IR 05000327/1993016
| ML20046B681 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 06/18/1993 |
| From: | Holland W, Kellog P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20046B676 | List: |
| References | |
| 50-327-93-16, 50-328-93-16, NUDOCS 9308060061 | |
| Download: ML20046B681 (20) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMisslON
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n REGION il
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101 MARIETT A STREET, N.W.
'C ATLANT A, G EORGI A 30323
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Report Nos.:
50-327/93-16 and 50-328/93-16
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: May 2 through June 5, 1993
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jf/[gO Lead Inspector:
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.~ HcH arvw sonineidyInspector Dath Si'gned W.
Inspectors:
S. M. Shaeffer, Resident Inspector A. R. Long, Resident Inspector S. E. Sp ks, Project Engineer
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Approved by:
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/Section 4A D4te Signed O
Pauf' Jd Divide actor Projects SUMMARY l
Scope:
This routine resident inspection was conducted on site in the areas of plant l
operations, plant maintenance, plant surveillance, evaluation of licensee l
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 or
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weekend operations.
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9300060061 930628 PDR ADOCK 05000327
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Results:
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No violations or deviations were identified.
Reviews of licensee outage performance were conducted regarding licensee j
activities during the middle of the Unit 1 Cycle 6 refueling outage, as well as the Unit 2 forced outage. The following conclusions were made:
Operations performance during this period was considered to be good.
A significant positive attention to detail activity was noted involving operator attentiveness. The operator's action resulted in identification and removal of a ground strap on a unit bus prior to energization.
Radiological controls performance continued to be good.
Person-rem expenditure and personnel contaminations were well below i
projected levels even though RWP work experienced additional
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growth due to both units being in outage. Continued good ALARA performance was exhibited with regard to the re-installation of the Unit I core barrel with an expenditure of 53 milli-rem. One notable event did occur near the end of the inspection period which involved the contamination of three workers working the Unit 1 #4 RCP flange.
Maintenance performance was considered mixed. Numerous restart I
related maintenance activities were conducted in a safe and quality oriented manner.
However, the two events associated with
attention to detail and personnel safety indicated that maintenance craft activities needed additional management i
attention to minimize the potential for personnel injury or equipment damage during work performance.
Engineering / Technical Support performance was considered good and somewhat improved since the previous inspection period.
Improvements were noted in the quality of presentations to the MRRC and BRC. Most system engineers were well prepared for i
discussions of their respective systems' problems.
Safety Assessment / Quality Verification performance was considered to be good. The overall assessment of the MRRC and BRC groups concluded that they were functioning and making restart decisions during this period in accordance with the restart criteria.
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In the area of Maintenance, a weakness was identified regarding a lack
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of attention to detail during repairs to the 2A-A EDG (paragraph 4.c).
In the area of Engineering, an inspector followup item was identified
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regarding followup on licensee evaluations for containment electrical
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penetration leakage on Unit 1 (paragraph 5.b).
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REPORT DETAILS i
1.
Persons Contacted Licensee Employees i
- R. Fenech, Site Vice President
- R. Beecken, Plant Manager J. Baumstark, Operations Manager L. Bryant, Maintenance Manager
- M. Burzynski, Nuclear Engineering Manager
- M. Cooper, Site Licensing Manager i
- D. Driscoll, Site Quality Assurance Manager J. Gates, Outage Manager
- C. Kent, Chemistry and Radiological Control Manager
- D. Lundy, Technical Support Manager R. Rausch, Modifications Manager
- G. Sanders, Operations Support Manager
- M. Skarzinski, Technical Programs and Performance Manager
J. Smith, Regulatory Licensing Manager
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- R. Thompson, Compliance Licensing Manager
- J. Ward, Engineering and Modifications Manager N. Welch, Operations Superintendent NRC Employees R. Crlenjak, Chief, DRP Branch 4 P. Kellogg, Chief, DRP Section 4A
- 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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paragraph.
During the month of May 1993, several management changes were announced for Sequoyah. These changes were:
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D. Driscoll replaced T. Flippo as the Site Quality Assurance Manager.
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M. Burzynski replaced P. Trudel as the Nuclear Engineering Manager I
During the week of May 17 - 21, 1993, the NRC RII Sequoyah Project i
Engineer, S. Sparks, was at Sequoyah reviewing restart activities.
Mr. Sparks specifically focused on backlog review efforts which were ongoing.
