IR 05000373/1994017
| ML20149H289 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 11/09/1994 |
| From: | Beverly Clayton NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149H281 | List: |
| References | |
| 50-373-94-17, 50-374-94-17, NUDOCS 9411220101 | |
| Download: ML20149H289 (18) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No.
50-373/94017(DRP); 50-374/94017(DRP)
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Dockets No.
50-373; 50-374 Licenses No. NPF-ll; NPF-18 Licensee:
Commonwealth Edison Company Executive Towers West III 1400 Opus Place, Suite 300 Downers Grove, IL 60515 Facility Name:
LaSalle County Station, Units 1 and 2 Inspection At:
LaSalle Site, Marseilles, Illinois Inspection Conducted: August 20 through October 7, 1994 Inspectors: P. Brochman K. Ihnen H. Simons C. Gill D. Hills E. Schweibinz D. Schrum K. Salehi W. Reckley, NRR R. Zuffa, Illinois Department of Nuclear Safety
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Approved:
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Brent Clayton, Chief Date Reactor Projects Branch 1 Inspection Summary inspection from August 20 through October 7, 1994 (Reports No.
50-373/94017(DRP): 50-374/94017(DRP)).
Areas inspected: A routine, unannounced safety inspection was conducted by the resident, regional, and headquarters inspectors and an Illinois Department of Nuclear Safety inspector.
Areas evaluated included plant operations, maintenance, engineering, plant support, and followup on previously identified items and licensee event reports.
l Results: One violation was identified in the engineering area due to the i
failure to take prompt corrective actions regarding incorrectly installed flow measuring orifices (paragraph 3.2).
9411220101 941109 PDR ADOCK 05000373
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Executive Summary LaSalle Nuclear Power Station Report Nos. 373/94017; 374/94017 Plant Operations Plant management's focus on safety continued to improve and was good. The quality of plant operations review committee (PORC) meetings continued to improve. The safety focus and quality of the PORC prior to the Unit 2 restart was especially noteworthy.
However, this good safety focus was not so apparent at an outage planning meeting following the Unit 2 scram on August 25, 1994. During that meeting, the restart schedule was repeatedly
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emphasized and there was little mention of safety. Methods to quickly determine the scope of a forced outage were not apparent.
Maintenance Good coordination was observed between all departments involved in the repair and charcoal replacement of the Unit.1 standby gas treatment system. This was
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noteworthy due to the emergent, expanded scope of the work and the relatively short technical specification timeclock associated with the repair.
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response to information obtained from General Electric regarding problems with scram pilot solenoid valves was also timely.
Difficulties associated with the repair of the 2A condensate / condensate booster pump were of concern as they
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may be indicative of broader problems in improving overall plant materiel condition.
Engineering Overall engineering support was acceptable and some improvement was noted.
The details of a.special engineering inspection are included as an attachment to this report.
Site engineering performance was good based on our review of modifications and support to plant operations. The modifications had thorough l
safety evaluations and effective design controls.
i Communications between engineering and other plant organizations were improved i
but difficulties still existed as evidenced by the failure to identify incorrectly installed flow measuring orifices after several opportunities to do so (Notice of Violation).
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System engineer improvement initiatives remained in early stages with
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substantial plans yet to be implemented.
Weaknesses included timeliness of responding to Site Quality Verification (SQV) findings, definition of the role of " System Manager" for system engineers, delay in implementing system engineering commitments to coordinate preventive maintenance, and continued root cause and corrective action impediments. The system readiness review board was a good initiative; however, opportunities for process improvement opportunities existed.
The licensee placed increased emphasis on completing work assignments; however, weaknesses in system engineering management overview remained. A nonconservative safety approach to reactivity management was noted but regarded as an isolated incident by the inspectors.
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Plant Support
Although some improvement in radiation protection performance has been notea, problem areas remained including a high number of hot spots, contaminated areas, and events; continuing radworker adherence problems; and still high (but improved) collective radiation dose. There were indications that Site Quality Verification (SQV) was developing the ability to integrate findings into broader fundamental issues (such as radiation protection and radwaste concerns.) Good security staff perfo.rmance was observed in the central alarm station; however, inadequate use of the problem identification system appeared to be a problem.
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DETAILS 1.0 OPERATIONS (71707 and 92901)
The inspectors reviewed the facility for conformance with the license and regulatory requirements. On a sampling basis, the inspectors observed control room activities for proper control room staffing; coordination of plant activities; adherence to procedures or technical specifications; operator cognizance of plant parameters and alarms; electrical power configuration; and the frequency of plant and control i
room visits by station managers. Various logs and surveillance records were reviewed for accuracy and completeness.
Walkdowns of select engineered safety features (ESF) were performed.
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1.1 Improvement of Plant Operations Review Committee Meetings The quality of the plant operations review committee (PORC) meetings was improving, with questions focusing on the safety impact of decisions and proposed changes. However, the licensee did not have a mechanism for tracking PORC open items; Comed subsequently developed a tracking system for PORC items. As none of the items were over 30 days old, no inspection of periodic review activities was made.
1.2 Good Safety Focus of Restart Activities Following Unit 2 Scram The safety focus of plant personnel investigating the August 25, 1994, Unit 2 scram due to the spurious opening of main turbine bypass valves, was very good. The investigation into the electro-hydraulic control (EHC) problems was thorough and systematic. A special procedure was developed to systematically troubleshoot the system and several minor problems were corrected which could have originally caused the opening of the bypass valves; however, the root cause was not definitively determined.
The safety focus of the PORC meeting held prior to restart was excellent, as all out of service equipment and other relative information were included in the decision to restart the unit.
In addition, a good discussion of the safety significance of the event was observed.
However, during an outage planning meeting, the inspectors observed that management emphasized production and starting up the unit, rather than safety.
The importance of the. schedule was emphasized with EHC being critical path. Although no negative effects were observed due to this focus, upper management's safety perspective could have been misunderstood by plant personnel.
It was not apparent to the inspectors that Comed had a method for quickly determining the scope of a forced outage and an outage work list.
However, Comed was somewhat prepared for this outage since a maintenance outage had been fully planned and then cancelled.
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1.3 Followup of Previously Identified Items in the Operations Area (0 pen) Unresolved Item (373/93013-01(DRP)):
Comed did not require.the operations' managers at its facilities to maintain a senior reactor operator (SR0) license.
However, SR0 licenses were maintained by the assistant superintendent of operations and the operations' engineers.
Clarification of operations manager qualification requirements was to be provided in a technical specification change regarding th current Comed organization structure (revised in early 1993).
However, this change continued to be negotiated within the company and with the NRC in regard to the Quality Assurance Topical Report.
Therefore, this item remains open pending completion of that activity.
No violations or deviations were identified in this area.
2.0 MAINTENANCE (61726, 62703, and 92902)
Station maintenance activities affecting the safety-related and important to safety systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and did not conflict with technical specifications.
Surveillance testing required by technical specifications, the safety analysis report, maintenance activities, or modification activities were observed or reviewed. Areas of consideration while performing observations were procedure adherence, calibration of test equipment, identification of test deficiencies, and personnel qualification. Areas of consideration while reviewing surveillance records were completeness, proper authorization and review signatures, test results properly dispositioned, and independent verification documented.
The following maintenance and surveillance activities were observed or reviewed:
Unit 1 Standby Gas Treatment charcoal replacement and screen repair Unit 2 Standby Gas Treatment charcoal replacement 1A Condensate / Condensate Booster Pump 1B Fuel Pool Emergency Make Up Pump 2B fuel Pool Emergency Make Up Pump 2B Drywell Nitrogen Compressor 2A Condensate / Condensate Booster Pump repairs LOS-DG-M3, 1B Emergency Diesel Generator monthly run LOS-DG-M6, 28 Emergency Diesel Generator monthly run LIS-MS-202, Main Steam Line High Flow MSIV lsolation Calibration LOS-RI-Q5, Reactor Core Isolation Cooling (RCIC) Pump Operability, Valve Inservice Tests in Condition 1, 2, and 3 and Cold Quick Start.
LIS-NR-209 Average Power Range Monitor Gain Adjustment LTP-1600-6 Traversing Incore Probe Calibration 2.1 Good Coordination of Plant Activities to Repair Unit 1 Standby, Gas Treatment System
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The inspectors observed good interdepartmental cooperation and management involvement regarding the timely return to service of the Unit 1 Standby Gas Treatment System (SGTS), This was noteworthy due to the emergent, expanded scope of the work and the relatively short technical specification timeclock associated with the repair.
