IR 05000327/1994009
| ML20029E057 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 05/02/1994 |
| From: | Holland W, Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029E055 | List: |
| References | |
| 50-327-94-09, 50-327-94-9, 50-328-94-09, 50-328-94-9, NUDOCS 9405160192 | |
| Download: ML20029E057 (30) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION o
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j',e REGloN 11 3*
101 MARIETTA STREET,,i W SUITE 2900 ra
- - j ATLANTA, GEORGIA 30323-0199
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Report Nos.:
50-327/94-09 and 50-328/94-09 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:
50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name:
Sequoyah Units 1 and 2 Inspection Conducted: March 6 through April 2, 1994 Lead Inspector:
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W. C Hollanq, Senior Gesident Inspector Date Signed Inspectors:
S. M. Shaeffer, Resident Inspector, Sequoyah G. A. Schnebli, Resident Inspector, Browns Ferry R. D. Starkey, Resident Inspector, Vogtle R. A. Musser, Resident Inspector, Browns Ferry T. A. Cooper, Resident Inspector, Crystal River J. L. Shackelford, Reactor Inspector G. R. Wiseman, Reactor Inspector Approved by:
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f/L/fV Mark S. Lesser, Chief, Section 4A Date Signed Division of Reactor Projects SUMMARY Scope:
Routine resident inspection was conducted on site in the areas of plant operations, plant maintenance, plant surveillance, evaluation of licensee self-assessment capability, licensee event report closecut, and followup on previous inspection findings. During the performance of this inspection, the resident inspectors conducted several reviews of the licensee's backshift and weekend operations.
In addition, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> NRC coverage of Unit I startup activities commenced on March 30, 1994.
9405160192 94o502 PDR ADOCK 05000327
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Results:
i In the area of Operations, observations during Unit I startup indicated that operator attention to detail continued to need additional management focus.
Examples of operator inattention to detail included lack of clear communication by operators during turnover as to status of a clearance for work on the drain line off the #4 Main Steam line (this job was considered to
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be one of the highest priority jobs), and identification by NRC inspectors of malfunctions of instrumentation in the Auxiliary Control Room during a tour approximately 2 days after indicated parameters should have been observed by operators (paragraph 3.a).
In the area of Operations, sensitivity to identification of reduced status equipment in the plant was good. However, in the area of Maintenance, it was concluded that several material condition areas need continuing management j
attention to reduce the number of items in degraded status so that operations personnel can focus more time on routine unit operations.
Examples of
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degraded equipment on Unit 2 were leaking safety-related relief valves, radiation monitor problems, and turbine stop/ intercept valve problems.
Examples on the common unit were glycol chiller problems and shutdown board room chiller problems. (paragraph 3.b).
In the area of Operations, a violation for failure to perform equipment clearances as required by SSP-12.3 was identified (paragraph 3.c.(1)).
In the area of Engineering, a continuing example of weak technical documentation for deferral of corrective maintenance on the drain line between the PRT to the RCOT was observed (paragraph 3.d.(1)).
In the area of Plant Support, housekeeping in the Unit I containment prior to closecut was good and reflected an improvement over the housekeeping j
conditions of Unit 2 containment during the restart of that unit (paragraph 3.d.(2)).
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In the area of Operations, it was concluded that the Operations Improvement Plan was focusing on appropriate areas in need of improvement. These conclusions were based on discussions with senior plant management and observations of operations management and personnel in the plant.
Specific discussions with plant operators indicated an increased presence of management in the field to help coach on management expectations.
However, continued i
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management focus is required in these areas to instill the expectations as a normal "way of doing business" (paragraph 3.g).
In the area of Maintenance and Surveillance, a non-cited violation was identified for two inadequate surveillance instructions associated with EDG
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fuel transfer pump verifications and RCS inventory compensatory measures (paragraph 5.b).
During this period, several reviews were conducted to evaluate management reviews of readiness of Sequoyah to restart Unit 1 and continue with site
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improvements as outlined in the Site Improvement Plan. Department reviews for restart of Unit I were considered adequate.
Backlogs were being appropriately
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focused on by management and that adjustments were being made to reduce the same. However, continuing management attention and additional licensee resources need to be applied to backlog reduction in the near term to continue to improve plant material condition (paragraph 6).
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During this period, reviews allowed for a conclusion that although problem identification thresholds has been lowered, a general reluctance from some 1evels of management down to line employees still existed at Sequoyah in PER initiation to solve problems.
This represents an inconsistency in both the communication and the understanding of management expectations (paragraph 6.d).
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i REPORT DETAILS 1.
Persons Contacted Licensee Employees 0. Zeringue, Senior Vice President, Nuclear Operations
- K. Powers, Site Vice President
- D. Moody, Acting Plant Manager
- J. Baumstark, Outage and Technical Services Manager
- D. Brock, Maintenance Manager L. Bryant, Outage Manager i
- M. Burzynski, Engineering & Materials Manager l
- D. Clift, Acting Planning and Technical Manager
- M. Cooper, Technical Support Manager
- R. Driscoll, Nuclear Assurance & Licensing Manager ST. Flippo, Site Support Manager J. Gates, Outage Manager
- G. Enterline, Operations Manager 0. Hayes, Operations Program Manager
- C. Kent, Radcon/ Chemistry Manager
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B. Lagergren, Manager of Projects D. Lundy, Engineering & Materials Program Manager J. Patrick, Maintenance Program Manager
- L. Pogue, Site Quality Assurance Manager R. Rausch, Maintenance and Modification Manager l
G. Rich, Chemistry Manager J. Robertson, independent Analysis Manager
- J. Symonds, Modifications Manager
- R. Shell, Site Licensing Manager
- M. Skarzinski, Acting Business and Work Performance Manager J. Smith, Regulatory Licensing Manager R. Thompson, Compliance Licensing Manager
- N. Welch, Operations Superintendent NRC Employees M. Lesser, Chief, DRP Section 4A
- R. Musser, Resident Inspector, Browns Ferry
- Attended exit interview.
Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used in this report are listed in the last
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paragrap r
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On March 11, 1994, the Sequoyah Site Vice President announced a reorganization of the Site Vice President and Plant Manager's organizations effective March 14, 1994. Those changes were:
Site Vice President Organization changes are as follows:
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Licensing and Quality Assurance have been combined to form Nuclear Assurance and Licensing. The Nuclear Assurance and Licensing organization reports off-site to the corporate office; however, the organization also is functionally listed as reporting to the Site Vice President.
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Engineering has become Engineering and Materials.
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Business and Work Performance is a new organization created to include Scheduling, Budget and Cost, Performance Analysis, and Methods and Procedures.
Plant Manager Organization changes are as follows:
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Maintenance and Modifications organizations were combined.
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Work Control was reassigned to the Operations Organization.
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A new organization called Outages and Technical Services was created with Technical Support, Radcon/ Chemistry, and Outage Management as direct reports.
l Realignment of managers for the new positions is outlined in the listing
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of licensee employees above.
2.
Plant Status Unit 1 began the inspection period in MODE 5 (day 335 of the Cycle 6 refueling outage). During the inspection period, Unit 1 completed activities required to commence plant heatup and entered MODE 4 (RCS
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temperature greater than 200* f.).
