identification and control, trending, quality assurance and quality control.
9101150033 910108 PDR ADOCl( 05000315 G
Results:
The team concluded that the licensee had increased resources to establish a Maintenance Improvement Plan (MIP) in 1990 to upgrade the maintenance process.
Although progress was noted in some key areas, many ma)or aspects of the MIP were not implemented, apparently as a result of a conscientious decision to make slow and deliberate changes.
Implementation of the MIP was scheduled to begin in earnest after the end of the current outage on unit one in early 1991.
The team, however, noted a number of problems in preventive maintenance (PM), electrical maintenance, motor operated valves (MOV), and quality assurance (QA).
The team determined that it was too soon to assess the effectiveness of some of the maintenance improvement programs.
No violations were identifie DETAILS 1.0 rinci al Persons Contacted American Electric Power Service Cor oration M. Alexich, Vice President, Nuclear Operations
- M. Horvath, AEPSC Quality Assurance Plant Detachment Representative Indiana and Michi an Electric Com an
+A. Blind, Plant Manager
+R. Allen, Administrative Compliance Coordinator, Senior
~K. Baker, Asst. Plant Manager, Production
>T. Beilman, Maintenance Superintendent
- P. Carteaux, Safety and Assessment Superintendent
+J, Droste, Plant Engineering Superintendent
- L. Gibson, Asst. Plant Manager, Projects
+V. Kinchenloe, Training Superintendent
+J. Rutkowski, Asst. Plant Manager, Technical Support
+J.
Sampson, Operations Superintendent
- Denotes those present at exit meeting on December 7,
1990.
U S
Nuclear Re ulator Commission
- T. Martin, Director, Division of Reactor Safety
- B. Jorgenson, Section Chief, Division of Reactor Projects
+J.
Isom, Senior Resident Inspector
- DE Passehl, Resident Inspector 2.0 Licensee Action on Previous Ins ection Findin s 2.1 0 en Violation 315 89031-01B'16 89031-01B Failure to properly size thermal overloads in motor control centers (MCC).
The licensee developed Engineering Guide EG jjPS&HF-001 to provide the methodology for sizing and utilizing thermal overloads.
However, the licensee had not completed sizing and replacing all thermal overloads in safety related MCC cubicles.
Pending completion of the licensee's corrective actions, this item remains open.
2.2'losed Violation 315 89031-03'16 89031-03 Failure to provide adequate instrumentation and methodology to test the 4Kv diesel start undervoltage relays.
Since the MTI, the licensee made several changes in the testing methodology of the undervoltage relays.
The first was a Technical Specification (TS) change which modified the acceptance criteria from 90.3
- 91.8 to 90.3
- 96.8 volts.
Second, the instrumentation accuracy was improved.
The analog volt meter previously used was accurate to within
+1.5 volts.
The new digital volt meter model was accurate to within + volts.
Third, I&C personnel no longer used hand signals to determine where or when the relay picked up or dropped out.
The new relays could be removed from the control room cabinets and calibrated on the new test set.
This item is closed.
3.0 Ins ection Results 3.1 Ins ection Pur ose and Method This follow up maintenance team inspection (FUMTI) was conducted to evaluate the progress that the licensee had ma'de in the area of maintenance since the MTI was conducted in December 1989.
The MTI was documented in Inspection Report 50-315/89031(DRS);
50-316/89031(DRS).
The team reviewed historic data and various improvement programs.
Specific areas evaluated were limited to management involvement, maintenance program coverage and requirements, performance measurements, work in progress, electrical maintenance, engineering support, deficiency identification and control, trending, 'quality assurance and quality control.
3.2 Review of Plant 0 erations Historic Data The team reviewed the latest avai,lable maintenance department goals, objectives and performance indicators, and the plant operations historic data from January 1,
1990 to December 7,
1990.
The maintenance department had established new policies, objectives and performance indicators in 1990 and was in the process of developing comprehensive departmental goals for 1991.
The MIP contained the corporate strategic plan based goals and maintenance department goals for 1991.
This was considered to represent significant programmatic improvement and greater management involvement.
Based on the available plant performance for 1990, the majority of goals relating to maintenance such as unplanned reactor trips, safety system actuation, and forced outage rate were met for unit 1, but not for unit 2. It was not apparent to the team that plant performance in 1990 had been affected by maintenance related problems.
3.3 ana ement Philoso h Or anization and Administration of aintenance Activities 3.3.1 Maintenance Philoso h The MTI in 1989 identified maintenance philosophy to be mainly compliance oriented with little consideration for an effective proactive process.