In addition to charcoal replacement (see paragraph 4.6), scope addition included repair of a charcoal absorber screen corroded due to a leaking fire protection system deluge line.
Comed also ensured that the inspectors were kept informed as to the progress of the job.
2.2 Timely Resolution of the Scram Solenoid Pilot Valve (SSPV) Concerns LaSalle's response to General Electric (GE) RICSIL 069, rega ding slow control rod scram times due to degraded diaphragms in SSPVs, was timely and well planned.
In response to the RICSIL, maintenance personnel inspected the diaphragms on suspect SSPVs during the last Unit I refueling outage, LlR06. As a result of this inspection and subsequent analysis by GE, four SSPVs, installed in Unit 2 during L2R03, were also inspected with localized hardening observed. An expanded scope inspection of all SSPVs in this group was underway at the end of this inspection period and additional instances of hardened diaphragms were being found.
2.3 2A Condensate Pump Repair Paoblems The problems associated with the repair of the 2A condensate / condensate booster (CD/CB) pump raised concerns regarding efforts to improve the material condition of the plant. This pump had been out of service for corrective maintenance since late June. The ongoing efforts to return thi:: pump to service were plagued by difficulties.
When the pump was returned to service, a flow transient resulted in a feedwater heater isolation; and the pinion bearing in the speed reducer was damaged.
Problems with the alignment of the pump skid continued.
The licensee intended to do a full root cause analysis on the difficulties associated with the 2A CD/CB pump.
2.4 Followup of Previously Identified Items in the Maintenance Area (Closed) Violation (373/92028-02(DRP)):
Inadequate limitorque operator maintenance procedure. Corrective actions were reviewed in inspection report 373/94002(DRP); 374/94002(DRP). The final action, revision of training lesson plan GPE06, "Limitorque Valve Operator Maintenance", to describe the methodology for installing grease in horizontally mounted motor operated valves, was approved on May 23, 1994.
This item is closed.
(0 pen) Open Item (373/93004-03(DRP)): Technical specifications failed to delineate channel checks of reactor vessel level instrumentation. A technical specification change request was onsite reviewed in June 1993 but due to other priorities was not completed and submitted.
It was recently updated and was currently in another onsite review (94-075)
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process. This item remains open until submittal and NRC approval of the change.
(Closed) Violation (373/93019-01(DRP)): Miswired relays despite independent verifications.
This violation did not require a licensee response as completed corrective actions were documented in the report.
Therefore, this item is considered closed.
(Closed) Inspection Follow-up Item (373/93030-01(DRP)):
Review failures of reactor core isolation cooling (RCIC) tracking control relay.
Comed's actions addressed two possible causes of the failures.
In response to possible contact corrosion, Comed init ated action item records (AIR) to include inspection of the RCIC relays in the preventive maintenance (PM) program, review other low current relays for possible
inclusion, and examine suitability of this model relay to a low current
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application.
In response to an identified manufacturing defect for HMA relays manufactured in 1974, Comed also initiated an AIR to measure other suspect relays for possible armature binding. This was planned for the
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next refueling outage on each unit. Although licensee event report 374/93010 mentioned a twenty year service life for these relays, Comed could not identify the source of this number. There was a service life of sixteen years applied to environmentally qualified (EQ) HMA relays, but these particular ones were non-EQ. The inspectors will continue during routine inspections to evaluate vendor information available to system engineers for root cause analyses. This item is closed.
(Closed) Violation (373/93035-01(DRP)):
Inadequate procedure to ensure main steam safety relief valve spindle nuts correctly tightened.
Corrective actions included maintenance procedure revisions and new post-maintenance testing procedures. These were completed and this item is closed.
No violations or deviations were identified in this area.
3.0 ENGINEERING (37700, 37500, 37550, 49001, 92700, and 92903)
The inspectors evaluated the licensee's engineering activities and the effectiveness of the engineering organization to perform routine and reactive site activities, including the identification and resolution of technical issues and problems.
3.1 Improved Engineering Performance; However, Several Concerns Warranted Continued Management Attention Based on a detailed inspection of the engineering area (contained in the attachment to this report), engineering performance continued to improve and was good. Modifications reviewed contained adequate design control and well documented safety evaluations.
Effective communications between engineering and other organizations resulted in the identification and resolution of some plant problems. However, several
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notable areas needing improvement included timeliness of responding to Site Quality Verification (SQV) findings, better defining the role of
" System Manager" for system engineers, delay in implementing system engineering commitments to coordinate preventive maintenance, and continued root cause and corrective action concerns.
One inspection followup item was identified regarding system engineering involvement in review of items in the electronic work control system prior to performing work.
3.2 Inadequate Resolution of Incorrectly Installed Flow Measuring Orifices Although there were several previous opportunities to identify misoriented flow measuring orifices (including one recent chance in 1994), Comed failed to adequately identify and resolve this issue.
On June 9, 1982, Zion Station notified all Comed nuclear stations
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that reactor coolant loop resistance temperature detector flow orifices were found installed backwards on Unit 2.
On August 3,1983, the two resultant LaSalle AIRS were closed based on verification of correct orifice orientation during initial plant construction and preoperational testing.
On October 5,1990, NRC Information Notice (IN) 90-65 notified all
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power reactor licensees of recent problems associated with orifice misorientation.
The resultant Lasalle Nuclear Tracking System (NTS) Item No. 373-103-90-06501 was closed based on the previous AIRS and IN 90-65 not applying to LaSalle.
A site maintenance procedure (LMP-GM-20) was also developed to verify proper orifice installation during maintenance activities.
On February 21, 1994, LaSalle Station's Unit 2 reactor core
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isolation cooling (RCIC) system isolated due to a burst rupture disc.
Comed determined part of the root cause was a drain line orifice improperly installed on the steam exhaust drain line.
The orifice was removed from the drain line approximately six months earlier, during a RCIC turbine inspection. A planned corrective act ;an to evaluate other systems for improper orifice installation was not timely.
Between July 25 and August 3,1994, inspectors identified flow measuring vifices installed backwards on the Units 1 and 2 fuel pool emergency mate up pump lines, the Unit 2 low pressure core spray system discharge lit e, and the Unit 2 drywell floor drain discharge line.
Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion XVI, states, in part, that " Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected".
The failure to promptly identify and adequately correct this problem is a violation (373/94017-01(DRP); 374/94017-01(DRP)) of Criterion XVI.
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The safety significance of these specific examples was minimal since in most cases the error in flow was in the conservative direction.
In the case of the Unit 2 drywell floor drain discharge flow orifice, the error in measurement war about two percent in the non-conservative direction.
However, the historical floor drain discharge flow was sufficiently I
below the Technical Specification limit such that given the error in flow measurement, the limit was not exceeded. This violation indicates continued problems with inadequate corrective actions.
i 3.3 System Engineering Improvement Initiatives Remained In Early Stages The inspectors evaluated the system engineering program's ability to influence plant equipment materiel condition. This evaluation included progress review of pertinent commitments in Comed's April 1,1994 response to a notice of violation.
This document defined Comed's plans for improving the system engineer program to effect better plant materiel condition and the intended future role of system engineers.
Although system engineering managers were generally familiar with these improvement plans, some were not aware that this document existed.
The licensee did not plan to implement many of these stated changes until 1995 and these efforts remained in their infancy.
This conclusion was based on the following observations:
System engineers were aware of the intent that they become System
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Managers, but they were unclear as to what actions this role entailed.
Plant management had not yet clearly defined their expectations in this area.
For example, the degraded equipment log was not consistently utilized as a source of information on equipment condition and status and equipment monitoring data (such as vibration trend data) was not consistently reviewed by system engineers.
Most system engineers interviewed appeared knowledgeable of system
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design, operation, and current status. They were effectively utilizing counterparts at other non-Comed facilities for information on their systems.
System engineers were not yet controlling maintenance work on their systems, although some did exert limited influence.
Upper plant management indicated that system engineers possessed the authority to control their systems; however the vehicle to exercise this control was not readily apparent. Some extraneous work activities were removed from system engineer responsibilities, with mixed success, so they would have more time to concentrate on long term system improvement.
One week prior to the inspection, the licensee implemented their
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electronic work control system (EWCS). This new system required engineer review of work activities prior to and subsequent to work performance. However, system engineers were not yet clear as to what their reviews entailed.