Required testing was completed in MODE 4 and the unit entered MODE 3 on March 30, 1994. On April 1, 1994 the licensee identified a leak in a drain line off the #4 Main Steam line at a point where the line entered the turbine building. At the end of the inspection period, Unit I remained in MODE 3 with repairs to the drain line continuing.
Unit 2 began the inspection operating at full power. The unit operated at power for the duration of the inspection perio a
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3 3.
Operational Safety Verification (71707)
a.
Daily Inspections The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator adherence to approved procedures, TS, and LCOs; examination of panels containing instrumentation and other reactor protection system elements to determine that required channels are operable; and review of control room operator logs, operating orders, plant deviation reports, tagout logs, temporary modification logs, and tags on components to verify compliance with approved procedures.
The inspectors also routinely accompanied plant management on plant tours and observed the effectiveness of management's influence on activities being performed by plant personnel.
On March 30, 1994, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> NRC coverage of Unit I startup activities commenced.
Inspections determined that the licensee was conducting Unit 1 startup activities in a safe manner.
Operations shift turnover activities indicated that crews were conducting generally good turnovers. However, several other observations by the inspectors indicated that operator attention to detail continued to need additional management focus.
Examples were lack of clear communication by operators during turnover as to status of a clearance for work on the drain line off the #4 Main Steam line (this job was considered to be one of the highest priority jobs), and identification by NRC inspectors of malfunctions of instrumentation in the Auxiliary Control Room during a tour approximately 2 days after indicated parameters should have been observed by operators.
b.
Weekly inspections The inspectors conducted weekly inspections in the following areas:
operability verification of selected ESF systems by valve alignment, breaker positions, condition of equipment or component, and operability of instrumentation and support items essential to system actuation or performance.
Plant tours were conducted which included observation of general plant / equipment conditions, fire protection and preventative measures, control of activities in progress, radiation protection controls, missile hazards, and plant housekeeping conditions / cleanliness.
During a tour of the plant and control room on March 20, 1994, the inspectors noted several items that operations identified as being in a degraded condition (reduced status).
The operations shift turnover report. identified 21 items in reduced status on Unit 1, 18 items in reduced status on Unit 2, and 17 items in reduced status on both (common) units. The inspector considered that operations sensitivity to identification of reduced status equipment was good, and each item identified was not singularly
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significant. However, the inspectors also concluded that the cumulative total of the listing indicated the plant was continuing to operate with degraded components in several areas.
Examples on Unit 2 were leaking safety-related relief valves, radiation monitor problems, and turbine stop/ intercept valve problems.
Examples on the common unit were glycol chiller problems and shutdown board room chiller problems.
The inspectors concluded that several material condition areas need continuing management attention to reduce the number of items in reduced status so that operations personnel can focus more time on routine unit operations.
c.
Biweekly Inspections
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The inspectors conducted biweekly inspections in the following areas: verification review and walkdown of safety-related tagouts in effect, review of the sampling program (e.g., primary and secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples), observation of control room shift turnover, review of implementation and use of the plant corrective action program, verification of selected portions of containment isolation lineups; and verification that notices to workers are posted as required by 10 CFR 19.
(1)
During a control room tour on April 2, 1994 the inspectors reviewed clearance tags in the Unit 1 area of the control room. The following deficiencies associaf.ed with various j
components were noted:
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Handswitch 1-HS-30-159A was tagged oy hold order 1-H0-94-1017. No switch position was specified on the hold order tag. The switch was in the PTL position.
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Handswitch 1-HS-46-27A was tagged by hold order 1-H0-94-1165. The tag and clearance sheet specified the switch position required as P-Auto.
The switch was found to be in the PTL position.
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Handswitch 1-HS-6-117A was tagged by hold order 1-H0-i 94-1133. No switch position was designated on the tag
or clearance sheet. The switch was in the PTL position.
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The inspectors immediately informed the Unit 1 AS0S and the tagging documents were updated or corrected. A PER was initiated by the licensee to review this condition.
The inspectors reviewed SSP-12.3, EQUIPMENT CLEARANCE PROCEDURE, Revision 6.
Paragraph 3.2.2.A.4 of SSP-12.3 states that clearance forms shall be completed in accordance with this SSP, and that the clearance tag shall be hung as specified on the clearance forms. Appendix P of SSP-12.3
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i requires that the clearance sheet specify the position or condition that the device is to be placed in and tagged.
l Appendix P also requires that the individual placing the equipment / device in the specified position initial the
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clearance sheet verifying that the tag was hung and equipment properly placed.
In addition, a second individual
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is required to independently verify that the device is tagged and in the position indicated.
The inspectors concluded that the licensee was not following the requirements of SSP-12.3.
Failure to perform equipment clearances as required by SSP-12.3 and TS 6.8.1, is identified as a Violation, Failure to Follow the Requirements of TS 6.8.1 and/or Inadequate Procedure (327, 328/94-09-01).
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(2)
Review of Overtime Administration l
During this inspection period, the inspector reviewed the licensee's administration of overtime in the areas of
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Operations, Maintenance, and Radiological Controls. The i
inspector used the guidance provided in TS 6.2.2.g, Facility Staff, and procedure SSP-1.7, OVERTIME RESTRICTIONS (REGULATORY), Revision 2, in conducting this review.
Overtime at Sequoyah has gradually decreased since April 1, 1993 to the present.
During that period, maintenance personnel worked 44.3% overtime in April, 1993, as compared to 10.0% in March,1994, and had a yearly average for the period of 29.2%. (overtime hours are expressed as a percent of straight time hours and represent only those hours of personnel permanently assigned to the groups inspected).
Operations worked 43.8% overt;ae in April,1993, as compared to 14.6% in March,1994, with a yearly average of 30.3%.
Radiological Control personnel worked 47.6% overtime in April, 1993, as compared to 7.4% in March, 1994, and had a yearly average of 23.6% overtime.
The inspector concluded that overtime usage has declined within the last year and that the licensee has made progress in reducing the total overtime worked by the site. The inspectors noted that the gradual decrease in overtime was due to the restart of Unit 2 and completion of refueling activities on Unit 1.
The inspectors also reviewed the requirements for approval, review, and control of overtime according to TS and procedural guidance A problem was identified regarding the licensee's administrative review process complying with the requirements of TS 6.2.2.
Guidelines on the number of hours worked, as defined oy TS 6.2.2.g include, in part, that an individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7 day period, all excluding shift turnover time.
Specifically, TS
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6.2.2.g, in part, requires that controls shall be included in procedures such that individual overtime shall be reviewed monthly by the plant manager or his designee to assure that excessive hours have not been assigned. Upon
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the inspectors review of SSP-1.7 and the previous six. months of plant manager monthly reports, it appeared that the plant manager only reviewed, on a monthly basis, the hours of individuals who have exceeded 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> in 7 days, rather than the time of those individuals whose time exceeded any of the time guidelines referenced abo've.
The inspectors discussed their concern with the Site Vice President on March 31, 1994, and discussed the reviews that were conducted over the past six months.
