IR 05000338/1994007
| ML20029E263 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 05/05/1994 |
| From: | Belisle G, Mcwhorter R, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029E260 | List: |
| References | |
| 50-338-94-07, 50-338-94-7, 50-339-94-07, 50-339-94-7, NUDOCS 9405180063 | |
| Download: ML20029E263 (13) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION 3'
'1 REGION 11
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S 101 MARIETTA STREET, N.W., SUITE 2900 To
- p ATLANTA, GEORGIA 30323 0199
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Report Nos.:
50-338/94-07 and 50-339/94-07 Licensee: Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:
50-338 and 50-339 License Nos.:
NpF-4 and NpF-7 Facility Name:
North Anna 1 and 2 Inspection Conducted: March 20 through April 16, 1994 J
Inspectors:
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Sr J-79 R. D.
horter, Senior Resident Inspector Date Signed WN m i k]. N.,
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'D. R. Eaylor, Resident Inspector Date Signsd
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Approved by:
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G; A. Belisle tSection Chief Date Signed r
Division of Reactor Projects SUMMARY l
Scope:
j This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance observations, and Licensee Event Report followup.
Licensee backshift activities were inspected on Marr.h 20, 21, 22, 23, 27 and April 1 and 8, 1994.
Results:
Plant Operations functional area During repairs to a moisture separator reheater drain tank manway cover, operators deviated from an abnormal procedure. The procedure called for tripping the main turbine, but this was not done due to personnel safety concerns.
The decision to wait to trip the turbine was justified; however, command and control for the evolution were weak. An Unresolved Item was identified to review the administrative process for procedure deviations (paragraph 4.b).
9405100063 940505 PDR ADOCK 05000338
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Maintenance functional area Individual Rod Position Indication power supply failures resulted in several entries into Technical Specification (TS) 3.0.3.
Difficulties identifying an intermittently failing component led to additional TS 3.0.3 entries.
Operators met required TS action time limits, and the condition was appropriately reported to the NRC (paragraph 3.a).
Continuing efforts to identify and correct a water intrusion problem with the turbine driven auxiliary feedwater pump oil system improved but did not totally resolve the problem (paragraph 4.a).
Plant Support functional area Overtime control for plant staff was adequate.
Licensee management's attention in this area has significantly reduced overtime use (paragraph 3.b).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees L. Edmonds, Superintendent, Nuclear Training C. Funderburk, Superintendent, Outage and Planning J. Hayes, Superintendent, Operations D. Heacock, Superintendent, Station Engineering
- J. Hegner, Supervisor, Licensing
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing
- C. Kube, Supervisor, Administrative Services
- W. Matthews, Assistant Station Manager, Operations and Maintenance J. O'Hanlon, Vice President, Nuclear Operations D. Roberts, Supervisor, Station Nuclear Safety
- R. Saunders, Assistant Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Maintenance
- J. Smith, Manager, Quality Assurance A. Stafford, Superintendent, Radiological Protection
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- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing Other licensee employees contacted included managers, supervisors, operators, engineers, technicians, mechanics, security force members, and office personnel.
NRC Personnel
- R. McWhorter, Senior Resident Inspector
- D. Taylor, Resident Inspector
- Attended Exit Interview on April 26, 1994.
- Attended Exit Interview on May 4, 1994.
Acronyms and initialisms used throughout this report are listed in the last paragraph.
On March 25, 1994, the licensee announced that Mr. W. Stewart, Senior Vice President, Nuclear, was retiring effective June 1, 1994.
Mr. J. O'Hanlon, Vice President, Nuclear Operations, was selected to replace Mr. Stewart. Mr. R. Saunders, Assistant Vice President, Nuclear Operations, was selected to replace Mr. O'Hanlon.