It was too early to evaluate the effectiveness of this initiative.
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Most system engineers contacted did not yet consider overview of
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the preventive maintenance (PM) program for their equipment as the system engineers' responsibility. Although they had effected some PM program changes in response to specific failures and problems with their equipment, almost none had performed a systematic review of PM activities on their systems. Although the system engineers are expected to be system managers, responsibility for the reliability centered maintenance (RCM) program, in existence for several years, had not yet been transferred to the system engineers from the maintenance department.
Insufficient guidance still existed on system performance
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monitoring. Although plant management had directed system engineers in late 1993 to develop system monitoring criteria, the importance of this activity was not emphasized by plant management and it was not accomplished.
Some of the engineers stated that implementation of the maintenance rule (planned for 1995) would accomplish this. However, planning for the maintenance rule remained at corporate.
Some of the system engineers were unaware of the maintenance rule.
Although system engineers were aware of their items on the plant's
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top 30 issues list, no consolidated action plan (including planned actions to address the issues to resolution and associated milestone dates) was available to plant management.
This impacted plant management capability to overview status and redefine resources and priorities on a timely basis.
Subsequent to the inspection, we understand that individual action plans will be developed for each issue and they will be reviewed by the Technical Review Committee and tracked by the Business Unit Plan.
This would provide a more effective means for managing the issues.
The individual plant examination (IPE) and probabilistic risk
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assessment (PRA) concepts were not being utilized in the routine plant decision process.
Several system engineers were not familiar with these terms.
LaSalle's IPE was submitted to the NRC on April 28, 1994 to meet Generic Letter 88-20 commitments. This submittal was actually the NRC's Risk Methods Integration and Evaluation Program previously performed on 1985 LaSalle Unit 2.
Due to several technical concerns that were expected to significantly impact the dominant sequences, the submittal indicated application of the analysis would be limited to narrow scope probabilistic evaluations.
It indicated an updated internal events PRA would be developed and periodically updated to reflect changes in equipment reliability, plant design, and operation.
However, the submittal did not indicate an expected time frame for this activity.
Subsequent to the end of the report period, Comed informed the inspector that a full PRA for LaSalle will be completed by the Fall of 1995.
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3.4 System Readiness Review Board (SRRB) Was Good Initiative; However, Improvement Opportunities Remained Comed's implementation of SRRBs successfully stressed to plant personnel the need to focus on system performance and in that respect was a good initiative. The system engineers considered them to be formal presentations for plant management's benefit to better understand known problems, conditions, and plans involving the systems. However, it did not appear that the review boards were being used to their fullest potential.
There was no clear correlation between information presented in the boards and actual management decisions with regard to the systems.
Conduct of the three SRRBs observed by the inspectors varied considerably.
The system engineers were very knowledgeable of their systems and answered most of the questions from upper management with ease.
However, some SRRBs highly emphasized possible solutions to high profile system problems while ignoring other evaluative items (such as total scope and effect of outstanding work or preventive maintenance adequacy) while others did just the opposite.
Several engineers said they had been provided no written guidelines for preparing for the SRRBs.
3.5 Increased Emphasis on Completing Work Assignments; However, Weaknesses in System Engineering Management Overview Remained Good initiatives were taken to address weaknesses in completing planned actions.
A periodic commitment status report was generated which included trending graphs of total action items open and number past due for each department.
These included nuclear tracking system (NTS), site quality verification, quality control, general information notices, business unit plan, and search for onportunity action items. The commitment status report was serving the purpose envisioned by plant management, changing the perception that due dates did not matter.
Items were being transferred from NTS to departmental work assignment databases. This was a good initiative to better enable supervisors to more closely manage resources, overview workloads, and set priorities.
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Part of the downward trend shown in the commitment status report was due
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to items being transferred to different tracking systems. Therefore, the report could not be utilized to accurately gage progress in reducing action item backlogs. However, because the number of overdue items remaining in tracking systems covered by the commitment status report was nearing zero, possible problems could be identified by any upward trend.
The inspectors identified the following concerns involving specific implementation details in system engineering (inspection scope was limited to that group):
There was no clear delineation of the t:pe of items contained in
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the commitment status report versus work assignment databases,
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resulting in inconsistencies.
Not knowing the general importance of items in a database co.uld hinder the management overview l
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System engineering management expected group leaders to be
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utilizing the system engineering work assignment database to overview system engineer work loads and set priorities.
However, Comed had not yet determined methods for utilizing the database to evaluate how well work assignments were being completed on a department basis.
System engineering management indicated plans to develop this overview capability. This was becoming of greater concern as more items were transferred out of NTS to the departmental database, some with potential significance.
For example, the inspectors randomly selected a five item sample (out of 20) system engineering NTS items closed in the previous two weeks.
Although closed in NTS, work on three of these items was not completed and the items were transferred to the system engineering work assignment database.
These were:
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A need for new control valves with anti-cavitation trim due to erosion causing recurring failures of valves and piping in various service water systems.
Difficulty in maintaining proper oil levels in large
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compressors which provided refrigeration for ventilation systems such as drywell cooling.
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Concerns that the weekly switchyard surveillance failed on a consistent basis due to numerous outstanding and old work requests.
The sample also included one item closed on NTS and the system
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engineering work assignment database without all requisite actions being completed.
This involved construction of an environmentally controlled enclosure for personnel manning the makeup demineralizer due to high ambient temperatures.
NTS status indicated this was closed out prior to the enclosure being constructed.
System engineering management indicated the item was
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closed because engineering work on the issue was complete and remaining actions were for other departments.
The inability to easily track an issue to completion was an impediment to good management overview capability and could contribute to an ineffective corrective action program.
3.6 Single Reactivity Management Nonconservatism The inspectors reviewed the core monitor code logs and identified that a group of rods were withdrawn from notch 6 to notch 14 resulting in the Maximum Average Planar Ratio (MAPRAT) linear heat generation rate reaching 0.999 on February 2, 1994.
Although the MAPRAT limit of 1.00
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was not exceeded, this practice of pulling groups of rods and not i
accounting for xenon burn-out had the potential to exceed core thermal
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limits.
Corrective actions included having the lead nuclear engineer communicate this event to other staff. The inspectors regarded this as an isolated incident.
3.7 Review of Licensee Event Reports (LERs)
The following licensee event reports were reviewed to ensure that reportability requirements were met, and that corrective actions, both immediate and to prevent recurrence, were accomplished or planned in i
accordance with the technical specifications:
(Closed) LER 373-94011 " Unit 1 Scram Due to a Feedwater Signal Spike,"
(Closed) LER 373-94010 " Scram due to Reactor Water Level Control Signal
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Loss to the IB Turbine Driven Reactor Feed Pump," and
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(Closed) LER 374-94006 " Reactor Scram Due to Spurious Opening of Main Turbine Bypass Valves."
In addition, recent problem identification forms (PIF) were reviewed in order to monitor conditions related to plant or personnel performance and to detect potential development of trends.
3.7 Followup on Previously Identified Engineering Items
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(Closed) Violation (373/93020-01(DRP)):
Several examples of failures to perform safety evaluations or provide adequate basis for conclusions.
Corrective actions involved training lesson plan revisions, conduct of additional training, and procedural changes.
These were completed and this item is closed.
(0 pen) Violation (373/93020-03(DRP)):
Failure to perform onsite review for control room radiation monitor modification.
Corrective actions were completed except for special guidance in a new modification procedure.
In a letter to the.NRC dated September 30, 1994, Comed revised the expected completion date to January 31, 1995.
This item will remain open pending review of the completed procedure.
(Closed) Unresolved Item (373/374/90004-01(DRS)):
This item pertained to not performing a test of the fire pumps at shutoff head during surveillances.
The inspectors agreed with the licensee that the shutoff
head test subsequent to initial installation did not have to be performed at the LaSalle Station to meet the current licensing basis.
The NRC previously documented this position in a letter dated April 24, 1984, from Mr. A. Bournia (NRC) to Commonwealth Edison Company, stating that the LaSalle Station is not required to test the fire pumps at shutoff pressure conditions.
In addition, the letter stated that the NRC would only hold the licensee accountable to the 1974
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edition of NFPA' code which was in effect at the time of design and erection of the facility. The LaSalle Station currently satisfies the intent of NFPA-20, 1974 edition, and this item is considered closed.