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On May 24, 1993, the NRC Restart Panel was on site to discuss restart activities with licensee senior management. The licensee presented
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their restart action plan to the NRC staff. NRC management and staff members in attendance included:
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S. Ebneter, Region II Administrator
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A. Gibson, Director, DRS, RII (NRC Restart Panel Chairman)
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F. Hebdon, Project Director, NRR (NRC Restart Panel Member)
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R. Crlenjak, Chief, DRP Branch 4, RII
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P. Kellogg, Chief, DRP Section 4A, RII (NRC Restart Panel Member)
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D. LaBarge, Senior Project Manager, NRR (NRC Restart Panel Member)
On May 25, 1993, NRC Commissioner James R. Curtiss visited the Sequoyah Nuclear Plant. The Commissioner met with the Resident Inspectors and Region II Management, toured the facility, and interfaced with Senior TVA management with regards to the licensee's restart plan and ongoing work activities. Accompanying the Commissioner during these activities were the NRC Region II Administrator, Stewart Ebneter, the NRC Region II Section Chief for Sequoyah, Paul Kellogg, and David Trimble, Technical Assistant to the Commissioner.
2.
Plant Status Unit 1 began the inspection period in day 25 of the Cycle 6 refueling outage (vessel defueled). Ten year ISI inspections of the reactor vessel were completed during the inspection period and the core barrel
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was placed back into the vessel on May 17.
Significant activities were
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also completed with regard to repair of a RCP flange leak, cleaning of 6.9 KV shutdown boards, A and B train ERCW outages, and work on RCS check valves. At the end of the inspection period, the licensee was making preparations for core reload activities.
Unit 2 began the inspection period in MODE 5 (day 62 of a forced outage).
During the period activities continued with regard to piping replacement in the secondary plant due to erosion.
In addition, other items identified as required for restart of the unit were also worked.
At the end of the period, Unit 2 remained in MODE 5 with work ongoing in i
accordance with the licensee's forced outage schedule.
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3.
Operational Safety Verification (71707)
i 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
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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
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plant tours and observed the effectiveness of management's influence on activities being performed by plant personnel.
During the inspection period, the inspectors noted that several l
operators (U0s and AU0s) were working 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> shifts in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
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period. This condition was detected during reviews of operations shift turnovers. The inspectors noted that from three to five operations personnel per day were " observing 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />" on the shift
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manning logs. The inspectors questioned operations management about this practice. They were informed that the present schedule
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of working operators overtime resulted in the routine 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
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shifts.
In addition, the inspectors noted that turnovers at the end of the 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> shifts frequently went into the next (17th)
hour. A review of TS 6.2.2 determined that this practice was acceptable, on a temporary basis.
Inspection report 327, 328/93-02 also discussed a routine reliance of management on operator overtime. This previous observation was made with both of the units in operation. Although the current
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heavy overtime usage is being worked during an extended outage
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period and is allowed by the TS, the inspectors were concerned
about increased potential for personnel errors during critical
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outage related evolutions. The inspectors considered that this
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i level of overtime usage, if continued during normal operation,
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would not meet the intent of TS.
The inspectors also noted that
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with the current levels of staffing, number of operating shifts, and eight hour shift rotations, it was difficult for the licensee
not to require the routine high use of overtime.
The inspectors discussed these observations with Operations
management. Management was aware of the problem and was planning
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several corrective actions to alleviate the reliance on operations
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overtime. These actions included taking positive measures to
increase the staffing of shift personnel..
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In addition, the licensee stated that prior to restart of either
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unit, all of the operations crew personnel would be working the same shift hours.
Currently, the SR0s are on 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts, while R0s and AU0s are on 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts.
The inspectors will
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continue to closely monitor licensee use of overtime in accordance l
with requirements.
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b.
Weekly inspections
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The inspectors conducted weekly inspections in the following i
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 j
included observation of general plant / equipment conditions, fire i
i protection and preventative measures, control of activities in
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i progress, radiation protection controls, missile hazards, and plant housekeeping conditions / cleanliness.
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c.
Biweekly Inspections 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 t
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secondary coolant samples, boric acid tank samples, plant liquid and gaseous samples); observation of control room shift turnover;
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review of implementation and use of the plant corrective action program; verification of selected portions of containment isolation lineups; and verification that notices to worker are posted as required by 10 CFR 19.
d.
Other Inspection Activities
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Inspection areas included the turbine building, diesel generator building, ERCW pumphouse, protected area yard, control room, Unit 1 containment, vital 6.9 KV shutdown board rooms, 480 V breaker and battery rooms, and auxiliary building areas including
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all accessible safety-related 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 were reviewed, and specific work activities were monitored to assure they were being accomplished per the RWP.s.
Selected radiation protection instruments were periodically checked, and equipment operability and calibration frequencies were verified.
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On May 17, during a routine tour of the EDG building, the inspector identified the following potential safety concerns.