The Site Vice President, formally the Plant Manager for the time period in
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question, provided an overview of how he had reviewed the overtime. The inspectors reviewed the plant manager's monthly review of plant use of overtime during the last six months with the Site Vice President and noted that reviews had been accomplished for individuals as required by Technical Specifications. However, additional review.
indicated that the guidance provided for conducting these reviews was not specific. The inspectors concluded that reviews were being accomplished as required by TS; however, the administrative guidance for conducting the reviews was weak. The licensee acknowledged the weakness and initiated review of corrective actions for revision of the SSP.
d.
Other Inspection Activities Inspection areas included the turbine building, diesel generator building, ERCW pumphouse, protected area yard, control room, vital 6.9 XV shutdown board rooms, 480 V breaker and battery rooms, and auxiliary building areas including all accessible safety-related
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pump and heat exchanger rooms. RCS leak rates were reviewed to ensure that detected or suspected leakage from the system was recorded, investigated, and evaluated, and that appropriate actions were taken, if required. RWPs we e reviewed, and specific work activities were monitored to assure they were being
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accomplished per the RWPs.
Selected radiation protection
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instruments were periodically checked, and equipment operability
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and calibration frequencies were verified.
(1)
During a tour of Unit 1 lower containment late in the
. previous period, the inspectors noted external damage to the PRT_to RCDT stainless steel drain'line. The damaged portion was located approximately 25 feet downstream of 1-FCV-68-310 and the inspector questioned the structural integrity of the line. This damage was previously identified by the inspectors on December 2,1993 and the licensee was informed (as discussed in inspection report 327,328/93-52).
By the end of the December inspection, the inspectors were informed
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that the damaged area would be repaired during the current outage.
During the current inspection period, the inspectors questioned the licensee regarding the status of the line repair and identified that the work request for the activity was deferred to the Unit 1, Cycle / refueling outage via an MRRC review.
The inspectors requested that the licensee provide the operability justification for the damaged component. The inspectors reviewed the deferral justification and concluded that it did not contain an adequate technical justification. The issue was discussed with outage management personnel, who agreed with the inspectors conclusion.
Subsequent technical evaluations were prepared and the inspectors concluded these reviews were adequate. Hewever, the inspectors also concluded that this was a continuing example of weak technical documentation for some deferred work items.
(2)
On March 24 and 25, the inspectors conducted tours of the Unit I containment regarding restart readiness. The areas reviewed included the lower containment inside the polar crane wall, raceway, fan and accumulator rooms, and the seal table areas. The walkdowns were performed after the licensee had completed performance of 0-SI-0PS-000-187.0, CONTAINMENT INSPECTIONS, Revision 4.
The inspectors identified approximately twenty material condition items for resolution by the licensee. The majority of the items required minor maintenance to correct; however, some required engineering reviews. The inspectors monitored the licensee's corrective maintenance and/or engineering justifications for the issues and concluded that they were properly addressed for restart. Aside from the material conditions, the inspectors concluded that the housekeeping in the subject areas was good and reflected an improvement over the housekeeping conditions of Unit 2 during the restart of that unit, e.
Physical Security Program Inspections In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital area access controls, searching of personnel and packages, escorting of visitors, badge issuance and retrieval, and patrols and compensatory posts.
In addition, the inspectors observed protected area lighting, and protected and vital areas barrier integrit L
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f.
Licensee NRC Notifications On March 14, 1994, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 regarding an inadvertent ESF actuation on Unit I while in MODE 5.
During filling and draining of steam generators per approved procedures a Hi-Hi steam generator level signal resulted in a feedwater isolation signal.
The licensee's initial evaluation indicated that approximately 2 minutes after steam generator # 1 was aligned for draining the feedwater isolation occurred. One of the narrow range level indicators for S/G # 1 was indicating approximately 95% level (logic for feedwater isolation is 2 of 3 steam generator narrow range level indicators greater than 81% level) when the draining evolution began. The operators believe that this indication was inaccurate due to the other two narrow range level indications reading approximately 79 and 78 percent when the draindown began.
Approximately two minutes into the draindown, the level indicator initially reading approximately 79 percent increased to approximately 81 percent, making up the two of three logic required for the isolation signal. A nitrogen blanket pressure of
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approximately 5 psig was being maintained on the SGs.
After the feedwater isolation occurred, operators secured the long cycle recirculation flowpath and completed draining of the # 1 SG.
The EFS signal resulted in closure of feedwater regulation valves.
Feedwater isolation valves were already closed as required by
plant conditions.
Minimal safety significance was associated with the event.
j The inspectors reviewed operator actions for the event.
Initial reviews the following day indicated that the cause of the second i
SG level instrument increasing above the setpoint during a draining evolution was partially filled reference legs for the j
instruments.
The licensee will verify this condition to-be the
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cause during performance of instrument calibrations. The licensee H
will submit an LER for this event.
g.
Reviews of Operations Readiness During the period, inspections focused on readiness of the Operations Department to resume power operation of both Sequoyah units.
The inspectors reviewed an Operations Improvement Plan which was being implemented by operations management during this period.
The plan included a review of recent operations events, a focus on areas needing increased attention, and a requirement for written identification and training of job expectations down to the UO/AVO levels. The training sessions were completed for the six crews by March 23, 199.
The inspectors conducted several plant tours to evaluate the effectiveness of communication of expectations from senior operations management to lower levels of the organization.
The inspectors determined that clear expectations had been communicated from the Operations senior management to the Shift Operation Supervisors.
In addition, continuing problem areas had been identified and operations management teams assigned specific tasks to provide action plans to accomplish improvements in these areas. These problem areas included:
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Operations Management and Supervision - This plan was implemented by the Operations Manager and included clear definition of the on shift organization duties and responsibilities.
In addition, buy-in to the expectations was emphasized by two-way communication meetings at all levels to allow for airing of all concerns.
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Equipment Status Controls - This plan was implemented by the Operations Program Manager and one of the Shift Operations Supervisors. The plan focused on better ways to maintain control of equipment status including status boards and reviews of current status control processes for improvements. Again, the team focused on two way communication between all levels of management and line personnel so that ownership of the process would be accepted by all.
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Personnel Performance / Expectations - This plan was implemented by the Operations Superintendent and focused on development of specific expectations for SOS /ASOSs, UO/AU0s, and for operations activities. This plan was implemented prior to Unit I restart. Careful considerations were given to buy-in of expectations by each level of operations management and operator personnel.
The inspectors determined that clear expectations had been communicated from the Operations Manager and Operations Superintendent through the Shift Operations Supervisors to the Assistant Shift Operations Supervisors. The inspectors noted that 46 specific responsibilities and 20 specific expectations had been described in writing for ASOS positions.
Specific expectations for Unit ASOS(s) included control board walkdowns at least twice each shift, review of unit operator logs at least twice each shift, approval of entry and exit for all TS LCOs related to his/her unit, and 17 others.
The inspectors consider that the initial communications of expectations was good and allowed for feedback from lower levels.
However, they also observed lower levels in the operations department expressing a wait-and-see attitude
regarding expected improvements in many long-standing plant I
problem areas.