(Closed) Unresolved Item (373/93020-02(DRP)):
Review CamEd's safety evaluation on control room ventilation radiation monitor circuitry modification. This was a concern as Comed's analysis indicated control room habitability requirements could not be met during a design basis accident if the control room ventilation system was initially in the purge mode. Appendix A to Branch Technical Position APCSB 9.5-1,
" Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior
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to July 1, 1976," position A.4, " Single Failure Criteria," stated, Postulated fires or fire protection system failures need not be considered concurrent with other plant accidents or the most severe natural phenomena." Position D.4, " Ventilation," contains design criteria for systems to remove smoke and corrosive gases. As the purge mode of the control room ventilation system was to be utilized to remove smoke and gases from the control room, the plant design and licensing basis did not require the analysis to assume operation in this mode concurrent with a design basis accident. This item is closed.
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(Closed) Unresolved Item (374/94016-01(DRP)): Misorientation of flow measuring orifices.
This item is closed based upon the discussion in
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paragraph 3.2.
I One violation and no deviations were identified in this area.
4.0 PLANT SUPPORT (71750 and 92904)
On a routine basis, the inspectors toured accessible areas of the facility to assess worker adherence to radiation controls, the site security plan, fire protection, housekeeping, and control of field activities in progress.
The inspectors evaluated the involvement of
support organizations in assuring safe and effective plant operation.
l 4.1 Management Meeting - Improved Radiation Protection Performance, but Some
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Problem Areas Remained l
On October 6, 1994, NRC Region III personnel met with Comed at its Quad Cities Station to discuss the status of radiation protection (RP)
improvement efforts in response to past poor performance at the Dresden, Quad Cities, and LaSalle Stations.
LaSalle's RP program showed improvement since the previous management meeting on August 12, 1994.
However, the NRC emphasized that RP performance remained below average, improvements were somewhat slow and just getting underway, and the need for continued high level focus on this area was clearly indicated.
Although the collective exposure to LaSalle workers remained relatively high, the licensee presented the following comparisons between 1993 and 1994.
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A 40% dose reduction for the top 10 repetitive jobs.
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A 36% reduction in total outage dose.
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Non-outage daily dose was reduced from 1.29 to 0.366 rem.
The 1994 cumulative dose was expected to be less than the 750 person-rem goal.
There were a number of other performance problem areas that, although somewhat improved, remained significant. These included a high number of hot spots, contaminated areas, and events; high radiation area and radioactive material violations; and continuing radworker adherence problems.
Performance improvement depended on continued strong station management support and better RP/ALARA ownership by all departments.
4.2 Lack of Awareness of Site Quality Verification (SQV) Concerns on
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Continuing Radiation Protection Problems l
An SQV audit indicated continuing problems in the area of radiation protection and operator work-arounds in the radwaste area.
On September 28, 1994, SQV issued Audit Report Number 01-94-08,
"Radwaste/ Radiation Protection." The inspectors reviewed the audit and found it to be thorough and performance based.
During this audit, the auditors discussed radiation protection (RP) issues with various workers at LaSalle.
Through these discussions, the auditor concluded that
"nearly half of those queried did not think that LaSalle had a rad worker problem and that RP issues were blown out of proportion by regulators."
Discussions at the exit interview revealed that some senior managers were not familiar with this audit observation. The inspectors were i
concerned, considering the seriousness previously placed on this issue
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and extensive corrective actions taken, that this observation was not receiving consistent high profile attention.
4.3 Improved SQV Ability to Integrate Findings Into Broader Fundamental Issues A Level 11 finding was issued by SQV "for deficient instances in the conduct of radwaste operations" and " low priority assigned to radwaste j
equipment work requests which fostered a culture where operator work i
arounds are accepted." Similar concerns were raised in NRC inspection report 373/93020 (DRP) in 1993 and the licensee subsequently implemented a radwaste materiel condition committee. Although not necessarily as timely as it could have been, this finding indicated more broad scope thinking in SQV.
The inspectors will continue to monitor Comed's response to the findings and their performance improvement initiatives in this area.
4.4 Good Security Performance in the Central Alarm Station; However, Inadequate Knowledge of Problem Identification Process Performance of the security officers in the central alarm station (CAS)
was very good. The personnel in CAS were very knowledgeable of security
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systems, components, and component problems.
However, 50 percent of the individuals in CAS were not fully familiar with the process for activating the duress alarm. This function was not included in the security officer training program.
The officers were also observed obtaining information on an individual who alarmed a turnstile while exiting the protected area (PA). The investigation determined that the security computer had not properly
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read the individual's badge when that person entered the PA, earlier that day. The inspector asked a security supervisor how this event
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would be reported.
The individual was uncertain how this problem should be reported (such as a problem identification form (PIF) or security event report).
4.5 Change in Emergency Preparedness Coordinators i
On October 3, 1994, a new Emergency Preparedness Coordinator was assigned to the Generating Stations Emergency Plan (GSEP) program, as j
the previous coordinator resigned.
The new GSEP Coordinator was also
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responsible for Emergency Operating Procedures (E0P) until an E0P Coordinator was selected. As several concerns regarding the GSEP program were discussed in NRC inspection report 373/94013(DRP),the i
inspectors will continue to monitor performance in this area.
4.6 Followup of Previously Identified Items in the Plant Support Area (Closed) Inspection Followup Item (373/91014-01(DRSS)):
A dissolved oxygen monitor failed to meet the NUREG-0737' post accident sampling system (PASS) requirements as it was located downstream of the degassing system.
The probe was positioned upstream of the degasser in a pressurized sample line and is capable of measuring the dissolved oxygen concentration of a liquid sample under accident conditions. This item is closed.
(Closed) Inspection Followup Items (373/92014-01(DRSS);
i NRC and had their vendor laboratory analyze for H'plit sample for the(tritium), Fe 374/92014-01(DRSS)):
Comed prepared a fuel pool s Sr" (strontium), Sr", gross a, and gross B.
Comparisons could not be
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made with the NRC reference laboratory data as low sample activity k
resulted in poor counting statistics.
This item is closed.
j (Closed) Unresolved Item 373/94016-05(DRSS); 374/94016-05(DRSS): This item concerned Standby Gas Treatment System (SGTS) operability.
In 1985, the charcoal absorbers in the SGTS Units 1 and 2 filtration beds were wetted by fire protection deluge system (FPDS) leakage. Bed j
samples were later tested that same year. The samples tested subsequent to these wetting events contained charcoal from the sample canisters.
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Because of their physical configuration, the charcoal in the canisters
- Clarification of TMI Action Plan Requirements
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i appeared unlikely to have been exposed to the same wetting as the beds and, thus, might not have been representative of the bed charcoal.
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Comed committed to retest the beds with methyl iodide penetrant to determine SGTS operability and to replace the bed charcoal with new charcoal, since the charcoal canisters were fully depleted and the bed
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charcoal was significantly aged and weathered.
The methyl iodide laboratory tests of the used charcoal beds and the one
remaining canister showed that both SGTS trains had significantly degraded charcoal; however, because of the eight-inch depth of the beds, they met the technical specification acceptance criterion and were operable.
The canister charcoal showed a somewhat greater degradation than the bed charcod.
During.a review of the test results, the inspector identified that the charcoal tests for both units had been conducted at a face velocity of 40 feet per minute (fpm), rather than the procedurally required 20 fpm.
This error was conservative, an isolated problem and did not effect the SGTS operability determination.
Comed issued a PIF and began corrective action to prevent recurrence by procedurally requiring that the charcoal face velocity for all filtration systems be specified in the purchase orders for all future methyl iodide laboratory tests.
Comed found no visual damage to the bed charcoal or the filtration housing internals for the Unit 2 SGTS train.
However, during the visual inspection of the Unit 1 SGTS train, Comed discovered that, directly below the deluge line, the FPDS was slowly leaking water onto the charcoal bed. This process had apparently been going on for some time since not only was the charcoal wetted, but the water and the potassium
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iodide in the charcoal had formed an acid that damaged a portion of one of the metal screens which held the charcoal in place. No charcoal was lost from the bed.
The metal screen mesh and the FPDS leakage were i
repaired before new charcoal replaced the wetted charcoal bed.
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also previously wetted by their FPDS, Comed planned to visually inspect i
the condition of the charcoal bed and deluge system for each filtration i
housing during the next scheduled charcoal test. After the end of the inspection period, problems were found in the control room ventilation
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system charcoal bed.