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the IA-A EDG room, six large cables, each approximately 20- foot in
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length, were coiled above and behind the control and excitation
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cabinet for the EDG. The cables were identified as future power connections for the site's fifth EDG, which currently is not being i
utilized. The coiled cables were suspended by a small plastic tie i
wrap and several small rope (twine) restraints. The inspectors considered that, over time, these restraints would degrade, break, i
and allow the cables to impact the cabinet and potentially affect 1A-A EDG operability. The other EDG rooms had similar cables;
however, these were better supported.
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The second concern involved hold down restraints for various cells on the 1B-B EDG 125 volt batteries. The inspectors observed that several of the restraints were installed in such a manner such
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that the ends were between 0.25 and 0.5 inches (0.63 and 1.27 cm)
from the positive terminals.
The inspectors were concerned that
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this may be a potential ground path, as the restraints are
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grounded to the battery support structure.
The inspectors noted
that the restraints were insulated with a rubber material; I
however, it was difficult to determine whether all of the I
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insulator was intact. The other EDG batteries did not have similar problems.
The inspectors discussed the above observations with the system engineer. The engineer recognized the potential hazards and stated he would review them for corrective action.
I e.
Physical Security Program Inspections In the course of the monthly activities, the inspectors included a
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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
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integrity.
During this period, significant modification to the site security i
barrier / systems was ongoing.
Frequent regional inspections are being conducted to review these major modification activities On May 10, 1993, an inspector noticed that an individual had
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passed through the gatehouse portals without obtaining a visitor's badge or carding in.
Upon discovering the error, he returned to
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the portal area and informed the guards. The gatehouse portals
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are outside the Protected Area, and therefore not under the purview of NRC Security requirements. However, carding in is i
necessary for personnel accountability under the Emergency Plan.
When the inspector questioned the incident, the licensee issued a post-order cautioning guards to be more diligent in monitoring
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personnel entry. The licensee also stated that future problems of this nature will be corrected within the new security plan and site upgrade.
f.
Licensee NRC Notifications (1)
On June 1,1993 the licensee made a four hour notification to the NRC as required by 10 CFR 50.72. The notification
was made due to the licensee making a courtesy offsite report to the State of Tennessee Radiological Health Group.
The report to the state concerned the licensee's
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identification that, on May 29, contract personnel had attempted to access the Sequoyah site with contamination from an offsite source. One contaminated individual set off i
a radiation monitor at the site access gatehouse.
Investigations revealed that a total of four individuals were contaminated, three of which did not set off the site access monitors due to the low level of contamination-
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present. All of the contract personnel had previously worked at the same location prior to coming to Sequoyah.
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The licensee confiscated contaminated shoes and equipment at the request of the State and monitored the individuals contamination levels.
Levels up to 10,000 counts per minute (CPM) beta / gamma and 4,000 CPM alpha was detected on the contractor's shoes and somewhat lower levels were detected i
i on some equipment.
Region II radiation protection personnel I
were also informed of the event by the resident inspectors.
g.
Outage Functional Area Reviews t
During this period, the inspectors focused on review of licensee i
performance during the middle cf the Unit 1 Cycle 6 refueling outage, as well as the Unit 2 forced outage in several functional areas.
The following conclusions were reached during this period:
Operations - Operator performance during this period was considered to be good. Operator attention to detail resulted in work being controlled such that no undue risk was placed on Unit 2 or the spent fuel pool. Unit I was defueled during the pericd. A significant positive attention to detail activity was noted i
involving a operator observance of a ground strap on a unit bus.
The observation assured that an important electrical bus was returned to service in a safe manner.
Radiological Controls - Performance in this area continued to be good.
Person-rem expenditure and personnel contaminations were well below projected levels even though RWP work experienced additional growth due to both units being in outage.
Continued good ALARA performance was exhibited with regard to the re-installation of the Unit I core barrel with an expenditure of 53 i
milli-rem. One notable event did occur near the end of the inspection period which involved the contamination of three workers involved in Unit 1 #4 RCP flange repair activities. The individuals received unexpected low internal contaminations during flange surface preparation. The licensee attributed the event to poor communications, inadequate vendor actions, and inadequate supervision of vendor activities.
The licensee completed RCP flange work with increased airborne monitoring.
Maintenance - Performance in this area for the inspection period was considered mixed. Numerous restart related maintenance activities were executed in a safe and quality oriented manner.
However, the two events associated with attention to detail and personnel safety which are discussed in paragraph 4.d, indicated that maintenance craft activities needed additional management attention to minimize the potential for personnel injury or equipment damage during these activities.
Engineering / Technical Support - Performance in this area was considered good and somewhat improved since the previous inspection period.