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Equipment Deficiencies Backlogs - This plan was being implemented by the two Unit Managers.
This area is further discussed in paragraph 6.b.
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Process Improvement - This plan was being implemented by the Operations Program Manager. This area included a review of operation administrative procedures for further enhancement.
Configuration control was the top priority with other procedures including conduct of operations scheduled for additional reviews.
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Procedure Improvement - This plan was being implemented by
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the Operations Support Manager.
It involved review of
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operations procedures for improvement / upgrading. The inspectors noted that the licensee was in the process of upgrading the General Operating Instructions.
Contract work was complete and the verification and validation process was beginning. The licensee expected implementation of the new G0Is during the Unit 2 Cycle 6 outage. Other areas being reviewed for upgrade included Abnormal Operating Instructions and System Operating Instructions.
The inspectors concluded that proper initial focus was being maintained in this area.
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Training and Qualification - This plan was being implemented by the Operations Support Manager.
It involved specific focus on AU0 qualifications.
Since identification of a problem in this area in December of 1993, the licensee has increased focus on these qualifications and now has over 50 percent of the AU0s qualified in all watch stations.
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Scheduling, Utilization of Personnel, and Supporting Others
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The effort involved prioritization of work activities to more effectively utilize both operations and maintenance resources i conduct of everyday business. The inspectors observed improvement in this area during this inspection period.
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Investigations and Corrective Actions - This plan was being implemented by a senior operator assigned the Program Support Staff. Corrective action document action items assigned to the Operations Department were completed as required prior to Unit 1 entering MODE 4.
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Verifications of Activities - This plan was being implemented by the Fire Operations Manager. Verification includes line and management coaching to insure that j
expectations have been effectively communicate.
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The inspectors concluded that the Operations Improvement Plan was focusing on appropriate areas in need of improvement. These conclusions were based on discussions with senior plant management, observations of operations management and personnel in the plant. Specific discussions with plant operators indicated an increased presence of management in the field to help coach on management expectations. However, continued management focus is required in these areas to instill the expectations as a "way of doing business." The inspectors will closely monitor these areas during the Unit I restart and into the future.
Within the areas inspected, one violation was identified.
4.
Maintenance Inspections (62703)
During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the appropriate procedures and requirements.
Inspection areas included the following:
a.
Late in the last inspection period, the inspectors became aware of refurbishment activities associated with safety-related pump motors.
Specifically, the inspectors reviewed a listing of adverse conditions for the pump motors (debris found in motors)
removed from the Unit 1, B train charging pump motor and the Unit 1, A train RHR pump.
The conditions were discovered during motor inspection / refurbishment at the TVA motor repair facility. These motor tear-down inspections were being accomplished for the first time on these pumps since original installation (before 1980).
The inspectors determined that no indications had been observed prior to motor inspections which would cause questioning of pump operability.
During this period, the licensee met with the inspectors and discussed existing conditions of pump motors which had not received motor tear-down inspections. The inspectors specifically questioned the condition of the Unit 2, 'B' train RHR pump and the Unit 1, 'B' train RHR pump.
The licensee stated that they had no indication of motor degradation based on pump run data.
The inspectors questioned if any visual inspections could be accomplished to determine the internal cleanliness of the pump motors. This was based on the cleanliness problem identified during tear-down of the Unit 1, train
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RHR pump motor.
The licensee agreed with the inspectors and inspected the Unit I and Unit 2 RHR pump motors in question.
The inspections, along with data that indicated the pump motors were operating well within normal temperature ranges resulted in the licensee concluding that the pump motors could operate for another cycle.
The inspectors reviewed the licensee's activities and concluded they were adequate.
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b.
Replacement of Containment Spray Pump 1A-A Mechanical Seal The inspectors witnessed maintenance on CS pump 1A-A to replace i
the mechanical seal which was identified as leaking during post
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maintenance testing. The maintenance was being conducted under WO 94-1553-00 which involved Maintenance Instruction 0-MI-MRR-072-002.0, Containment Spray Pump Inspection, Revision 1, dated October 8, 1993.
During a review of the work package the inspector noted that maintenance personnel documented in the work package when they were disassembling the seals, on March 1,1994, the set screws in the locking collar were found loose.
In addition, further licensee inspection of the shaft showed no indication that the set screws had ever been tightened.
In subsequent discussions with the craft personnel performing the maintenance, the inspectors were informed that the set screws should also have been secured with LOCKTITE, as required by the MI.
The inspectors discussed the loose set screws with the system engineer who was aware of the problem. He indicated that the loose set screws were probably the root cause for the seal failure. The system engineer informed the inspectors that he would initiate a PER to document the problem concerning the loose set screws and damaged pump seals.
PER No. SQ 940183 was initiated on March 10, 1994, which was 10 days after identification of loose set screws and damaged seals discovery on March 1, 1994. The inspector concluded that craft activities to correct the deficient conditions were adequate; however, initiation of the PER was not timely, c.
Design Changes and Plant Modifications The inspectors reviewed selected DCN packages associated with plant modifications to support the Unit I recovery effort. The DCN work packages were reviewed and work in progress was observed to: (1) ensure that the DCN packages were properly reviewed and approved by the appropriate organizations in accordance with the licensees administrative controls; verify the adequacy of the 10 CFR 50.59 evaluations performed and that the appropriate FSAR revisions were planned or completed, if applicable; (2) ensure that the applicable plant operating procedures and design documents were identified and revised to reflect the modification; verify that the modifications were reviewed and incorporated into-the operations training program, as applicable; (3) verify that the modifications were installed in accordance with the work package (for those that could be physically inspected); (4) ensure that the modification was consistent with applicable codes and standards, regulatory requirements, and licensee commitments; and (5) ensure that post modification testing requirements were specified and that adequate testing was accomplished. The following were reviewed:
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DCN No, M-10549-A, Re-route safety related conduits that are routed too close to steam generator blowdown piping in the
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Unit I reactor building fan room #1.
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PER No SQ940085PER had been initiated identifying several l
conduits serving valves 1-FCV-1-182 and 1-FCV-1-183 that were too close to high temperature steam generator blowdown piping, contrary to the requirements of Engineering Specification G-40.
In the process of investigating this condition, the licensee discovered five other safety related valves with conduits too close to the same piping. These valves were 1-FCV-1-181, 1-FCV-67-87, 1-TCV-67-84, 1-TCV-67-i 85, and 1-TCV-67-86, i
DCN M-10549-A was issued to allow for the re-work, re-route, and/or replacement of 25 conduits and their associated cables (as required) to distances that comply with the G-40 requirements.
The inspectors reviewed applicable portions of this modification as described above.
No discrepancies were identified.
(2)
DCN-M09086A, Modification of Fluted Head Anchor Sleeves for Main Steam Lines exiting Main Steam Valve Vaults, Unit 1 On March 18, 199t., the inspectors conducted a review of the subject modification.
The inspec. ors met with engineering and modifications personnel to discuss the modification prior to a walkdown of the completed work. The inspectors reviewed drawings DCA-M09086-02, 05, 08, and 19 with the licensee personnel prior to the walkdowns. The inspectors and licensee personnel then conducted a walkdown of the modification areas in both Unit I valve vaults.