Maintenance was found to be primarily based on TS requirements and some vendor manual recommendations; however, only 893 of 6800 vendor manuals had been approved.
During this inspection, the team noted increased management involvement in improving maintenance at D.
C. Cook., The plant manager's major goals for 1991 were personnel safety, maintenance program and outage management.
These goals
indicated a major shift in management's priorities since the MTI.
The team determined that the licensee had devoted considerable resources to the development of Reliability Centered Maintenance (RCM).
All systems in the plant were scheduled to be included.
The MTI had noted the initiation of a pilot program before that inspection.
The RCM process provided a rational basis for determining PM requirements for equipment considered important for proper functioning of the system.
PMs were developed based on vendor recommendations and industry experience and went well beyond TS requirements.
The team.considered the eventual incorporation of RCM into the PM program for all systems a significant strength.
Feedwater and auxiliary, feedwater system groups were in final review.
These reviews resulted in a 120 (45X)
PM task increase for feedwater (FW) and 51 (9X) increase for auxiliary feedwater.
An important finding of the FW study was that "currently no PMs were performed on the majority of the MOVs in the FW system."
The completion of the remaining 23 system groups was scheduled for June'0, 1992.
All PM procedures were to be in-place by December 31, 1992.
However, the team had concerns with schedule completion and order.
The team considered the schedule achievable but very ambitious.
The licensee had made changes to the program which had already resulted in a 4-6 month delay.
Additional delays had been identified by the licensee who. was taking action to obtain additional resources to maintain the schedule.
The team was also concerned that the emergency core cooling system (ECCS)
group review had been delayed for one year and followed less safety significant systems'he licensee explained that the order of systems was dictated by the order in which system engineers were being brought into the organization.
The, team was concerned that safety significant systems were not given higher priorities.
Since the MTI, the licensee had reorganized and accelerated the vendor manual review process.
The PM group was now the cognizant organization for vendor manual review and approval.
As of November 28, 1990, the licensee had approved 2904 of 6400 manuals.
3.3.2 Mana ement Or anization and Administration During t'e MTI, the inspectors identified the management organization and administration as a significant weakness.
A reorganization, just before the MTI, had left mai'ntenance personnel confused about authority, responsibility, and accountability.
Only limited maintenance goals were established in 1989 and none for 1990.
Maintenance policies did not exist for the mechanical and electrical groups.
A corporate manager existed for the plant maintenance division of fossil plants, but none was established for D.
C. Cook.
The MTI also noted poor scheduling, coordination, and prioritization of work activities and as well as an inability to respond to NRC requests in timely manner.
To correct these weaknesses, the licensee initiated the following improvement and corrective actions:
Early in 1990, management conducted group and individual meetings to explain the reasons for the reorganization and to provide a forum to permit personnel to feedback their concern The team attended the plant manager briefing to all plant staff on goals for 1990 and 1991.
In particular, the briefing focused on the employees'ontributions in achieving the objectives set in the maintenance related goals mentioned above.
The briefings were held four times a day, three days a week, to ensure all personnel could attend.
Significant resources and effort were devoted to complete the development of the MIP in 1990.
The MIP provided a single integrated approach to establish goals and identify areas for improvement.
The MIP considered the concerns of all groups involved in audits of maintenance both within and without the company.
While it was clear that the MIP would improve the quality of maintenance, it was too soon to assess the effectiveness of the MIP.
Progress had been made in some key areas; however, many major aspects of the MIP had not been implemented.
This was a result of the licensee's conscientious decision to make slow and deliberate changes, due in part to the impact of organizational changes and the 1990 refueling outages.
However, the team felt that implementation of these programs needed to be accelerated to provide more'imely positive results.
The team noted that in 1990, a corporate Nuclear Maintenance Section was formed to improve the interface between site and corporate maintenance management.
Also, the licensee combined scheduling for electrical, mechanical, and I&C into a single organization supervised and staffed by highly experienced personnel.
All maintenance was performed using a single priority system.
The team noted that during the FUMTI, information requested was located quickly and responsiveness to other requests was excellent.
Although outage management was not identified as a weakness by the MTI, the licensee had put in place an Outage Management Team (OMT) to better coordinate the complex process of executing the current outage.
The OMT efforts appeared to be successful for the Unit 1 outage.