Improvements were noted in the quality of presentations to the MRRC and BRC. System engineers, in general,
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were well prepared for discussions of their respective systems'
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In addition, engineering and technical support-for
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resolution of several long-standing EDG problems, evaluation of
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electrical penetration leakage, and evaluations for potential
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Vantage 5H fuel failures were considered good.
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Safety Assessment / Quality Verification - Performance in this area was considered to be good. The overall assessment of the MRRC and BRC groups concluded that they were functioning ar.1 making restart
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decisions during this period in accordance with the restart criteria.
h.
RESTART REVIEW ACTIVITIES On May 20, 1993, the licensee submitted a restart plan to the NRC.
The plan discusses licensee actions for six focus areas: balance of plant, backlogs, Operations, programs, corporate / site interface, and people / organization / culture. The plan summarized the scope and implementing methodology for the extensive ongoing restart activities.
On May 24, 1993, the licensee met with the NRC staff at the Sequoyah Training Center to provide an overview of the restart plan. The discussion included how the Site Improvement Plan, secondary plant reliability studies, technical programs improvements, and Operations program performance were integrated into the restart plan. Specific presentations were given in the six focus areas. The presentations included summaries of issues,
restart objectives and actions, and post restart actions to ensure continued improvement.
During the past several months, the resident inspectors have focused on the operations department improvement efforts. The i
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inspectors met frequently with operations management and discussed ongoing licensee actions. These included department standdown meetings. Other activities included reductions in several backlogs that the operators have been willing to live with.
Operations backlog areas included hold orders, temporary labeling, temporary operator aids, JCOs, and control room instrument
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deficiencies. The inspectors will continue to monitor licensee actions in these areas.
In addition, review of corrective actions
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for past problems and enforcement issues had commenced in
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accordance with the NRC restart inspection plan.
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BACKLOG REVIEW COMMITTEE The inspectors observed activities of the Backlog Review Committee l
(BRC). As described in the licensee's Restart Plan dated May 20,
1993, the purpose of the BRC was to identify and evaluate existing l
site backlogs as of May 1,1993, for their individual and.
aggregate impact on restart and, with the recommendation of the
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backlog owner and affected system engineer, make restart decisions l
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on those backlogs. The BRC along with the system engineer presents to the Management Restart Review Committee (MRRC) the results of their determinations.
System engineers together with their respective department managers identified and discussed backlog items and provided a recommendation to BRC on whether the item should be completed prior to restart.
These items were then presented to and
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discussed with the BRC by the system engineers. The various categories of backlog are identified in the licensee's Restart Plan, and included items such as WR/W0s, DCRs, issues from the Master Issues List (MIL), CAQs, NRC commitments, as well as several other categories. The BRC evaluated several backlog categories on a system basis, such as WR/W0s and MILS, in which each item was reviewed. Other backlog categories were reviewed by i
BRC on a programmatic basis, such as vendor manual updates, procedural revisions, and drawir.g deficiency backlog. The licensee's stated that all backlog items were to be reviewed by the system engineer and the department manager for inclusion into
the restart schedule prior to presentation to the BRC.
The BRC consisted of four members with experience in operations (active SRO), engineering, maintenance, and plant management.
Discussions between the system engineer and the BRC were observed by the inspector to be open, and the BRC members ensured the issue was clearly understood prior to any recommendations. The BRC met daily to evaluate backlogs.
The inspectors reviewed the BRCs criteria for identification of issues / items needing corrective action prior to restart.
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criteria were:
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Adverse impact on safety system availability or performance
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Significant challenge to plant / personnel because of individual or aggregate impact
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High potential to impact plant operating reliability
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Prudence of or need for working during two unit outage Among the systems and backlog items observed by the inspectors were portions of ERCW, penetrations and sleeves, heater drains and vents system, main generator hydrogen cooling system, control-building heating, ventilating, and air-conditioning, NRC commitments, MILS, CAQs, WR/W0, and TACFs. All issues observed by the inspectors were consistent with the above criteria and were conservative. The inspectors also observed that there was no reluctance on the part of the BRC to add items to the restart list if the restart criteria were satisfied.
In addition, criteria were well understood by system engineers who presented the information to the BRC.
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Prior to the BRC, the licensee identified items / issues that would
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be resolved prior to restart of either unit. This list was i
developed from discussions with system engineers, department managers, review of WO/WRs, the Master Issue List (MIL),
recommendations of a B0P reliability study, as well as othcr sources. This list of restart activities was reviewed and approved by MRRC.
Separate from these activities, the BRC, in conjunction with the system engineers and department managers reviewed backlog items as discussed above.
Items were identified as scope growth if BRC recommended completion prior to restart and these items had not been on the original list of restart activities. All scope growth items recommended by BRC were required to be discussed with the MRRC, which has final approval for additions to the list of restart activities.