The inspectors concluded that the modifications were installed as described in the DCN drawings.
During the walkdown, the inspectors noted poor housekeeping in both valve vaults.
The vaults were generally dirty and cluttered with construction debris. Although the licensee stated that some work was still in progress in each valve vault, the inspectors considered that the vault areas were in need of attention regarding cleanup from construction activities.
Licensee management was informed of the inspectors concern in this area.
Vault cleanup actions were initiated the next day.
d.
l Early in the inspection period, the inspectors reviewed the root cause investigation and corrective maintenance activities taken for the failure of two, Unit 2 AFW LCV's to properly function during a performance of 0-SI-0PS-003-276.0, AUXILIARY FEEDWATER CONTROL VALVE OPERABILITY, Revision 4, which is performed on a
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monthly periodicity. The failed valves were 2-LCV-3-156 and 2-LCV-3-164. These valves are air operated and fail open on a loss of air.
The valves failed the SI due to a visual inspection r.oting that the valves did not stroke fully open, even though required AFW flows were achieved.
PER SQ940174 was initiated by
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operators in addition to the SI deficiencier due to the coincident valve failures representing a potential rel. ability problem.
The licensee performed troubleshooting of the valves per WRs C267158 and C267097 and determined that the pneumatic relay for the valve positioner (Masonelian model 8012) had failed via a worn relay plug. The spring-loaded plug is made of stainless steel and the relay seat material is aluminum.
The inspectors examined the relay component internals from the failed valves and discussed the potential root cause with the license.
It appeared that the seating surface of the relay plug for each valve was horizontally scored on one side which allowed air to bypass the control of the positioner and place supply air to the top of the valve.
This resulted in the valves not traveling full open during the SI.
The inspectors noted that this failure mechanism had the potential to fail the subject and similar Unit 2 AFW valves in'a non-conservative manner. The inspectors discussed this with the
licensee and questioned whether the. proposed corrective actions
would address this potential problem.
l Based on subsequent reviews, it was postulated that the root cause I
of the problem was that the spring which held the plug against the seat may have become positioned such that the plug may not have
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been contered,~and thus sustained scoring from the uneven wear-point over a long period of operation.
To review the extent of i
condition.for this problem, -the licensee identified 12 additional valves in operation on both units, with the 8012 positioner.
Four valves were the other Unit 2 AFW LCVs and the remaining were on TCV's for the ERCW and CCS systems. The Unit 1 AFW LCVs were installed with a different type of positioner and initially
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determined not to be susceptible to this type of problem; however,
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as discussed below, these valves were later determined to have related problems.
The licensee inspected two additional Unit 2 AFW LCV positioners and found only small discolorations where the failed relay plugs were previously noted as scored.
Based on these inspection results, the ability to identify additional problems during performance of monthly stroking of the AFW valves,
and the apparent root cause, the inspector concluded that the
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licensee's initial reviews of the problem were adequate.
The licensee plans to inspect other 8012 positioners during the Unit 2 refueling outage.
i e.
Unit 1 AFW LCV Problem Late in the inspection period, with Unit I still in MODE 4, the inspectors witnessed maintenance activities associated with Unit 1 AFW LCV, 1-LCV-3-148. WR C268233 was initiated to address a i
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15 problem identified by operators where the subject valve was shut; however, a flowrate of approximately 250 gpm was supplying the loop 3 SG.
Diagnosis of the valve problem postulated that the pilot valve for the positioner may be defective due to the presence of the presence of an air leakage sound.
Troubleshooting, replacement of the pilot valve, and stroke testing was performed on March 29 and the valve was declared operable.
The inspectors reviewed this valve failure with licensee engineering personnel on April 1, 1994.
Initial licensee evaluation of this failure postulated a buildup of corrosive products pilot valve which caused wear on the pilot seat. The licensee decided to inspect another valve positioner internals prior to Unit 1 startup to better bound the problem and extent of condition. The inspection period ended prior to this activity being accomplished. The inspectors will continue with the review of tnis area during the next inspection period.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726)
During the reporting period, the inspectors reviewed various surveillance activities to assure compliance with the appropriate procedures and requirements. The inspectior, included a review of the following procedures and observation of surveillance:
a.
MSIV Stroke Time Testing During the period, the inspectors reviewed 1-SI-SXV-000-003.0, FULL STR0 KING 0F CATEGORY
"A" Ai;D "B" VALVES DURING COLD SHUTDOWN, i
Revision 0.
The surveillance was used to conduct full stroke
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testing of the Unit 1 Main Steam Isolation Valves prior to entry into MODE 4 on March 4, 1994, and at 330*F on March 26, 1994.
The i
inspectors noted that the stroke time for each MSIV was below the j
5.0 second maximum time in the TS.
Stroke times for the MSIVs were as follows:
VALVE TIME 3-4-94 TIME 3-26-94 1-FCV-1-4 4.4 seconds 3.9 seconds 1-FCV-1-ll 3.4 seconds 3.7 seconds 1-FCV-1-22 3.4 seconds 3.6 seconds 1-FCV-1-29 3.5 seconds 3.5 seconds
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The inspectors concluded that the MSIV stroke times demonstrated adequate adjustments were accomplished for valve guide rods based on a recent event at another nuclear _ plant.
b.
During the inspection period, the inspectors reviewed the results of licensee assessments and reviews regarding problems in the areas of TS surveillances. The licensee commenced a full scale review of areas that had been problems in the past; one example is discussed in paragraph 7.c.
The reviews and corrective actions for the identified discrepancies were documented by the licensee via Incident Investigation SQ94018411. The three major focal areas included:
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Review of the process that identifies SRs in TS and transfers these requirements to the master SI listing.
Each SR in TS is assigned a Surveillance Instruction which accomplishes the SR.
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Review of the process that assures that each assigned SI has the TS SR requirement identified in the document.
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Review of the process which assures that each SI is written to accomplish the TS SR requirement.
During reviews of the first and second areas, the licensee identified various administrative problems, some of which had the potential for an SI surveillance not to be performed. The licensee initiated PER SQ940199 to document and correct these problems.
The reviews conducted by the licensee covered 100 % of these areas.
During a review of the last area, which consisted of a 100 %
review of Operations procedures, the licensee identified two problems where misinterpretation of the TS SRs resulted in inadequate procedures to properly implement the specific TS SR requirements. The first example, identified on March 10, 1994, involved TS SR 4.8.1.1.2.a.3, which requires, in part, that each EDG set be demonstrated operable by verifying that the fuel transfer pump starts and transfers fuel from the storage system to the engine mounted fuel tank, on a periodicity of once every 31 days.
Four surveillance procedures, one for each EDG, implement monthly required surveillance (1, 2-SI-0PS-082-007. A and B, ELECTRICAL POWER SYSTEM DIESEL GENERATOR).
However, these procedures did not contain steps to satisfy the TS SR 4.8.1.1.2.a.3.
The SR was misinterpreted as being met during the performance of ASME Section XI testing.