Since both as-found SGTS trains were 0perable and corrective action to prevent recurrence of problems found during the charcoal tests were initiated, this item is closed.
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No violations or deviations were identified in this area.
5.0 MANAGEMENT MEETINGS (40500)
5.1 Preliminary Inspection Findings (Exit)
The inspectors contacted various licensee operations, maintenance, engineering, and plant support personnel throughout the inspection period.
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At the conclusion of the inspection on October 7, 1994, the inspectors
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met with licensee representatives (denoted below) and others and summarized the scope and findings of the inspection activities. The licensee acknowledged the inspector's comments. The inspectors also discussed the likely informational content of the inspection report with i
regard to documents or processes reviewed by the inspectors.
The licensee did not identify any such documents or processes as proprietary.
D. Ray, Plant Manager D. Leggett, Operations Manager J. Dedin, Assistant Operations Superintendent R. Shields, System Engineering Supervisor J. Abel, Site Engineering and Construction Manager D. Farr, Technical Services Superintendent L. Gerner, Regulatory Assurance Manager J. Lewis, Health Physics Services Supervisor J. Giuffre, Mechanical Maintenance Master B. Bejlovec, Instrument Maintenance Supervisor J. Gieseker, Business Unit Plan Manager K. Kociuba, Master Electrician
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5.2 Additional Management Meetings On October 6, 1994, a meeting was held with the licensee to discuss the status of radiation protection (RP) improvement efforts in response to past poor performance.
The licensee was represented by the RP Managers from the Dresden, Quad Cities, and LaSalle Stations.
Mr. W. Axelson, Director, NRC Region III Division of Radiation Safety and Safeguards, represented the NRC.
The LaSalle portion of this meeting is discussed in more detail in paragraph 4.1.
6.0 DEFINITIONS 6.1 Inspection Follow-up Items Inspection followup items are matters which have been discussed with the licensee which will be reviewed further by the inspectors and which involve some action on the part of the NRC or licensee or both. An inspection follow-up item identified in this report is discussed in the attachment to this report.
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NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-373/94017(DRP); No. 50-374/94017(DRP)
Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Licensee:
Commonwealth Edison Company Executive Towers West III 1400 Opus Place, Suite 300 Downers Grove, IL 60515 Facility Name:
LaSalle County Station - Units 1 and 2 Inspection At:
LaSalle Site, Marseilles, IL 61341 Inspection Conducted:
August 8 through October 7, 1994 Inspectors:
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R. Schweibinz, Lead Inspgdtor Date O. S. Mazzoni (Contractor)
S. A. Traiforos (Contractor)
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[O ' 28-N R. (/ Gardner, Chief Date Plant Systems Section Inspection Summary Inspection on August 8 through october 7, 1994 (Reports No. 50-37 3 / 94 017 (DRP) : No. 50-374/94017(DRP))
Engineering inspection in accordance with NRC Inspection Procedure 37550.
Results: Overall, the inspectors determined that Engineering performance was good.
Modifications reviewed contained adequate design control and well documented safety evaluations (Section 3.1.1).
Effective communications between engineering and other organizations resulted in the identification and resolution of plant problems (Sections 3.3.2.2, 3.3.2.4, and 3.3.2.5).
However, the inspectors identified a number of concerns which require continued management attention (Section 3.1).
Four previously identified inspection items were closed (Section 2.0).
One inspector follow-up item (Section 3.1.5.1) requiring further NRC review was identified as a result of this inspectio.
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DETAILS l
1.0 Persons Contacted i
Commonwealth Edison Company
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- J. Abel, Manager, site Engineering
- J.
Gieseker, BUP Manager
- J.
Arnould, Staff Engineer
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Sunoort Encineerina
- J. Miller, Site Engineering Supervisor
Bohan, Site Engineering Electrical M.
Sharma, Site Engineering Electrical
M. Wendling, MOV Engineer W. Siwiec, Leak Rate Engineer
- M. Oclon, Site Engineering Programs Lead M. Smith, Check Valve /AOV Engineer D.
Gullott, ISI Engineer
- S. Brown, Site Engineering / Issues Management A.
Kelley, Site Engineering Systems Enaineering
- R. Shields, Systems Engineering Supervisor T. Hammerich, System Engineering, Mentor H. Vinyard, Assistant System Engineering Supervisor
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R. Grumcheck, System Engineering P. Sampson, System Engineering Performance Group Leader
- M. Cooper, System Engineering Root Cause Group Leader J. Sparacino, System Engineering T. Kolross, D/G System Engineering Modification Desian H. Musser, Design Engineering Mechanical Lead
i R. Friedrich, Design Engineering J.
Borm, Design Engineering Site Ouality Verification (SOV)
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- E. Martin, QV Director
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McIntyre, Audit Supervisor
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Kluge, ISEG Engineer
- C.
Laskey, QV Inspector
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Reculatorv Assurance
- M. McInerney, NRC Coordinator
- B. Adams, NETS, MOV Issues
Denotes those present at the status briefing on September 2, 1994.
Other persons were contacted as a matter of course during the inspection.
2.0 Licensee Actions on Previous Inspection Findinos 2.1 (Closed) Open Item (50-373/92015-01; 50-374/92015-01), three issues on check valves.
The first issue concerned the generic exclusion of two inches in diameter and smaller check valves from l
the check valve program without addressing criteria such as system cleanliness, operational frequency, chemical stressors, or component wear.
The second issue was that the corporate directive NOD-TS.9 allowed the use of the IST program testing as an indicator of check valve degradation in lieu of preventive i
maintenance.
The third issue identified several containment l
isolation valves greater than two inches in diameter that were in
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the IST program, but not included in the check valve program.
The inspectors reviewed the licensee's closure of these issues I
and concluded that they had been addressed in a timely and satisfactory manner.
This item is closed.
2.2 (Closed) Violation (50-373/91019-01B; 50-374/91019-01B),
failure to include Non-Technical Specification Safety Related Relays in the Station's Calibration Program.
Licensee actions were detailed in AIR 373-100-91-01901B, summarized as follows:
Generation of a listing of all relays that were required to be included in the calibration program, completion by 2/15/93.
Development of acceptance criteria, completion by 02/19/93.
Generation of procedure LTP-100-6, approval by 03/31/93.
Testing of ali says, completion by refueling outages L2R05 and L1R06.
The inspectors found the above listed corrective actions to be adequate to resolve the finding, and verified that they had been performed.
This item is closed.
2.3 (Closed) Unresolved Item (50-373/91019-06; 50-374/91019-06),
4160 V Degraded Voltage.
In response to the EDSFI finding, the licensee took compensatory measures and instituted corrective
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actions, as described in AIR 373-100-91-01906.
The inspector verified that the corrective actions taken were adequate to address the concerns of the finding.
The inspector also verified that the corrective actions were being properly implemented.
The only corrective actions with pending inplenentation were those related to 120 Vac circuits, where alternate solutions were being evaluated for cost impact.
Implementation of these corrective actions was projected for seventh refueling outage of each unit.
This item is closed.
2.4 (Closed) Deviation (50-373/91019-05D; 50-374/91019-05D),
failure to establish a formal setpoint methodology for the degraded voltage relays to address all known instrument errors.
In response to the EDSFI finding, the licensee established corrective actions, as described in AIR 373-100-91-01905D which included the implementation of a formal setpoint procedure to account for all possible errors.
Other corrective actions included the installation of an improved relay, to reduce errors in the detection scheme.
Preliminary calculations were performed for the calculation of the relay setpoint, taking into account possible errors.
A final calculation was planned to be issued by tho seventh refueling outage of each unit.
The inspector found that the corrective actions and their implementation were adequate for resolving the finding.
This finding is closed.
3.0 Introduction The purpose of this inspection was to evaluate the effectiveness of the Engineering organization in the performance of routine and reactive site activities, including the identification and resolution of technical issues and problems.
This inspection focused on system engineering functions, modifications, temporary design change activities, operability evaluations, equipment trending, technical problem resolution, and engineering support to other plant organizations for the following categories:
Extent and quality of Engineering involvement in site activities.
Engineering Support to Other Organizations Self assessment and improvement initiatives.
Extent and effectiveness of site Engineering communications.
The criteria used to assess the Engineering performance was quality of technical work produced, understanding of plant design, and proactive involvement.
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3.1 Extent and Ouality of Engineerina Involvement in Site Activities
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The inspectors concluded that the extent and quality of Engineering involvement in site activities was generally good.