During the inspection period, the inspectors attended various MRRC meetings to evaluate the decisions of MRRC including, but not limited to:
the acceptance of scope growth items into the restart plan; the final resolution of restart issue discrepancies between engineers and BRC; and the overall decisions of the MRRC decisions regarding issue resolution. Also reviewed by the inspectors during these meetings was the quality of presentations to the MRRC by system engineers and supervisors. The inspectors had the following observations:
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The inspectors observed a MRRC meeting in which the BRC presented scope growth items and items in which BRC and the system engineer could not reach agreement. The presentation of these issues to the MRRC was considered open, and decisions were consistent with the restart criteria.
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The inspectors noted that, in general, the MRRC was not reluctant to delay a final decision for excluding an issue from the restart plan if insufficient information was available for an appropriate decision to be made.
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The inspector considered that system engineers were reasonably well prepared in presenting the MRRC with their respective system restart issues; however, several presentations had not fully explored all available options.
The MRRC recognized the exceptions as noted above and delayed final action until all options could be evaluated.
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The inspectors considered several of the restart scope reduction requests, as presented by project management personnel to be not clearly presented; however, upon questioning by the MRRC, the issues were more clearly
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these observations, was fully evaluating the scope reductions in a manner consistent with the restart criteria.
The inspectors concluded that review committee activities, to date, were in accordance with the licensee's criteria as outlined in the SEQUOYAH RESTART ACTION PLAN. Site management was conservative in making decisions to incorporate resolutions to long-standing problems and improving B0P and other plant support equipment.
However, late in the period, the inspectors also observed some indications that key TVA corporate senior management was more focused on schedule adherence and possible reduction of work scope. The inspectors will continue to review the licensee's restart efforts in accordance with the NRC restart inspection pl an.
Within the areas inspected, no violations were identified.
4.
Maintenance Inspections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance activities to assure. compliance with the appropriate procedures and
requirements.
Inspection areas included the following:
a.
On May 10, 1993 the inspectors learned of a potential problem that had been identified the previous night.
The problem was
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associated with recirculation flow for the Unit 2, 2B-B RHR pump.
The potential problem occurred during realignment of the pump in
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accordance with 0-50-74-1, RESIDUAL' HEAT REMOVAL SYSTEM, Revision
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Operators were attempting to realign the RHR flowpath from the B RHR pump to the A RHR pump. During this evolution, the operators noted that the 2B-B RHR recirculation valve (2-FCV-74-24) did not automatically open when flow decreased to approximately 626 GPM. Operations personnel declared the Unit 2, B train RHR pump inoperable and wrote a work request to troubleshoot the problem. At no time during this evolution was RHR flow degraded.
Troubleshooting was accomplished on May 10. The troubleshooting determined that the valve flow switches were performing as
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designed.
Plant personnel determined that the flow indication I
observed by operators was from a different transmitter which e
properly indicated 160 - 200 GPM lower than the actual flow. _ The inspectors obtained a copy of the work request (C173382) and noted that it identified a potential problem with RHR pump mini-flow
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switch 2-FS-074-0024A-B. The inspectors discussed the activities associated with troubleshooting the problem with operations and instrument maintenance supervision. The inspectors obtained a
copy of the work order (WO 93-02492-30) package for the job, and reviewed documented troubleshooting activities. The inspectors
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concluded that the maintenance troubleshooting was in accordance
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with procedures and that equipment performed within tolerances.
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b.
During the inspection period, the inspectors monitored activities
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involving replacement of train A ERCW isolation valves. These valves are 24 inch butterfly valves and are located in the ERCW building, in each respective ERCW's pump discharge piping.
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l Previous pump refurbishment outages revealed that the existing valves had significant leakage; however, the system met its TS performance criteria with this degradation.
The inspectors i
observed work activities and reviewed work documentation. The l
inspectors considered that system tagouts were appropriately
performed, compensatory measures for security and fire protection considerations were in place, foreign material exclusion requirements were addressed, and that housekeeping was improved, when compared to previous ERCW related maintenance activities.
The inspectors reviewed DCN Nos. M-09499-A, F-09574-A and their l
associate WP. The inspectors considered that these documents
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adequately controlled the work activities.
One problem was encountered during the PMT for the valve (s)
replacement. During pressure testing, three out of four of the
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valves developed substantial leakage at the gasket connections.
i The licensee determined that the craft utilized the minimum
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torquing requirements as referenced in the WP. The valves were L
subsequently re-torqued and tested satisfactorily. The
inspectors concluded that the work activities and PMT were
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c.
During the inspection period, the inspectors reviewed activities involving a number of modifications performed on the 2A-A EDG.