The second example, identified on March 14, 1994, involved TS SR - 4.4.6.2.1.a, which requires, in part, monitoring of the lower containment atmosphere particulate radioactivity monitor at least once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This SR is partially implemented by procedures 1, 2-SI-0PS-068-137.0, REACTOR COOLANT SYSTEM WATER
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INVENTORY, Revision 3.
These procedures indicate that if the acceptance criteria for the monitoring of the lower containment atmosphere cannot be met, performance of SI-137.1, REACTOR COOLANT SYSTEM - UNIDENTIFIED LEAKAGE MEASUREMENT, Revision 15, could be used to satisfy the TS SR. However, TS SR 4.4.6.2.1.a was misinterpreted, in that this substitution was not appropriate due to the TS only allowing for monitoring of.the lower containment atmospheric particulate radioactivity monitor.
The licensee determined that the root cause of the above problems / misinterpretations resulted from inadequate Operations procedure revision reviews. At the end of the inspection period, the licensee had completed review of all operation's procedures for technical adequacy and no additional problems were identified.
The inspectors concluded that the licensee's review process described above was thorough and addressed all process areas involved from identification of each SR in the Technical Specification through procedural implementation of the TS SR in surveillance instructions.
The licensee will submit an LER for the identified problems.
Failure to have adequate procedures to meet the subject TS SRs is identified as a violation (327, 328/94-09-02). However, this
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violation will not be subject to enforcement action because the l
licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.
Within the areas inspected, one non'-cited violation was identified.
6.
Evaluation of Licensee Self-Assessment Capability (40500)
During this inspection period, selected reviews were conducted of the licensee's ongoing self-assessment programs in order to evaluate the effectiveness of these programs.
a.
During the week of March 7 through 11, 1994, the licensee conducted MRRC reviews for Unit I restart and two unit operation including department readiness reviews early in the week and a senior management site readiness review on March 11, 1994.
The inspectors monitored activities associated with these reviews.
In addition, the Region II, NRC Section Chief for Sequoyah also was on site and participated in the reviews.
i The inspectors concluded that the department readiness reviews were accomplished as specified in their restart plan and appropriate reviews were accomplished to determine readiness for Unit 1 to return to power operatio =.
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b.
Review of Licensee Management Attention Issues (MAI) for Unit 1 Restart
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Throughout the inspection period, the inspectors monitored the i
licensee's progress in addressing items on the MAI list. The MAI
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list appears in the daily planning meeting for status review by
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I management. More detailed discussions of each of the various j
l topics are held on a rotating basis throughout the week, such that
each subject is discussed at least once a week.
Issues on the MAI i
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list include:
sis and PIs with open deficiencies; Chemistry instrumentation; Radiation monitors out of service, MCR nuisance,
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lit, or disabled alarms; MCR instruments out of service; Hold orders greater than 90 days; and AVO logs out of specification i
readings.
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The inspectors attended various issues meetings and reviewed the individual items discussed with regard to its impact on the restart of Unit 1.
The majority of the individual issues were being appropriately addressed by the responsible plant organizations and progress was noted during the inspection in the reduction of the identified deficiencies.
Good progress was noted in the areas of chemistry instrumentation and radiation monitors out of service.
Overall, no specific problems were identified which the inspectors considered a restart issue.
However, the inspectors also concluded that several of the issues were not being aggressively addressed by the licensee. An example of this was the review of hold orders greater than 90 days. The inspectors noted that, in general, the monitoring of these issues j
was hindered by a lack of ownership for the individual items and
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no priority assigned to resolve the issues in a timely manner. Of the 116 items on the list, less than half had owner organizations assigned and only 26 had estimated schedule completion dates. The
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l inspectors also concluded that the licensee, in the past, had been using the established hold order process in lieu of a viable equipment abandonment process. By the end of the assessment period, attention in the area of hold order reduction was i
improving; however, management overview of this and other problem l
areas is warranted to affect any substantial issue reduction. The
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inspectors will continue to monitor the licensee's progress in each of the MAI list during future inspections.
c.
Backlog reviews During this period, additional reviews were conducted of licensee backlog progress as outlined in the Sequoyah Management Assessment Review Team report for February 1994.
This report was reviewed by Sequoyah senior management on March 17, 1994. The licensee i
concluded that plant performance items being tracked generally were meeting goal expectations.
In the area of the Site Improvement Plan / Backlogs several backlog reductions were not progressing as expected. These were: (1) hold orders, (2) drawing l
updates, and (3) Vendor Manual updates.
Licensee management was
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aware of these trends and stated that additional resources would be focused on these areas.
In addition, special reviews were conducted of the Work Order / Work Request backlogs during the period.
The licensee identified approximately 1700 items in the non-outage corrective maintenance area and 950 items in the preventive maintenance area. The licensee stated that additional focus would be placed on reduction of these backlogs after Unit I restart. The licensee had implemented a 12 week rolling schedule process and was scheduling maintenance within system windows identified in this process. The inspectors did not observe backlog reductions in these areas for the inspection period, mainly due to emergent work identified during restart activities for Unit 1.
The inspectors concluded that backlogs were being appropriately focused on by management and that adjustments were being made to reduce the same.
However, the inspectors also concluded that continuing management attention and additional licensee resources need to be applied to backlog reduction in the near term to continue to improve plant material condition.
d.
Corrective Action Reviews During this period, the inspectors conducted a review of the licensee corrective action process.
The inspectors observed that i
the licensee was identifying conditions adverse to quality (PERs)
and the quantity of PER documents being written-indicated that the
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threshold for writing a PER was low.
However, other examples indicated that licensee personnel initiation of PERs were not consistently demonstrating that all employees maintained the same threshold. One example of a less than timely initiation of a PER was discussed in paragraph 4.b.
Another example was the identification of a problem associated with leakage past safety injection valves. After discovery of the problem, licensee personnel seemed reluctant to initiate a PER for the problem.
Questions asked by licensee personnel included:
Is there another way to handle this issue besides a PER? Who has to write the PER?
If I write the PER, will I have to answer it?
The inspectors concluded that although problem identification thresholds has been lowered, a general reluctance from some levels of management down to line employees still existed at Sequoyah in PER initiation to solve problems. Management expectations therefore remain inconsistent.
Within the areas inspected, no violations were identified.
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20 7.
Licensee Event Report Review (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC reporting requirements were being met and to evaluate initial adequacy of the corrective actions. The inspector's review also included followup on implementation of corrective action and/or review of licensee documentation that all required corrective action (s) were either complete or identified in the licensee's program for tracking of outstanding actions.
a.
(0 pen) LER 327/93-27, Degraded Fire Dampers as a Result of Failure to Install the Dampers in Accordance with Design Drawings. The issue involved the licensee identification that a significant number of fire dampers which were required to provide fire barrier integrity in some areas of the plant had not been installed as detailed in typical design drawings during original construction.
This resulted in a determination that the fire dampers were not installed per design drawings and did not correlate with Underwriters Laboratory (UL 555) tested configurations.
Fire dampers are considered acceptable when the installed configuration is in accordance with the manufacturers installation instructions.
These instructions must be sufficiently detailed to allow installation that is representative of the configurations that were fire tested in accordance with UL Standards.
Immediate licensee actions included posting of roving fire watches per TS 3/4.7.12.