On day 61 of a scheduled 85 day outage, the licensee was 8 days ahead of schedule 3.3.3 Preventive Maintenance P'r o ram During the MTI, the licensee and the NRC could not determine if the maintenance program was appropriately balanced with corrective maintenance (CM) and PM because a formal PM program had not been established.
As a result, the licensee had formed a new group within the maintenance department.
This group consisted of 17 personnel, including three engineers, was the single point of contact for all plant PMs, and provided the technical support necessary to integrate and manage the plant wide PM program.
The PM group had identified all PMs being performed in the plant.
However, the PMs were contained in seven different data bases, and the team was concerned that such scattering could result in the failure to identify overdue PMs on safety related equipment.
The licensee was developing a single comput: er data base to integrate all PM requirements, but it was not scheduled to be in place before the summer of 1991.
6'
The team reviewed the overdue PMs shown in the "Preventive Maintenance
'Monthly'eport for JAN 91."
There were 12 electrical, 153 mechanical and
The number of PMs for safety related electrical and mechanical equipment could not be determined from the report.
There were
overdue PMs for safety related I&C equipment.
The team examined a sample of the overdue PMs and did not consider the overdue PMs an immediate safety concern.
The licensee's predictive maintenance program had continued to develop'ince the MTI, The methods considered fully implemented by the licensee were vibration monitoring, thermography, and oil analys'is.
Motor current spectral analysis and noise analysis were being used selectively.
3.3.4 E ui ment Identification The licensee had made approximately 50,000 color photographs of all components in the plant.
Photographs were cataloged by equipment identification number and were accessible through a computer with laser disc memory/printer or by direct reproduction from a color slide.
Several instances of the use of this system were noted by the team.
The team considered the photographs a strength since positive identification and accessibility determinations were enhanced during the job planning and execution phases of the maintenance process.
II 3.3.5 Conduct Performance Measurement The MTI had previously identified weaknesses in root cause analysis and action to correct reported problems.
An investigation and determination of root
.
cause was required when a problem report (PR) was initiated.
The team reviewed several PRs to assess how root cause analysis was performed on identified maintenance related failures.
In general, the root cause analysis performed on the PRs reviewed appeared adequate, and corrective action seemed appropriate and timely.
Any corrective action not completed at the time the PR was submitted for review and approval was required to be scheduled.
This ensured required actions were actually implemented.
However, PRs were not always written when problems occurred, and there may or may not have been a
root cause analysis performed, depending on system engineer involvement.
3.4 Technical Su ort 3.4.1 En ineerin Su ort The MTI had previously identified concerns with engineering support of maintenance.
Specific weaknesses noted were engineering support for root cause, failure analysis, and post maintenance testing (PMT); and communication between plant and corporate engineering staffs.
Some improvements were noted during the FUMTI in the area of engineering support of maintenance, such as a
new test requirement manual to assist planners in specifying PMT, increased system engineer involvement in support of maintenance, and a new program that established system engineer responsibilities and interface with corporate engineering.
Although improvements were noted, the implementation of the system engineering program was slo.4.2 S stem En ineerin The system engineering department had expanded from 3 system engineers (SE) in December 1989, to 10 SEs in December 1990, with plans to hire at least 3 more.
Plant Engineering
"System Engineer Program" was,issued in September 1990, to formalize the responsibilities of the SE.
Some of the SEs had been involved with their assigned system for several years, either as a test engineer or a maintenance engineer, and had not fully assumed the new duties of the position due to back-to-back outages.
All SEs were required to attend reactor operator training on assigned systems and many had attended a Kepner-Tregoe course on root cause analysis.
Several SEs appeared actively involved. in maintenance problems in assigned systems; however, some SEs indicated that if a component like a valve, for example, failed, the maintenance engineer, not the.SE, would have the responsibility to provide guidance for the repair.
There was no requirement for.the SE to review all system related job orders.
When assigned a problem report for review, a root cause analysis was required; otherwise SEs would have to depend on their awareness of system problems to determine which
.
problems needed to be followed up.
Some SEs performed root cause analysis on specific problems and trended system parameters to identify CM and/or were involved in the RCM analysis and the review of the final RCM package.
The team observed the following weakness in the lack of system engineer involvement regarding the failure of a reactor trip breaker (RTB)
~
The licensee had only one SE assigned to the entire electrical area.
The team noted the electrical SE was not involved and was totally unaware of a Unit 2 RTB failure on November 5, 1990.
The Unit 2 RTB failed due to high resistance in the auxiliary contacts caused by possible contamination of the graphite grease.