However, the inspectors identified a number of concerns which require continued management attention.
These concerns include:
the use of a 50.59 evaluation form that did not request a reason for the change (the previous form was modified (3.1.1.1));
a lack of attention to detail in some TSC packages (3.1.1.2);
slightly less than adequate corrective action to a good finding (3.1.2.3);
no procedural requirement for evaluation and documentation by engineering, of the root cause or reason for an identified problem unless it had been identified in a PIF (3.1.5.1);
system engineers were aware of the intent that they become System Managers, but they were unclear as to what actions this role cntailed (3.1.6);
the delay in implementing the commitment that coordination of the Preventative Maintenance program be assigned to System Engineering (3.1.6);
and, many SQV findings took a year or longer to close with multiple extensions (3.3.1).
3.1.1 Modification Process The inspectors concluded that the modification process was generally effective.
This included major and minor modifications, exempt changes, and temporary system changes.
Design controls were adequate, safety evaluations per 10 CFR 50.59 were complete and well document <2d, and post-modification testing was effective.
Those packages reviewed for which the inspectors had no comments are listed in Section 5.0.
No significant concerns were identified with the packages reviewed.
However, management attention is needed in several areas as described in Section 3.1.
3.1.1.1 Exempt Changes (EC)
EC 01-94-945: This EC replaced the reactor recirculation water chemistry sample stop valve 1B33-F059 because it had developed
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through-seat leakage resulting in failure of the leak rato tests of adjacent containment isolation valves.
Work Request (WR)
105734 was written on February 25, 1991.
It was explicitly stated in the modification package that the reason for the replaced valve leakage had not been identified.
This is further discussed in the root cause evaluation section of this report.
The valve was replaced with a different type of valve during lLR06 (EC approval letter was dated March 24, 1994).
Even though the licensee provided t'ae inspectors with a written explanation for the reasons for thr. delay in performing this EC, the inspectors were concerned that a non like-for-like valve substitution appeared to be the result of inadequate planning for the replacement.
Non like-for-like replacement required engineering evaluation which could have been avoided.
In addition, the new valve was not a bellows sealed valve.
This could result in premature (small) leakage to the drywell.
Finally, in reviewing EC E01-1-94-945 the inspectors and the licensee could not identify records of review of this EC by the Technical Review Committee (TRC).
This issue has been recently addressed formally by the licensee through the issuance of a new LaSalle county station policy guideline, LSCS P.G. No.
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" Business decision making process", revision 0, dated.Tene 6, 1994, which required that all design changes be reviewed by the TRC.
This policy guideline served as LaSalle station's implementing procedure for the TRC/BRC (business review committee) process.
EC 94-988: This EC implemented stellite hardfacing and machining of the disc angel wings of the reactor recirculation discharge block isolation valve 1B33-F067B to eliminate binding.
The modification approval letter addressed the addition of stellite hardfacing to the disc wings with respect to the station's cobalt reduction program.
Even though it was acknowledged in the letter that the approximate 500 grams of stellite added within the primary coolant system was significant, it was argued that the stellite wings would not be in the main flow path thus reducing the amount of stellite which could be removed by the coolant.
However, corrosion of the stellite material would still result in the release of some quantity of cobalt.
The inspectors observed that there was no documentation in the modification package or the modification approval letter regarding any considerations for use of alternate materials.
Hcv2ver, during the inspection the licensee provided documentation which demonstrated that alternate materials had been considered but their use had not been recommended by the valve aanufacturer (Atwood-Horrill).
EC 93-979A1 This EC replaced the 2x4" expander and 90 degree elbow of carbon steel located one foot downstream of the Residual Heat Removal (KHR) service water strainer 2E12-D300A backwash piping 2RH90AA-4", with stainless steel reducing elbow.
The inspectors observed that even though calculations were not included in the EC package, they had been performed and were
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consistent with procedure LTS-600-20, Conduct of LaSalle Erosion / Corrosion Inspections.
EC 94-903A: Remove Unit 1 250Vdc charger (Equipment #1DCO3E)
Float / Equalizer Timer - Approved Completion April 21,1994.
The 50.59 evaluation form, item f, (LAP-1200-13, Rev.5, March 4, 1994) did not request a reason for the change.
This was a departure from the previously utilized 50.59 form, the form in use at the Downers Grove office, which specifically requested the reason for the change be stated (Ref:
Exhibit E ENC-GE-06.1, Rev.
5, item 2).
The licensee explained that the form being used at LaSalle (LAP-1200-13) was developed from ENC-QE-06.1.
In response to the inspector's finding, the licensee agreed to process a " Procedure Deficiency Sheet", due January 1, 1995, for modification LAP-1200-13, to include a short description as to why the associated change activity was being done.
The inspector found that while the individuals personally involved in the preparation of the modification would be expected to be quite knowledgeable of the reasons for the change, the independent reviewer's task would be hindered by the lack of documentation of these reasons.
In addition, in the development of the LAP-1200-13, 50.59 form, the licensee deviated from its own established approach of Exhibit E ENC-QE-06.1.
Since the issue relates to the generic form of the 50.59 evaluation, it would affect all modifications performed under this type of form.
However, in establishing adequate corrective action, the licensee showed a good t.pproach in addressing the problem.
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EC 93-959: Non-safety-related modification performed for the removal of the station auxiliary transformer (SAT) low voltage side surge arresters.
The removal of the surge arresters created a condition which could potentially endanger the integrity of safety connected equipment, since the surge arresters would dissipate surges that travel through the transformer.
The inspector questioned the approaches used by the licensee in the areas of justification and support of assumptions, adequacy of design input data, and proper independent verification.
The inspector found that there appeared to be no calculation performed to evaluate the magnitude of the surge that would travel through the transformer.
The evaluation reviewed was contained in a Sargent & Lundy letter, SCE-7009, dated September 17, 1993.
Subsequently, the licenses produced an Interoffice Memorandum dated october 7, 1991, which attached a " white paper" that provided numerical data to back up its conclusion that surges entering the auxiliary system are attenuated to a level that is not expected to expose any auxiliary equipment to overvoltages requiring surge protective measures.
The inspectors have no further questions in this regard.
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3.1.1.2 Temporary System Chances (TSC)
TSC-2-0198-94: This non-cafety-related TSC was made to throttle valve 2E51-F049 which is downstream of the RCIC barometric condenser vacuum tank condensate pump, to reduce the current drawn by its motor.
This change was made on March 5, 1994.
Some analysis of the effect of this change was performed by site engineering but it was not documented.
A 50.59 Evaluation for the TSC was performed prior to the change without the benefit of a documented formal analysis.
Chron # 301880, dated May 16, 1994, discussed the review of related Problem Investigation Forms (PIFs) 374-201-94-00517 and 374-201-94-531 and based on analysis recommended throttling the valve, an action which had already been performed on March 5, 1994.
In addition, draft revisions of relevant documents and procedure LES-DC-104 which were used for testing DC motors, with their safety evaluations, were submitted for approval on July 9, 1994, but had not as yet been approved (five months following installation).
On August 20, 1994, as a result of the inspector's observations, the licensee completed a procedure deficiency sheet to revise procedure LES-DC-104.
Lack of Attention to Detail in some TSC Packages The inspectors observed a lack of attention to detail in some of the TSC packages reviewed.
For example, drawing number was not included in Attachment A, LAP-810-11, of TSC 2-0198-94.
In addition, TSC nunber was missing from Attachment A, LAP-810-11, and Attachment A, LAP-1200-13 of TSC 1-933-94.
Moreover, inconsistent safety classification was detected within TSC 2-0798-93 package.
Exhibits B and C, ENC-QE-60, stated SR (Safety Related) while both S&L evaluation and licensee's EC approval letter stated non-safety related.
Finally, safety classification in Attachment C, IAP-1200-13 (non-safety related) was inconsistent with the classification in the summary TSC listing provided to the inspectors (safety related) for TSC 1-933-94.
The inspectors reviewed the 50.59 evaluations associated with the reviewed modification packages, exempt changes and temporary modifications and did not identify any problems.
3.1.2 Licensee Event Reports One aspect of the review of root cause analyses and identification of repetitive and significant problems was performed by the review of eight Licensee Events Reports (LERs).
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The description of the issues found by the inspectors is provided as follows:
3.1.2.1 Automatic Bus Transfer The inspectors reviewed LERs 373/93-015, 374/89-007, and 373/87-014 as they relate to bus transfer operations, to determine their adequacy.