On April 13, 1994, the licensee announced that the following personnel changes would take place at North Anna, effective June 1,1994:
Mr. G. Kane, Station Manager, will retire; Mr. J. Stall, Assistance Station Manager, Nuclear Safety and Licensing, will replace Mr. Kane; Mr. D. Heacock, Superintendent, Station Engineering, will replace Mr. Stall; and Mr. B. Shriver, Director, Corporate Nuclear Safety, will replace Mr. Heacoc On April 13 and 14, 1994, the NRC Region 11 Section Chief, Mr. G. A. Belisle visited North Anna. Mr. Belisle attended meetings with local public officials, toured the site with the inspectors, and met with licensee management to discuss current issues at the facility.
2.
Plant Status Unit 1 operated the entire inspection period at or near 100% power. On April 9,1994, the unit had operated continuously for one year since the spring 1993 steam generator replacement outage.
Unit 2 began the inspection period at 100% power. On April 2, 1994, power was reduced to approximately 8% to effect repairs on an MSR drain tank manway cover (paragraph 4.b).
Later that day, the unit was shut down for additional repairs. The unit was restarted on April 3, and 100% power was attained on April 5.
The unit remained at or near 100%
power for the remainder of the inspection period.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with TS.
Instrumentation and safety system lineups were periodically reviewed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection program implementation, radiological work practices, plant security, and housekeeping. DRs were reviewed to assure that potential safety concerns were properly reported and resolved.
a.
Rod Position Indication Problems On March 18, 1994, the licensee experienced the first of several problems with the IRPI system which resulted in entering TS 3.0.3 LCO requirements.
The IRPI system included 48 analog meters which provided individual position indications for each of the 48 reactor control rod assemblies. The' individual indications supplemented computer and group demand position indications, and their operation was governed by TS LCO 3.1.3.2.
This TS LCO allowed one IRPI channel per group to differ from other indications by greater than twelve steps provided that actions stated in the TS were followed. The initial events were:
Data Time Event March 18 5:58 a.m.
Operators received multiple computer j
alarms and noted that.almost all IRPIs were increasing.
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Rita Time Eyvsni March 18 7:02 a.m.
TS 3.0.3 was entered when two IRPIs in the same group were greater than twelve steps from the rod group step counter demand position indication.
March 18 7:04 a.m.
TS 3.0.3 was exited when one rod's indication was returned within the twelve steps criteria.
Initial investigations by I&C personnel found that the output from the IRPI cabinet power supply was fluctuating and injecting errors into the instruments. A defective transformer voltage regulator was suspected. The licensee continued to monitor the system.
On March 20, additional fluctuations in IRPIs were observed.
However, only one rod exceeded the twelve steps criteria, and an entry into TS 3.0.3 was not required. On March 21, the licensee designed temporary modification N2-J1067 to allow connecting a
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temporary power supply to the IRPI system. The licensee proposed
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installing a jumper from an alternate unregulated power supply transformer on the opposite safety bus to the IRPI system.
The inspectors reviewed the proposed temporary modification in detail using electrical prints to verify that safety-related electrical busses would not be cross-connected and that the alternate power supply would be adequate to support IRPI operability. The inspectors concluded that the temporary modification was suitable for the work. The installation required entry into TS 3.0.3 since the IRPI system would lose all power during the change.
The following TS 3.0.3 entries were then made:
Date Time Event March 22 2:40 p.m.
TS 3.0.3 was entered to install the temporary modification.
The inspectors attended the pre-evolution brief and monitored the installation from the control room and the work site.
No complications resulted.
March 22 2:49 p.m.
TS 3.0.3 was exited after completing the temporary modification installation.
From March 22 through 24, troubleshooting performed by the licensee could not positively identify a failure mechanism.
Technicians cleaned the regulator, including a dirty rheostat, and set up a dummy load and recorders to monitor regulator performance. The regulator appeared to function properly, and no additional failures were noted. The licensee decided to return
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the IRPI system to its normal power supply. During this evolution, the following events occurred:
Ra_tg Time Even1 March 25 4:25 p.m.
TS 3.0.3 was entered for temporary modification removal.
March 25 4:39 p.m.
TS 3.0.3 was exited after technicians successfully restored the IRPI system to its normal power supply.