With one of the RTBs in the trip position, the trip of the other RTB caused an ESF actuation.
PR 90-1661 was written to document this failure.
Earlier in April 1990, the electrical maintenance staff and electricians received instructions from the vendor for performing PMs which included checking and changing or adding grease to the RTB contact fingers.
The licensee's PM procedure and the original vendor manual did not require changing of the graphite grease.
Discussions with the licensee indicated that the graphite grease, which acted as a conductor, had never been changed since the plant became operational in 1974.
In addition, the licensee took no action from April to November, 1990, to resol've differences between the PM procedure and the revised vendor instructions for the RTBs.
This lack of attention subsequently resulted in the ESF actuation.
3.4.3 Maintenance En ineerin The maintenance department had increased to 6 maintenance engineers including 4 in mechanical and welding and 2.in Instrument and Electrical (I&E).
The maintenance engineers were component-oriented and each was assigned an area such as pumps, valves, welding, or turbine.
Each was required to work closely with the mechanics and resolve maintenance problems with respect to the repair of components on a daily basis.
None were involved in review of job orders for failures or trending'.
4~
i
3.4.4 Maintenance Trendin During the MTI, the inspectors identified trending as a weakness in the licensee's maintenance program.
The team verified that the maintenance organization established or was in the process of developing procedures to implement maintenance trends.
The licensee developed the Maintenance Administrative Process (MAP) which used data obtained from PRs.
The PRs which addressed systematic fixes and root cause analysis were used to compile the Consolidated Trend Program (KTP).
The KTP trend report, currently issued twice a year, used the accumulated data from the PRs and described adverse trends during the previous six months.
In addition, the license was in the process of expanding the I&C Job Trend Evaluation Trend Program to include the electrical and mechanical maintenance departments.
The draft procedure received from the licensee would implement measures to analyze the Job Order (JO) for root cause failure, and work performed by the craft to correct the problem; the procedure also addressed rework evaluation.
During the review of the trend reports, the team observed that the Trend Report for "Problem Reporting System" dated November 7, 1990, concluded that management needed to focus more attention on reports caused by "work practices and lack of attention to detail;" lack of attention to detail was also identified by outside auditing organizations and by the previous licensee trend report in 1989.
PR-0702 reported a possible adverse trend in the failure of Technical Specification dampers; one of the causes was determined to be lack of PM.
3.5 On oin Maintenance The team performed limited observations of ongoing work in electrical, mechanical, and I&C areas.
Where possible, safety significant activities were chosen for the review to determine if required administrative approval was obtained; if work instructions were adequate, if replacement parts were acceptable, and if personnel were experienced and knowledgeable.
3.5.1 On oin Electrical Maintenance The team observed portions of activities associated with the following JOs.
A28207 A28208 A50899 Perform motor operated valve (MOV) PM Perform MOV PM Check relay calibration Based on the limited observation 'of work activities, the team concluded that maintenance activities were satisfactorily accomplished by maintenance personnel.
The maintenance supervisor and craft were knowledgeable and adequately trained.
A thermography program, which included both safety and balance of plant (BOP) electrical components, was-in place.
Concerns were identified with the lack of follow up to resolve wiring errors, lack of attention to detail, and poorly organized procedures associated with
preventive maintenance work on valves.'28207
- The team observed work associated with component cooling water valve CMO-420 and found that the leads landed on the limit switch did not conform with wiring diagram 1-95233.
The team verified that the electricians had correctly identified the errors between the drawing and the field configuration.
The drawing used for reference by the electricians indicated that a red conductor was to be terminated at terminal point 40 on the limit switch.
Instead a green conductor was landed on terminal point 40 and the red was a spare conductor.
The team determined that the operation of the valve was not affected.
However, a deficiency was identified by the electricians
.with no subsequent follow up.
The licensee's procedures required'that a
condition report be issued or that the drawing be forwarded to the design organization, The licensee had not written a condition report, a
PR or taken follow up action to determine whether the discrepancies affected the operation of the valve.
In addition, the team found that since the drawing was used only for reference, the drawing was not kept with the JO package.
Consequently, there would be no evidence that a wiring discrepancy had occurred when the JO package was ready to be closed out.
On December 6,
1990, the licensee issued PR 90-1914 to resolve the differences between the drawing and the field configuration.
A28208
- During observation of ongoing field activities the team noted that torque switch settings required by procedure were not recorded, follow up action was not taken to resolve wiring discrepancies, and a poorly organized procedure which required steps to be accomplished in sequence resulted in the incorrect reinstallation of the Limitorque Model HBC operator.