LER 373/93-015 indicated that a relatively long voltage transient (voltage at less than 72% for at least 200 ms, or over 12 Cycles) occurred during the event.
The inspectors were concerned that the long voltage transients reported in the LERs could indicate problems with the bus transfer operation and subsequent high transient torques that could be generated on the safety related motors.
The effect of high transient torques on the motor shafts would be cumulative in nature, such that shaft damage may not become evident for some period of time after the occurrence of the onset of the initial stresses, and only become evident after a number of successive events of transient torques.
In response to the inspectors' questions, the licensee analyzed the operation of the bus transfer during the 1993 event, and demonstrated that it had occurred in less than 8 milliseconds (as described in the FSAR).
The inspectors found that the only equipment with capabilities of capturing transient events in enough detail to provide some analysis was the Hathaway Sequence of Events Recorder.
The inspectors found that this recorder had limited memory capabilities and could not provide all pertinent information required to analyze electrical transients, such as fast bus transients.
The licensee presented their approach to possible improvements.
3.1.2.2 Continuity of Service to 480 Volt Busmag LER 374/94-004 describes an event on June 21, 1994 where a scram was caused by the loss of electrical power to critical loads fed off busses 231A and 231B.
Despite this event, the inspector found no objective evidence of any study to consider the upgrading of continuity of service for the critical loads.
In response to inspector's question the licensee issued an
" Assignment Status Report, Index #702".
The " Assignment Description" is the investigation of possible reclosing schemes for bus feed breakers for balance of plant busses which could cause a unit trip.
3.1.2.3 Testing of Safety Relief Valves LER 373/94-008, Testing of Standby Liquid Control System Pump Discharge Safety Relief Valves.
The inspectors identified some problems with this LER and relevant PIF 373-180-94-01448.
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documents addressed a recent review of old (1985) data sheets which indicated that procedure LTS-600-10, rev.
2, Safety and Relief Valve Inservice Test, which removed the valves from the system and tests them on the bench, allowed for a higher set point for relief valve 1C41-F029A than allowed by technical specifications (1400 psig).
This error in procedure was corrected in rev.
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The inspectors observed that even though the above PIF attributed the problems to both procedural and personnel errors, the LER incorrectly attributed the problems to personnel errors only.
Moreover, the inspectors observed that the above PIF and LER did not require under " corrective action" the review of current revision of LTS-600-10 to ensure that a similar problem did not exist with relief valves of other plant systems, and the set point values in LTS-600-10 are consistent with the design values for all relief valves.
In response to the inspectors request, the licens*1 verified that the only other relief valves referenced in the Technical Specifications were the Main Steam Safety Relief Valves and their settings were consistent with LTS-600-10.
However, in comparing set point values to design basis values, a discrepancy of 2 psi was identified for the High Pressure Cooling System (HPCS) diesel generator cooling water system relief valves 1(2)E22-F345 with LTS-600-10 using as acceptance criterion 152+4.5 psig while design drawings indicated 150+4.5 psig.
PIF 373-201-94-01978 was written on September 1, 1994, to correct the problems.
An operability evaluation ENC-QE-40.1 was performed on September 2,
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1994, and the relief valves were declared operable.
3.1.3 Adecuacy of Encineering Support Informal interviews were held with selected plant personnel to determine the adequacy of engineering support.
The personnel contacted were found to be capable of performing their assigned function, highly motivated, and well qualified in terms of technical capability.
The inspectors found that there was excellent support provided to answer the questions, and that the ability to retrieve information was very good.
3.1.4 Methods Used to Address outside or Industry Information The inspector reviewed the approach to address items such as generic letters, information notices, 10 CFR 21 notifications, vendor notifications, GE Operating Experiences, etc.
Regulatory Assurance is responsible for the receiving, routing, and logging of the documentation.
The Assignment Status Report is utilized for tracking purposes.
The inspector found that the licensee program for the review of industry information was adequately
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O structured and insured that proper review would be provided by the involved disciplines.
3.1.5 Encineerina Assistance in Identifyina Causes and Innlementina Corrective Actions 3.1.5.1 Root Cause Evaluation The inspectors' review of the licensee's root cause evaluation program revealed that the licensee has made a substantial effort in addressing root cause.
However, the inspectors found that there was no procedural requirement for evaluation and documentation by engineering, of the root cause or reason for an identified proolem unless it had been identified in a problem identification form (PIF).
For example, as discussed in the review of EC E01-94-945, it was stated in the modification package, by both the licensee and its contractor, Sargent &
Lundy, that the reason for the replaced valve leakage had not been identified.
The licensee stated that the reason for an identified problem or failure had been documented in the majority of cases through Technical Review Committee (TRC) discussions, in modification approval letters, etc.
However, the inspectors could not identify any requirements for root cause or reason for failure review.
Moreover, the licensee indicated that the " work causes" entry in the Work Request (WR) procedure (LAP-1300-1) was one of the mechanisms for documenting the cause for performing the work.
The inspectors observed that the " work cause" was completed by maintenance personnel only if the WR was performed as corrective maintenance and marked as such in the appropriate entry of this form.
The inspectors observed that even though the work causes were helpful, in many cases they were not detailed enough to address the underlining real causes.
More importantly, there was no requirer ent for engineering to assist in assigning a " work cause."
Regarding the recent effort to implement the Electronic Work Control System (EWCS), the inspectors' review of systems engineering anticipated involvement revealed that it emphasized post-maintenance testing and work history after the work was performed.
While they are required to review work requests before the work is performed, there still appears to be no explicit requirement for system engineers to review work requests for root cause identification (or reason for failure) prior to performing the work.
System Engineering involvement in review of items in the EWCS prior to performing work is an inspection follow-up item (373/94017-02; 374/94017-02).
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3.1.5.2 Procedure LES-DC-104 and ESO-199 As discussed in Section 3.1.1.2 regarding TSC 2-0198-94, procedure LES-DC-104 was used for testing DC motors.
A note in Attachment B of this procedure stated that the DC motors running currents, that is the full load current (FLI), were given for
" convenience only" and that the acceptance criteria should be verified against the Equipment Setting Order (ESO) ESO-199 which is a controlled document.
In response to the inspectors'
request, the licensee compared the FLI values in the procedure with the ESO-199.
All of the values in the procedure were verified as correct with the exception of motor lE51-C004.
For this motor the FLI was indicated in the procedure as 11.5 amps while it was specified as 10.98 amps in ESO-199, which had been revised as a result of DCR 93-032.
The licensee verified that the tested value was 8.78 amps which met the ESO-199 stated value.
However, as a result of this finding and EC 2-0198-94, the licensee completed on August 20, 1994, a procedure deficiency sheet to revise procedure LES-DC-104.
3.1.6 System Encineerina While some observations were identified in the System Engineering area, our evaluation of this area will be discussed in more detail in the next inspection period.
Most system engineers interviewed were very knowledgeable of system design, operation, and current status.
They were effectively utilizing counterparts at other non-Comed facilities for information on their systems.
Although they were not controlling maintenance on their systems, they did have some influence.
Soc.c extraneous work activities were removed from system engineer responsibilities, with mixed success, so they would have more time to concentrate on long term system improvement.
System engineers were aware of the intent that they become System Managers, but they were unclear as to what actions this role entailed.
It appears that plant management had not yet clearly defined their expectations in this area.
For example, equipment monitoring data (such as vibration trend data) was not consistently reviewed by system engineers.
The inspectors evaluated the status of the system engineering program with respect to the ability to influence plant equipment materiel condition.
This included a progress review of some commitments in the licensee's response dated April 1, 1994 to inspection reports 93026 and 93035.
One of the commitments, as
,y described in that correspondence, included " Coordination of the c
Proventative Maintenance program is joing assigned to System Engineering.
Actians are already be;.ng taken for transfer of p
this responsibilitf."
However, systen engineers did not yet
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consider overview of the PM program for their equipment as their responsibility.
Although they had affected some PM program
changes in response to specific failures and problems with their equipment, they had, for the vast majority, not performed a systematic review of PM activities on their systems.
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3.1.7 Enqineerina Responsiveness to Site Ouality Verification The inspector's review of several audit reports for 1992, 1993, and 1994, and followup correspondence indicated that responses to audit findings did not, in many cases, meet the requested response time, and extensions were granted.