On March 23-24, 1994, a Region based inspector reviewed the affected NRC fire protection SERs, the licensee incident investigation report (II), fire damper walkdown inspection reports, and the status of licensee actions to date.
As a result of the damper installation deficiencies originally identified in September 1993, a fire damper walk down program was undertaken by the licensee to evaluate fire damper installations in required fire barrier walls in safety-related structures in both Units. Of the 325 (250 duct-mounted and 75 wall-mounted)
affected fire dampers, the licensee has completed the walk down of 219 fire dampers. During the walkdowns, the licensee discovered
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common damper installation differences that included missing damper sleeves, retaining angles not of the suggested size, and damper assemblies rigidly attached to the penetration sleeves.
The identified fire damper installation conditions would not prevent the fire dampers from operating to the closed position but
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may prevent thermal expansion of the damper if exposed to fire resulting in damper distortion and a degraded fire barrier condition.
TVA Design Criteria No. SQN-DC-V-7.5. for Fire Protection Systems, dated September 26, 1972, indicated that the fire damper installations in ventilation ducts were not in strict compliance
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with UL 555 or the manufacturers instructions.
Licensing discussions with NRC staff at that time concluded that the fire damper installations were considered adequate to comply with BTP 9.5.1 as documented in Supplement 2 of the plant SER dated August 1980.
To determine the safe-shutdown significance of these damper deficiencies, the inspector verified the adequacy of ventilation separation of the plant's alternate shutdown capability for a fire in the Control Room.
TVA Abnormal Operating Instruction A01-27, Control Room Inaccessibility, Revision 22, dated May 28, 1992, was reviewed to verify manual operator actions required for plant shutdown. The inspector reviewed the heating and ventilating air flow diagrams for the control, auxiliary, turbine, and diesel generator buildings and verified that only two emergency supply / return ducts communicated between the control room and the auxiliary shutdown control room areas identified in the A01.
Each of the ducts have two closed duct-mounted fire dampers in series (fire damper Nos. XFD 31A 227, 228, 231, and 232) installed in the fire area barrier (Q-line) wall. The inspector, accompanied by licensee engineers, walked down a number of these areas in the auxiliary and control buildings. The inspector verified that compensatory measures consisting of roving fire watches were in place and fire suppression and detection systems were provided within the Auxiliary Building fire areas where the ducts are routed.
Based on the fire protection features utilized in these areas, there is reasonable assurance that the installed dampers will remain in place for a sufficient time to provide some measure of protection. Therefore, the alternate safe shutdown capability would not be adversely affected by the potentially degraded conditions of the installed fire dampers.
Based on the review conducted March 23-24, 1994, the inspector concluded:
The identified fire damper installation conditions would not
prevent the fire dampers from operating to the closed position but may prevent thermal expansion of the damper if exposed to fire resulting in a degraded fire barrier condition.
Fire damper installations at Sequoyah are within the
licensing basis of the plant for BTP 9.5.1 but do not correlate to national industry fire protection tested standards.
Adequate compensatory measures for the degraded fire barrier
conditions consisting of roving fire watches were in place.
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The Appendix R alternate safe shutdown capability would not
be adversely affected by the potentially degraded conditions of the installed fire dampers.
The LER will remain open pending the licensee completion of
the fire damper evaluations and associated corrective actions.
However, based on the inspectors review of the licensee's fire damper walk down/ evaluation schedule, Appendix R alternate safe shutdown capability and proposed corrective actions, the inspector concluded that the licensee corrective actions completed to date are adequate for restart of Unit 1.
b.
(Closed) LER 327/93-28, Containment Isolation Valves Not Verified Closed or Secured. The issue involved licensee identification of auxiliary feedwater vent valves that were not depicted on flow prints. Therefore, inadequate configuration control existed for these valves. The cause of the problem was a past engineering practice that allowed the installation of vent valves on instrument lines at the discretion of engineering personnel without showing the valves on the appropriate drawing.
Corrective action for Unit I was to remove the valves from the system, lhe inspectors verified by system walkdown that the Unit I valves had been removed from the system.
Unit 2 valves were verified to be closed and plugged.
This item was discussed in inspection report 327, 328/93-54.
In that report, it was concluded that walkdowns conducted prior to Unit 2 restart in October of 1993, and design basis document walkdowns conducted in 1986 and 1986 were not effective in identifying and resolving this problem in a more timely manner.
The inspectors also reviewed the licensee's incident investigation event report # SQ93068611, AFW TEST LINE VENT VALVES and noted that the licensee identified the root cause of this problem to be personnel error due to the past engineering practice described above.
Additional corrective actions to bound extent of condition included review of the design baseline verification program walkdown information to ensure that this type of mistake did not did not occur elsewhere.
The inspectors reviewed the licensee's documentation supporting these reviews.
c.
(Closed) LER 327/93-30, Failure to Perform a Surveillance Requirement (SR) on an Essential Raw Cooling Water (ERCW) Valve.
The issue involved the licensee's identification of a failure to perform a Surveillance Requirement (SR) on an essential raw cooling water (ERCW) valve (0-VLV-67-152). The subject ERCW valve supplies ERCW to the B-train component cooling system (CCS) heat exchangers (OB1 and 082) and is required to travel to the 35 %
open position during a safety injection signal to ensure proper cooling for CCS heat loads. The valve is normally in the 50 percent position (approximate) and receives signals to perform its safety function from both units. TS SR 4.7.4.b.1 requires that i
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the subject valves be tested once every 18 months.
The last test performed for the Unit I and 2 valves were in March of 1990 and September 1990 respectively.
The licensee attributed the root cause of the issue to personnel error during a revision to the loss of offsite power with a safety injection test procedures.
Unit I was in MODE 5 at the time of discovery and Unit 2 was operating in MODE 1.
The problem was identified by the licensee during a Site Quality Audit of the SI/SR database.
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The inspectors reviewed the immediate corrective actions for the missed surveillance which included setting the valve to the 35 %
open position and removing power to the valve.
This action ensured that the valve would be in its proper position upon a safety injection signal. During the current inspection period, i
the licensee completed the Unit 1 portion of the TS required-testing for the subject valve. This was performed in conjunction with EDG and ESF testing (1-SI-0PS-082-026). The compensatory measure requiring the valve to be set at 35 % open with power removed will stay in effect until the Unit 2 ESF testing can be accomplished during the next refueling outage.
The inspectors also discussed with the licensee the final SI/SR database review to ensure that all SRs were properly cross-referenced as the procedure that satisfied the specific SR.
This review included a 100 % review of the Surveillance matrix to verify all applicable Technical Specification Surveillance Requirements were included.
No other related problems were identified; however, other subsequent licensee audits performed by Technical Support identified problems regarding other areas of the surveillance program.
These problems were previously discussed in paragraph 5.b of this report and were identified as a violation.
The inspectors concluded that the compensatory measures and other proposed and completed corrective actions for the subject event were adequate.
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Within the areas inspected, no violations were identified.
8.
Action on Previous Inspection Findings (92701,92702)
a.
(CLOSED) VIO 327, 328/93-33-02, 10CFR 50, Appendix B, Criterion III Violation for Failure to Maintain a Category 1 Control Air
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System Drawing in an Accurate Configuration.