The team witnessed portions of work to set limit switches on component cooling water valve CMO-429.
The team identified the following concerns:
The initial condition section of procedure 12MHP5021.001.037,
"Maintenance Procedure for Rotor and Torque Limit Switches on Limitorque Motor Operated Valves," Revision 4,'equired that the design torque switch setting be obtained and recorded in Attachment 1, On December 4, 1990, the team reviewed Attachment l,and noted that initial condition requirements such as the JO number, valve ID number and design and maximum torque switch settings were not recorded.
In addition, Step 6.5 required that the Unit Supervisor be contacted prior to starting work and that Attachment 1 be signed.
The electrician had obtained a
clearance for the job; however, none of the steps mentioned above were recorded or signed.
Furthermore, the team noted that t'e procedure did not require the recording of the as-found torque switch setting until the valve was already disassembled, repaired and reassembled (Step 7.4.1 of the procedure).
This was regarded as an example of a poorly organized procedure.
The licensee stopped the job, brought the procedure up to date; and issued PR 90-1910.
During further observation of work, the team noted discrepancies between the wiring diagram and the field connections at the limit switch.
A jumper across terminal points 42 and 52 and a lead landed on terminal point 51 were not shown on the drawing.
The team noted that the
\\
electricians had marked reference drawing 1-95233 but had not taken action to resolve the wiring discrepancies, even though the errors had been identified on November 18, 1990, when the valve was disassembled.
In addition, the supervisor and the team found that the drawing did not match terminations in the'junction box for terminal points 424CL and" MCC.
This had not been identified previously by the electricians.
The wiring errors at the limit switch were found to be spares and the errors in the junction box were determined not to affect the operation of the valve.
However, procedure PMI-7030 required that if drawing errors were identified, a condition report shall be issued or the drawing shall be forwarded to the design-division for resolution.
The 'licensee did not provide evidence that corrective action had been taken.
On December 6,
1990, the licensee issued PR 90-1912 to resolve this matter.
The above example was considered a weakness in the licensee's actions to follow up on identified problems.
- During the ongoing field activities, the licensee attempted to stroke open the valve from the closed position but found that the valve was aire'ady in the open position.
During reassembly of the HBC operator, the electricians involved in replacing the operator failed to check the position of the valve and assumed the valve was in the closed position.
The team reviewed the work package and found that poor turnover documentation, when the HBC operator was removed and then re-installed, may have also contributed to the problem.
The steps in the procedure, where one shift left off, were not clearly delineated.
In addition, procedure
- 12MHP5021.001.0042,
"Disassembly, Repair and Rebuild of Limitorque HBC Valve Operators,"
Revision 2/1 did not require that the position of the valve be documented during disassembly of the HBC operator.
However, prior to reassembly of the HBC operator, Step 7.3.9 required that the valve be placed in the full closed position.
The step in the procedure was in error because the valve could not normally be closed without the operator.
This was another example of a poorly written procedure.
3.5.2 On oin Mechanical Maintenance The team observed portions of the activities associated with the following JOs.
A1499 A57164 731173 Repair body/bonnet leak in reheat coil drain tank drain.
Replace existing packing in EDG jacket water pump.
Replace seat in circ water outlet valve from turb aux cooling water heat exchanger.
The team concluded that mechanical maintenance activities observed were accomplished by skilled maintenance personnel.
The team noted that the JOs were approved'nd that work was being done within the scope of the JOs using approved procedures and drawings.
Photos were included in the job package to facilitate identification.
Areas in the vicinity of the work were clean and contained necessary equipment to support the work in accessible positions.
Portable lighting was used when necessary.
3.5.3 On oin I&C Maintenance The team observed portions of the activities associated with the following JO.
A50899 Calibrate time delay relay The team concluded that I&C maintenance activity observed was accomplished by, skilled maintenance personnel who appeared knowledgeable of the work performed.
3.6 ost Maintenance estin The plant engineering department issued the
"Component Test Requirement Manual," dated September 13, 1990.
This manual was expected to improve the present method of specifying PMT, but only applied to inservice test (IST)
valves.
Job order planners used the manual in conjunction with the facility data base (FDB) and procedure MHI-2293, "Maintenance Testing and Inspection Instructions," Revision 1, which contained specific attachments for PMT.
The'esponsibility for specifying PMT was still with the job order planners.and there was usually no direct system or maintenance engineer. involvement, The licensee expected improvement and consolidation of requirements with the future use of the nuclear plant maintenance computer system.