Many findings took a year or longer to close with multiple extensions (Section 3.3.1).
3.2 Encineerina Support to Other Oraanizations
The inspectors reviewed additional aspects of engineering's support to maintenance and operations to assess its scope and effectiveness.
Examples and conclusions from this assessment follow.
3.2.1 Enaineerina Sunnort to Maintenance The inspectors evaluated the involvement of engineering in the development and implementation of predictive and preventive maintenance.
The predictive and preventive maintenance activities at LaSalle have been evolving over the last few years.
They were coordinated by the performance monitoring group of systems engineering and consisted of the following programs:
vibration monitoring check valve acoustic monitoring lube oil analysis thermography program thermal performance system readiness review reliability centered maintenance (planned implementation 1995)
development of data access / analysis In addition, plant support engineering was responsible for the following programs:
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check valve, motor operated valve, relief valve, air operated valve, and erosion / corrosion Some activities were supported by other departments.
For example, the< system material analysis department (SMAD) performs the lube oil analysis.
One apparent weakness identified by the inspectcrs was that while the licensee was attempting to address predictive and preventive maintenance, there appeared to be no
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documented guidance given to the performance monitoring engineers for the analysis of results and feedback to the system engineers.
3.2.2 Enaineerina Support to Operations The inspectors determined that engineering support to operations was good.
The majority of inspector observations in this area have been during responses to events, such as Unit trips, and the RCIC rupture disc event.
Interviews with operators indicated that engineering was supportive in solving system problems as well as making improvements to the systems (Section 3.3.2).
Engineers were observed to be actively involved in operability determinations and assessment of events.
3.3 Self-Assessment and Imorovement Initiatives j
3.3.1 Self-Assessment
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l The inspectors concluded that self-assessment of engineering activities by the site Quality verification (SQV) organization was effective, performance based, and identified potential problem areas to management.
Several audit reports for 1992, l
1993, and 1994, and followup correspondence were reviewed.
The audits appeared comprehensive.
One observation _however, was that responses to audit findings did not, in many cases, meet the requested response time, and extensions were granted.
Many findings took a year or longer to close with multiple extensions.
Despite the SQV Level 1 corrective action finding in the
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beginning of 1994, review of corrective action report (CAR)
i 01-94-042 indicates the practice of not meeting the requested
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response dates continues in July 1994.
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3.3.2 Encineerina Imorovement Initiatives
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3.3.2.1 Technical Review Committee (TRC)
i The inspectors attended one TRC meeting held on August 15, 1994.
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The inspectors observed that presentations and technical
discussions were complete and thorough.
The ranking of l
modifications and exempt changes was carefully reviewed and in i
some cases new rankings were assigned.
However, the inspector observed that some engineers had not thoroughly investigated what
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other plants had done in resolving similar issues and, as such, lessons learned from industry's experience were not fully i
utilized.
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3.3.2.2 Use of Robots to Reduce Dose i
The licensee has an ALARA Robotics Committee which has been active in the use of robots to reduce dose.
In early September l
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they used a maintenance inspection and surveillance robot (MISR)
that they received from Dresden to perform an inspection in the low pressure heater bay.
The inspection of two heater drain valves that were not operating properly was estimated to take about 30 minutes with a resultant dose of 80 mrem.
The MISR is a tracked robot that is controlled by a coaxial cable and has the ability to go up to 200 feet into an area.
It is equipped with a boom mounted high resolution color camera with audio that can be raised up to 11 feet.
The inspections were performed with a total exposure of 4 mrem.
It has been used several times since then with similar results.
3.3.2.3 Systems Enaineerina Involvement in the Electronic Work Control System (EWCS)
The licensee recently put the EWCS in operation at LaSalle.
One of the goals of this system was to enhance work control through automation.
The inspectors reviewed Systems Engineering anticipated involvement in EWCS.
This consisted of reviewing corrective action requests, and reviewing and approving post maintenance tests and work histories.
Because of the developmental stage of EWCS, the inspectors could not adequately assess engineering's contribution.
However, the inspectors found that one added benefit of the EWCS was that it allowed a reconsideration of the role of engineering in the work process.
3.3.2.4 Post Scram Control Rod Position Indication The licensee implemented a modification to the control rod position indication that is provided by the rod worth minimizer for Unit 1.
This was done to resolve a common BWR problem of lost position indication after a reactor scram.
Hot control rods become slightly longer than normal and may travel slightly beyond the sensing range of the magnetic reed switches.
This generally results in several rods losing position indication after a scram.
Because of the capabilities of the LaSalle control rod position indicating system, Comed designed, developed, fabricated, and installed an interface circuit that would capture the good, full-in indication of the control rods.
This represents a good application of a proactive engineering approach to resolve a long standing industry problem.
3.3.2.5 Operations Degraded Equipment Loq (DEL 1 Support Engineering developed a PC based DEL for control room personnel, to simplify and improve administrative tracking of degraded equipment.
The DEL is also available to other plant personnel through the licensee's local area network (LAN).
This database is being offered to the other Comed sites.
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o 3.4 Extent and Effectiveness of site Enaineerina Communications Good communication and coordination were observed between engineering and operating, radiation protection, and maintenance, in their response to events and day to day activities.
4.0 Status Briefing The inspectors conducted a status briefing on September 2, 1994, at the LaSalle County Station to discuss the major areas reviewed during the inspection, the strengths and weaknesses observed, and the inspection results.
Licensee representatives in attendance at this status briefing are documented in Section 1.0.
The inspectors also discussed the likely informational content of the inspection report with regard to documents reviewed by the inspectors during the inspection.
The licensee did not identify any documents or processes as proprietary.
i 5.0 Additional Packaces Reviewed Maior Modification Packaces M01-1-87-095: Line up Reactor Coolant Isolation Cooling (RCIC) to the Suppression Foci (SP) in the event that the RCIC suction and return lines to the Condensate Storage Tank (CST) failed.
M01-2-93-022 and -023: Disconnect the reference legs of fuel zone l
level transmitters from their condensing chambers and connect them to the reference legs of the wide range transmitters.
This
modification would provide for additional post accident level
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indication.
M-1-1-87-098-08: Correct the problem of rotational resistance of
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Emergency Core Cooling System (ECCS) testable check valves during j
low flow conditions.
M01-1-91-009: Removal of electronic overspeed trip for RCIC for Unit 1.
M01-2-91-009: Removal of electronic overspeed trip for RCIC for
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Unit 2.
M01-1-89-013A: Replace Unit 1 Turbine Driven Reactor Feed Pump Speed Control System with a digital TDR FP Speed Control System.
Minor Modification Packaces P01-1-91-555: This modification replaced the actuator motor for Motor Operated Valve (MOV) 1E12-F049B from a two ft-lb to a five ft-lb.
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e P01-1-92-517: Replace contactor coil and add an interposing relay in the HPCS DG Room Vent Fan 1VD01C control circuit in MCC 143-1, compartment 4E.
P01-2-92-512: Replace degraded voltage relay.
P01-1-91-555: Replace 2ft-lb motor with a Sft-lb motor (GL 89-10 program).
Exempt Changes (EC or ECR)/ Set Point Changes (SPCR)
EC 94-903C: Remove Unit 1 250V dc. charger (Equipment #1DCO3E)
Float / Equalizer Timer - Approved Completion March 29, 1994 EC 94-946C: Change RPS Circuit Breaker EC 93-988: Replace pressure switch 2C71-N003A for turbine first stage LP scram and EOC RPT scram.
EC 93-986A: Install anti-hammer circuit for MOVs 1(2)FWO18.
EC 94-947: Addition of a safety related varistor in parallel to the RCIC Thermal Overload Byp?.49 Relay "KX1".
EC 92-916: Rewire torque and limit switches ECR 93-902A: Change the high voltage terminal taps for safety related 4160/480V transformers feeding buses 236X and 236Y.
ECR 93-902C: Change the high voltage terminal taps for safety related 4160/480V transformers feeding buses 135X and 135Y.
ECR 93-978: Install anti-hammering circuit in closing circuit of MOV 2E12-F021.
SPCR 93-036: Change breaker calibration from 20'C base temperature to 40*C base temperature.
Temocrary System Chances (TSC)
TSC-2-1002-90: Unit 2B Diesel Generator Fuel Priming Pump Logic Change TSC-2-0403-92: Connect auxiliary contacts from the Unit 2B Diesel Generator output breaker in series with the Reverse Power Relay
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