March 25 4:42 p.m.
TS 3.0.3 was entered when the power supply failed again, and two IRPIs in the same group exceeded the rod group step counter demand position indication by twelve steps.
March 25 4:48 p.m.
TS 3.0.3 was exited after technicians
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adjusted the power supply regulator and
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the IRPIs returned to within specifications.
The licensee decided to return the IRPI system to the alternate power supply pending further
investigations.
March 25 5:00 p.m.
TS 3.0.3 was entered for reinstalling the temporary modification.
March 25 5:10 p.m.
TS 3.0.3 was exited after technicians successfully reinstalled the temporary modification.
From March 26 through April 6, the licensee continued repair efforts. This subsequent troubleshooting identified a defective capacitor. The capacitor failed intermittently and was not identified during the first repair attempts. The capacitor was replaced and the power supply was satisfactorily retested.
Following this work, the following actions were taken to return the IRPI system to nonnal alignment:
Ralg Time Event April 7 2:35 p.m.
TS 3.0.3 was entered to remove the temporary modification.
April 7 2:39 p.m.
TS 3.0.3 was exited after technicians successfully restored the IRPI system to its normal power supply.
No further problems occurred as the IRPI system indicated normally for the remainder of the inspection period. The licensee reported
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these entries into TS 3.0.3 to the NRC in LER 50-339/94-04. The inspectors concluded that the licensee met TS LC0 action statement time limits and 10 CFR 50.73 reporting requirements.
However, the licensee's difficulties in positively identifying a failure mechanism during the first maintenance attempt resulted in additional entries into TS 3.0.3.
The inspectors concluded that the licensee returned the power supply to service without positively identifying a failure mechanism. The licensee stated that due to the difficulty in identifying the intermittent problem, the actions taken during troubleshooting were appropriate.
b.
Overtime Usage The inspectors assessed the licensee's overtime usage including reviewing overtime for the previous two refueling outages.
Overtime usage had also been reviewed by the inspectors in April 1992 and violation 50-338, 339/92-13-02 was issued. Corrective actions were completed, and the violation was closed in NRC Inspection Report Nos. 50-338, 339/93-27.
The inspectors found that TS Table 6.2-1 required that the licensee establish procedures to ensure that NRC policy statement j
guidelines regarding work hours established for employees were followed. The NRC policy statement guidelines were depicted in Generic Letter No. 82-12, Nuclear Power Plant Staff Working Hours.
The licensee's program to meet these guidelines was established in VPAP-0103, Working Hours and Limitations, revision 2.
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inspectors found that this procedure established proper controls for overtime usage.
The inspectors reviewed the licensee's monthly administrative reports for overtime usaga since January 1993.
These reports summarized overtime amounts for various station departments and'
identified situations where overtime limits were possibly exceeded. Also, the inspectors reviewed timesheet records for selected work weeks during the last two unit refueling outages, spring 1993 and fall 1993.
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The inspectors found that overtime for key station personnel (operators, maintenance and health physics)-was properly tracked and reported to station management.
For those personnel that exceeded limits without prior approval, station DRs were written and appropriate corrective actions were taken. The site QA group also reviewed overtime and initiated DRs for problems identified.
The inspectors found that management reviewed these DRs and held personnel and supervisors accountable for overtime problems.
The timesheet reviews did not identify any situations where overtime limits were exceeded without prior approval or later identification and DR submission.
The inspectors concluded that for key station personnel overtime was well controlle.
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The inspectors also reviewed station engineering overtime.
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inspectors noted that engineering was not considered to be part of the plant organization and was not included in the monthly administrative report.
Station management indicated that they expected all personnel (station and non-station) to meet the VPAP requirements.
The inspectors identified and informed licensee management that engineering personnel did not correctly consider a floating seven day work week with respect to the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in seven days working hours limit. The inspectors noted that for non-station personnel, this was not a regulatory requirement.
But, management indicated that the condition did not meet their expectations and would be corrected.