This violation occurred when the licensee was in the process of establishing a clearance on the control air system for work involving a moisture element. During valve manipulation for isolation both control air headers in the auxiliary building were inadvertently isolated.
This resulted in the automatic closure of containment isolation valves associated with the ice condenser and radiation monitoring systems.
The licensee initiated LER 50-327/93-019 and II No. S-93050 as a result of the inadvertent ESF actuation. The root cause of the event was determined to be personnel error during a j
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-l drawing revision of the control air flow diagrams made in 1977.
The error resulted in mislabeling control air headers A and B on
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Drawing 47W848-2. The licensee responded to this violation in a letter to the NRC dated October 4, 1993, which discussed the following corrective actions to prevent recurrence.
The transition flags on the drawings associated with the control air, service air, raw cooling water, raw service water to the HPFP, and HPFP systems were walked down to ensure no further discrepancies existed. These systems were selected by the licensee because of their complexity, physical plant arrangement, and the fact that they were not previously reviewed during the design baseline verification program. The inspectors reviewed the LER, the II, the response to the violation, and the licensee's corrective actions, all of which were considered to be adequate.
b.
(0 pen) VIO 327, 328/93-42-01, Failure to Follow the Requirements of Site Standard Practice 12.3 during Performance of Maintenance Activities on the IB 6.9 KV Unit Board.
The issue involved a failure to follow administrative procedures in performance of work activities associated with maintenance on electrical components.
The licensee responded to this violation in letters dated December 13, 1993 and March 17, 1994.
The NRC is continuing to review the corrective actions discussed in those letters.
However, initial reviews of the corrective actions involving additional instructions to electrical craft and supervision have resulted in observations of identified improved performance in the electrical maintenance area.
Specifically, an increased awareness and redefinition of electrical hazards indicated that work activities are being accomplished in a safer manner and within H
established clearance boundaries. The inspectors considered that the actions taken to date support restart of Unit 1.
However, the inspectors will continue to monitor the implementation of additional corrective actions during future inspections.
c.
(0 pen) VIO 327, 328/93-52-02, Violation of Technical Specification 6.8.1 due to SI-254 and SI-254.2 Being Inadequate. The issue involved the NRC's identification of boric acid solution on the containment liner.
The subject
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area was in the containment raceway at the concrete and steel liner interface. The area was not inspected by the licensee during the performance of the subject SI's due to it being covered by stainless steel flashing and insulating material. The problem was first identified on Unit 1, during the 1993 refueling outage.
Immediate corrective i
actions for the identified conditions involved removal of the flashing, identification of liner degradation from corrosion, drying of the accessible areas, and containment liner repair.
To status the issue for Unit I restart, the inspectors reviewed portions of the liner repairs in progress and concluded that the
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licensee adequately addressed the immediate problem.
Final inspections of the affected areas were also made on March 2 and 24, 1994, regarding the reinstallation of the stainless steel flashing and RTV sealant. Two areas were identified by the inspectors which required additional RTV application. One of the areas had been damaged by an instrument storage box.
The second was a small installation error at the top of the flashing; however, the inspectors also noted that a large portion of the containment liner and flashing had been previously wetted down from an unknown source. The inspectors could not determine whether any of the solution had flowed behind the installed flashing via the degraded RTV. The inspectors were later informed that the subject containment liner area was wetted down from a leaking component on System 62 (CVCS), specifically a flange downstream of 1-VLV-62-544.
This valve was located in the #4 accumulator room, directly above the subject area of flashing.
The inspectors concluded that the licensee adequately addressed the concerns for restart; however, it was also concluded that the repair process for 1-VLV-62-544 did not include adequate evaluation for potential damage to other components or structures from the leakage.
The inspectors will review the licensee's long term corrective actions for the violation during future inspections, d.
(0 pen) VIO 327, 328/94-04-01, Failure to Take Corrective Actions to Preclude Repetition of Configuration Control Problems. The issue involved continuing Operations department configuration control problems. The licensee responded to this violation in a letter dated March 30, 1994. The licensee acknowledged the violation and stated that the reason for the violation was ineffective communication and failure to use effective self-checking processes.
Immediate corrective actions included many of the items discussed in paragraph 3.g of this report. The inspectors conducted extensive review of the Operations department during this period and consider that corrective actions for this issue have been implemented to the point that safe operation of both units is reasonably assured.
The inspectors will closely monitor additional corrective actions in this area during future inspections.
Within the areas inspected, no violations were identified.
9.
Exit Interview The inspection scope and results were summarized on April 6, 1994 with those individuals identified by an asterisk in paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
Proprietary information is not
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contained in this report. Dissenting comments were not received from the licensee.
Item Number Description and Reference VIO 327, 328/94-09-01 Failure to Follow the Requirements of TS 6.8.1 and/or Inadequate Procedure.
NCV 327, 328/94-09-02 Failure to Follow TS 6.8.1 in Establishing Adequate Procedures to Meet TS Surveillance Requirements.
Strengths and weaknesses summarized in the results paragraph were discussed in detail.
Licensee management was informed of the items closed in paragraphs 7 and 8.
10.
List of Acronyms and Initialisms AFW
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American Society of Mechanical Engineers ASOS -
Assistant Shift Operations Supervisor AVO
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Assistant Unit Operator CCP
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Centrifugal Charging Pump CCS
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Component Cooling Water System CFR
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Code of Federal Regulations CR
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Control Room CVCS -
Chemical and Volume Control System CVI
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Containment Ventilation Isolation DCN
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Design Change Notice DRP
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Division of Reactor Projects ECCS -
Emergency Core Cooling System EDG
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Emergency Diesel Generator ERCW -
Essential Raw Cooling Water ESF
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Engineered Safety Feature Flow Control Valve FCV
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FSAR -
Final Safety Analysis Report G01
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General Operating Instruction GPM
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Gallons Per Minute HPFP High Pressure Fire Protection
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IFI
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Inspector Followup Item KV
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Kilovolt LCO
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Limiting condition for Operation LCV
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Level Control Valve LER
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Licensee Event Report MCR
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Main Control Room MFP
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Management Review Committee L
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MRRC -
Management Restart Review Committee MSIV -
Main Steam Isolation Valve NCV
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Non-cited Violation NRC
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Nuclear Regulatory Commission NRR
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Nuclear Reactor Regulation PER
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Problem Evaluation Report PORC -
Plant Operations Review Committee PMT
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Post-maintenance Test PTL
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Pull-to-Lock PRT
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Pressurizer Relief Tank PSIG -
Pounds Per Square Inch RCDT -
Reactor Coolant Drain Tank RCP
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Reactor Coolant Pump RCS
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Radiation Monitor RTV
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Room Temperature Vulcanizing RWP
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Radiation Work Permit SER
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Safety Evaluation Report SG
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Surveillance Instruction SOS
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Shift Operating Supervisor SR
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Surveillance Requirement TS
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Technical Specifications U0
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Unit Operator URI
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Unresolved Item VCT
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Volume Control Tank VIO
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Violation WO
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Work Order WR
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Work Request