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i These modifications were being performed to correct long-standing l
issues associated with various components and design aspects of
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the EDGs. The activities involved the resolution of the following
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1.
The present engine idle start circuitry could allow the EDG to inappropriately accelerate past 550 RPM, thereby dropping out the idle start circuitry and allowing the EDG to j
accelerate to rated speed (CAQR SQP880541). According to
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the system engineer, this problem has occurred approximately i
l five times in the three years. The modification added idle start circuitry (time delay) to allow the EDG to accelerate past 550 RPM for less than 5 seconds and then' return to idle. This modification should increase reliability of the j
idle start system and result in a reduction in engine wear i
due to controlled idle starts. This modification is now i
complete for all the EDGs except for the IA-A.
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2.
The indicating lamps on the EDG engine control panel could cause a short circuit of the control power during lamp replacement resulting in the EDG becoming inoperable (Final event report 553891106820). This problem was identified in i
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1989 and reported to the NRC via LER 327, 328/89-14.
In that event, while an AVO was replacing a light bulb, the 2B-B EDG became inoperable.
The licensee has operated under administrative controls to only change failed lamps during each EDGs respective monthly outage, until the implementation of the current modification. The modification installed resistive base lamp holders to prevent the potential for a short circuit and subsequent loss of control power to the EDG. This modification is now
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complete for all of the EDGs.
3.
Morrison-Knudsen Company issued a 10 CFR Part 21 in 1989
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noting that Sequoyah's EDGs did not have independent I
pneumatic starting systems as required by the FSAR section 9.5.6 (CAQR SQP890523). The issue involved the ability of l
the EDG to start if only certain pairs of air start motors were available. This situation could occur upon the loss of starting air to one engine of the tandem EDG, resulting in a
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l failure to start. This issue was determined by the licensee as not being an immediate safety issue due to the redundant air start motors not being required to satisfy single failure criteria. This criteria was considered satisfied by the emergency AC power system having two completely separate and redundant trains. The licensee determined that
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modification to the air start system would increase I
assurance that the EDG would start when required (i.e., adds assurance that the EDG will start in the event where one set of the redundant air receivers or air supply is disrupted).
This modification is now complete for all the EDGs except for the IA-A.
4.
Control wiring for the motor operated potentiometer (M0P) in the 2A-A EDG was reversed for the automatic and manual voltage controller (SQP890579). This condition was
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discovered in 1989 when the MOP was being replaced with an l
identical unit. The referenced CAQR described a condition where wiring internal to the MOP was swapped to provide for proper voltage control. The swapped internal wiring was I
apparently intentionally performed prior to 1989 to modify
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the circuitry at the MOP, rather than fix a field discrepancy. The current modification will prevent continued polarity problems with the circuitry in lieu of future EDG control M0P replacement (ie. field wiring correctly accepts vendor MOP without modification). This modification is now complete for. all the EDGs except for the
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IA-A.
The system engineer informed the inspectors that a similar modification is being planned to perform a similar i
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correction to the Woodward governor speed controller on all J
the EDGs. This correction was not ready to be incorporated in the current modification activity.
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The inspectors reviewed the above ac;ivities and the associated i
documentation (DCN No. M066C4A). No discrepancies related to the above modifications were ident; Tied. However, during PMT for portions of the modifications, a problem was identified with operation of the 2A-1 engine governor. Subsequent investigation revealed a problem with the governor servo booster valve. The
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licensee decided to replace the valve with a like part from the i
fifth EDG, which is not in service. WRs C200777 and C172982 were i
written to remove the valve from the fifth EDG and reinstall it in the 2A-1 engine. The work was performed properly; however, during review of the WO 93-02758-00, the inspectors identified that the replacement servo valve had been installed with the existing oil
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in the actuator. Due to this being identified to the licensee
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after the EDG was run, the inspectors questioned the condition of all the oil in the governor at this time.
The licensee first
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initiated WR C172778 to sample the governor oil; however,
subsequently decided to replace the oil with an immediate action work request prior to final testing of the EDG for operability.
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The inspectors considered that the repairs to the booster valve
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were satisfactory; however, the inspectors also identified a
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weakness due to the installation of the serve valve into the 2A-A
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EDG without regard for the possible contamination of the existing i
governor oil.
d.
During this period, the inspectors were informed about two events which were considered "near misses" from a personnel safety point of view. The first problem involved maintenance craft connecting a ground strap to an electrical bus outside of a maintenance boundary. The second problem involved maintenance craft working i
on energized equipment due to not properly verifying that the
correct component was being worked.
l The first problem was discovered by an operations SRO who was doing a final equipment walkdown prior to reenergizing the 6.9 Ki/
unit board. He noticed maintenance activities in the vicinity.