3.7 C
A Involvement 3.7.1 C Involvement in Maintenance The MTI had previously found "peer inspection" to be vague, i'neffective, and lacking in guidance or acceptance criteria.
Subsequently, procedure PMI-7090,
"Plant Quality Control Program," Revision 3 was issued to clarify the differences between QC type inspections and those performed by "peer inspectors."
The procedure specified that QC inspections were normally required for work performed by contractors,'nd that most other inspections were performed by "peer inspectors."
Types of "peer inspections" included:
verification, independent verification, independent inspection and inspection hold points.
Verification was allowed to be performed by a co-worker while independent verification/inspection was required to be performed by an individual who did not witness the work at the time it was performed.
The team reviewed maintenance procedures for the type of verifications and inspection points contained and to assess acceptance criteria provided.
The procedures contained verification points for such things as torque wrench calib'ration, blue check results, and relay coil wires tagged and lifted; and independent inspection points for inspection of valve parts for damage and inspection of pump parts prior to reassembly.
In each case, the acceptance criteria was provided'in the procedure and appeared to be adequate.
The team noted that QC personnel picked up extra radiation exposuie because a
contractor requested a
QC cleanliness inspection without actually being ready.
During final closure of steam generator manways, multiple entries by QC personnel were required because'f inadequate cleaning by the contractor'rior to requesting the inspection.
PR 90-1878 was issued to report this condition and was being investigated at the time of the FUMTI.
3.7.2 A Audits and Surveillances The MTI inspectors had determined that the scope and number of QA audits related to maintenance was a weakness.
The QA audit of the PM program was not performed in 1989 and the maintenance portion of the PM audit pe'rformed in 1990 was deferred; however, there were several other QA audits and QA surveillances performed in the maintenance area in 1990 which appeaied to be performance based, involved direct observation of work in progress and which identified important findings.
The team.reviewed QA audits and surveillances to assess how well maintenance problems were identified and corrected.
QA findings appeared to be tracked thoroughly for follow up actions.
Late responses to QA findings were reported to management to encourage prompt action.
A review of overdue responses indicated that two responses were over 60 days late.
One response, QA-89-25-05B, was over 5 months late and had already been rescheduled.
PR 89-1307 was issued November 27, 1989, to document that, contrary to American Society of Mechanical EngineersSection XI (ASME XI) and procedure PMI-5070, maintenance was performed on several IST p'rogram pumps without an associated evaluation for impact on the pump's test criteria.
As part of the investigation, the IST pump engineer reviewed the job orders and found no problems; however, the maintenance department committed to change procedure PMI-2290,
"Job Orders," to require that the IST pump engineer be contacted when work is done in the future.
An extension in the due date to June 30, 1990, for the revision to the procedure was requested based on forthcoming ASME XI code changes, but as of the time of the FUMTI, the audit finding was still not closed.
3.7.3 A Plant Cor orate Interface The team noted a coordination problem between site QA and corporate QA.
Site QA audit finding 90-24-02D identified several instances where transmitter junction boxes were missing drain holes.
PR 90-1115 was written to document the condition and stated that EQ inspections were not complete and any additional nonconformances would be added to the same PR.
The PR was then forwarded to corporate engineering for review and evaluation.
Because the PR was written as a result of a site QA audit, procedure PMI-7030, "Condition Reports and Problem Reporting," Revision 15, required the PR to be returned to site QA for closure.
Instead, after engineering disposition, corporate QA inadvertently closed out the PR without verifying if other nonconformances existed.
'Site QA initiated PR 90-1532 to re-open the issue because additional transmitters were involved.
Even though PR-1115 was inadvertently closed out by corporate QA, the audit finding was still open.
In response to team concerns, site QA initiated PR 90-1924 to document the fact that corporate QA inadvertently closed out a site QA initiated PR.
Further investigation by site and corporate QA during the FUMTI revealed that this had happened before.
Both PMI-7030 and the corporate procedure, GP15.1,
"Corrective Action,"
Revision 6, were revised to clarify applicable portions of PMI-7030 and GP15.1 to prevent recurrence.
4.0 The team met with licensee representatives (shown in Section 1) on December',
1990, at the D.
C.
Cook Nuclear Power Plant and summarized the purpose, scope, and findings of the inspection.
The inspectors 'discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the team during the inspection.
The licensee did not identify any documents or processes as proprietary.
I
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