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He informed the craft that he was going to energize the unit board
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and learned that a ground strap was installed on one of the output i
breaker taps on the board he was to energize. The ground strap had been installed by the maintenance craft in error.
Had this j
questioning attitude not been applied by the SR0 during final board walkdown, extensive equipment damage or personnel injury could have occurred if the board had been energized with the ground strap installed.
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The second problem involved work being accomplished on the J'
incorrect component due to craft failure to properly identify the
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equipment (equipment sump pump) to be worked at the job site.
This error resulted in mechanical maintenance decoupling an operable pump, and electrical maintenance disconnecting and removing the pump motor.
Restoration of the pump using a new
motor was also accomplished. The error was discovered when the post maintenance test resulted in another sump pump other than the
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one having been worked starting.
If the pump being worked had been started during the maintenance activity, serious personnel injury or equipment damage could have resulted.
Significant management attention was focused on the problems after each occurred. However, the facts that both problems occurred during this period, and the potential for serious personnel injury for each problem, resulted in a conclusion that additional management attention was warranted in the maintenance area regarding attention to detail and general craft practices in the way work is accomplished.
Within the areas inspected, no violations were identified.
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5.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various l
surveillance activities to assure compliance with the appropriate
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procedures and requirements. The inspection included a review of the l
following procedures and observation of surveillances:
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I a.
On May 19, the inspector witnessed testing of the 2A-A EDG. This testing was being performed as part of post maintenance testing for a number of modifications performed on the system (DCN M06604A). These modifications were previously described in paragraph 4.c.
Early in the testing activities, a problem was identified in which, when the tandem EDG set was attempted to be started by the air start motors to the 2A-2 engine alone, a failure to start occurred. Troubleshooting determined that the governor servo booster valve was not functioning properly. After.
repairs were completed, testing was allowed to continue.
The inspectors monitored maintenance and operations personnel during the pre-run checkout activities, including portions of SI-102 M/M, DIESEL GENERATOR MONTHLY MECHANICAL INSPECTIONS, Revision 7.
No discrepancies were identified. The inspectors discussed the scope of testing with the system engineer, reviewed the work documentation, and concluded that the activities were adequately performed. The inspectors also concluded that system engineering's understanding of the specific issues and involvement throughout the modification and subsequent testing activities was good.
b.
During the inspection period, the inspectors reviewed portions of the test data from SI-157, TESTABLE PENETRATIONS, Revision 19, for Unit I cycle 6.
The SI data indicated that two electrical containment penetrations, X-164E and X-127E were leaking excessively (17 SCfH and 11.5 SCFH respectively).
Prior to the Unit I cycle 6 performance of the SI, the as-found leakages for these penetrations were essentially zero. The licensee documented these failures on PER SQPER930154.
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The original vendor for these penetrations was Westinghouse.
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Currently, the licensee's vendor for this equipment is Imaging and Sensing Technology Corporation. The subject penetrations are an obsolete canister type, which have a ceramic to metal seal and are not repairable using any qualified method. The licensee contacted both of the above vendors to discuss the existing leakage and
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discuss any typical degradation characteristics.
Neither vendor could reliably predict future failure or degradation based on past history of electrical penetrations.
In addition, the vendors could not correlate the failures to any environmental condition (temperature, humidity, etc.).
The current leakage at this time is not greater than the allowable TS limit of 0.6 of the allowable leakage limit.
This limit equates to approximately 135 SCFH. Also, each of these leaking penetrations is currently not greater than the ANSI N45.4 single i
path leak commitment for a single penetration (approximately 27 SCFH). The inspectors reviewed previous outage data for the
subject leaking penetrations and other similar electrical penetrations. One previously identified leaking electrical penetration (X-156E) is being replaced by the licensee during the Unit I cycle 6 outage.
During the Unit I cycle 5 outage, this penetration was identified to have approximately 22 SCFH leakage.
However, at the end of the cycle 5 run, the leakage had degraded to approximately 57 SCFH.
This demonstrated to the inspectors that there existed a high probability that, once leakage was established in these penetrations, it was likely to continue to
degrade, possibly to the point where it could challenge the TS
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leakage limit.
To assist management in decisions regarding operation during the-l next fuel cycle with the current leakage of the two penetrations, Technical Support personnel evaluated various options and their associated risks. The inspectors considered this evaluation conservative and very useful to management in evaluating the j
situation.
The inspectors discussed the options concerning the
leakage with the licensee.
Replacement of the penetrations required a long material lead time, as the licensee did not have any replacements onsite.
A second option to replacement was to operate with the degraded penetrations, and a third option involved operation with some periodic monitoring of the known leakage areas during the operating cycle. Given these options, the licensee determined that monitoring the subject penetrations durina heat up or mid-cycle was not necessary. The inspectors expressed oncerns with regard to this decision to operate without monitoring for further degradation.
Tne inspectors considered that there was a high potential for continued degradation and possible exceeding of the TS leakage limit.
This issue will be identified as IFI 327/93-16-01, Followup on Licensee Evaluations for Containment Electrical Penetration Leakage on Unit 1.
The inspectors will continue to monitor the status of these two penetrations during future inspections.
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Within the areas inspected, no violations were 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.
During the inspection period, the inspectors reviewed the results of the f
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licensee's Incident Investigation number S-93-024 regarding Unit 1 reactor cavity liner leakage. These activities were also reviewed by the inspectors in Inspection Report 327,328/93-13. During the current inspection period, the licensee has concluded, through monitoring of sump inleakage, that the leakage rate is constant at approximately 2.5 gpm. This value is with the cavity flooded up to approximately the 726 elevation. The licensee's proposed corrective actions include trying to identify the liner leakage during the flood up for refueling the core.
The inspectors discussed the troubleshooting plan with technical support personnel and will monitor the evolutions during the next inspection
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period.
Within the areas inspected, no violations were identified.
7.
Licensee Event Report Review (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC j
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
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(Closed) LER 327/92-15, Noncompliance With the Containment Isolation TS During Unavailability of Train A Auxiliary Air. The issue involved the identification by the licensee of a configuration of the air supplies and solenoids for the containment vacuum relief isolation valves which l
would result in the loss of automatic closure capability upon the L
unavailability of Train A control air, rendering the valves inoperable.
The licensee submitted a TS change on March 19, 1993, to address the inoperability of the containment vacuum relief butterfly isolation i
valves, relative to the unique function of the penetration. The inspectors reviewed the TS change and considered it appropriate to
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address the issue.
l Within the areas inspected, no violations were identified.
8.
Action on Previous Inspection Findings (92701, 92702)
(Closed) IFI 327, 328/92-35-04, Potential Design Deficiency for Auxiliary Building Fans. The ;ssue involved identification of a potential plant design deficiency during testing of the control room l
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building emergency ventilation system received an auto start signal from
other than a containment isolation condition.
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The licensee evaluated the inspectors concern regarding the potential
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design deficiency. The issue was assigned as item # 236.000 on the Nuclear Engineering design issues list. Design includes a signal to
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stop the subject fans on any CREVS actuation signal.
System engineering personnel confirmed that modification work is scheduled to be completed i
prior to either units' restart.
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Within the areas inspected, no violations were identified.
9.
Exit Interview l
The inspection sccpe and results were summarized on June 9, 1993 with those individuals identified by an asterisk in paragraph I above. The
inspectors described the areas inspected and discussed in detail the
inspection findings listed below.
Proprietary information is not contained in this report. Dissenting comments were not received from the licensee.
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i Item Number Descriotion and Reference IFI 327/93-16-01 Followup on Licensee Evaluations for l
Containment Electrical Penetration
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Leakage on Unit 1 (paragraph 5.b).
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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 ANSI -
American National Standards Institute
ASOS -
Assistant Shift Operations Supervisor AU0
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Assistent Unit Operator
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Backlog Review Committee
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CAQR -
Condition Adverse to Quality Report
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CFR
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Code of Federal Regulations CPM
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Counts Per Minute
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CREVS -
Control Room Emergency Ventilation System
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Containment Ventilation Isolation DCR
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Design Change Request i
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Division of Reactor Projects EDG
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Emergency Diesel Generator ERCW -
Essential Raw Cooling Water ESF
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Engineered Safety Feature
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Flow Control Valve FSAR -
Final Safety Analysis Report
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GPM
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Gallons Per Minute l
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IFI
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Inspector -ollowup Item Inservice Inspection ISI
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KV
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Kilovolt LC0
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Limiting Condition for Operation LER
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Licensee Event Report
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Masters Issue List MRRC -
Management Restart Review Committee NRC
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Nuclear Regulatory Commission NRR
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Nuclear Reactor Regulation PCV
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Pressure. Control Valve PERP -
Plant Evaluation Review Panel FMT
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Post-maintenance Test QA
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Quality Assurance RCS
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NRC Region II RWP
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Radiation Work Permit SCFH -
Standard Cubic Feet Per Hour SI
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Surveillance Instruction System Operations
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System Operating Instruction SOS
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Shift Operating Supervisor SR0
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Senior Reactor Operator SSP
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Site Standard Practice TACF -
Temporary Alteration Change Form TS
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Technical Specifications UD
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Unit Operator URI
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inresolved Item VIO
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Violation WO
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Work Order WR
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Work Request i
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