Overall, the inspectors concluded that overtime was being adequately controlled. A substantial improvement in overtime controls was noted as a result of the corrective actions taken for the April 1992 violation.
Station management was very active in assuring that overtime requirements were being met. The inspectors also noted that overtime usage for the October 1993 outage was significantly less than for the previous outage.
c.
NRC Notifications On March 28, 1994, the licensee notified the NRC as required by
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10 CFR 50.72 concerning the notification of off-site authorities.
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Specifically, the licensee issued flood warnings to the highway departments of surrounding counties.
The flood warnings were in accordance with plant procedures following large discharges from the Lake Anna Dam due to heavy rains. The inspectors reviewed these notifications and verified that there were no NRC safety-related concerns associated with the events.
No violations or deviations were identified.
4.
Maintenance Observations (62703)
Maintenance activities were observed and reviewed to verify that activities were conducted in accordance with TS, procedures, regulatory guides and industry codes or standards, a.
Unit 2 TDAFW Pump Repair The inspectors followed the licensee's continued repair efforts to correct a water intrusion problem into the turbine oil reservoir for the Unit 2 TDAFW pump. On March 30, 1994, the licensee attempted to repair the problem by injecting a leak sealant compound into the turbine casing areas near the suspected leakage points. After the repair, the intrusion rate decreased by about one half.
However, the problem was not totally resolved.
The pump was returned to an operable status. The inspectors observed selected maintenance activities and verified that operability
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requirements were met. No problems were identified with the maintenance activities.
The licensee did not plan any additional maintenance to correct the water intrusion problem until the next refueling outage since the additional efforts would require excessive pump outage time.
Deferring further work until the next refueling outage reflected an appropriate consideration for maintaining the TDAFW pump available during operations, b.
Unit 2 MSR Drain Tank Manway Maintenance On April 2,1994, the inspectors observed the licensee's attempt to repair a leaking manway cover on 2-SD-TK-2C, the MSR drain tank. The repairs were planned to be performed with the unit at approximately 8% reactor power (50 MWe). This power was selected since it represented the point at which the unisolable tank would be at atmospheric pressure. At this low power level, operators were to keep tank pressure at atmospheric by maintaining a balance between the steam leaving the tank to the main condenser and the steam entering the receiver from the MSRs.
They were to do this by two methods. The first method was to throttle the high level divert manual isolation valve to control flow from the tank to the condenser.
The second method was to adjust turbine load to control flow into the tank. With the flows into and out of the tank balanced, maintenance personnel were to replace the manway.
The inspectors attended the pre-evolution brief for operators, observed the power reduction from 30% to 8%, and observed the maintenance. With stable conditions established and zero pressure indicated in the tank, maintenance began repair attempts.
Several minutes after the manway cover was removed, condenser vacuum started to rapidly deteriorate. Absolute vacuum declined from 0.3 in-Hg to 4.6 in-Hg in approximately three minutes.
This vacuum exceeded the point at which abnormal procedures required operators to trip the turbine.
Specifically, 2-AP-14, low Condenser Vacuum, revision 5, immediate action step two, stated, " MONITOR CONDENSER PRESSURE - 3.5 INCHES HG ABS OR LESS".
The response not obtained column applying to this situation then-stated, "J1 Reactor power is 10% or less, JJiB trip turbine and GO TO 2-AP-2.1, TURBINE TRIP WITHOUT REACTOR TRIP REQUIRED." The shift supervisor elected not to trip the turbine citing the safety of personnel in the area as the primary reason.
Tripping the turbine had the potential to increase the MSR drain tank pressure and to blow steam out of the uncovered manway thereby posing a significant health hazard to personnel in the immediate area.
The inspectors questioned the operators' decision to not trip the turbine as required by the AP.
The inspectors reviewed plant
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strip chart recorders and operator logs, interviewed personnel, and compiled the following timeline for the April 2 event:
Time:
Event:
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1:00 a.m.
Commenced ramp down from 100% power 5:12 a.m.
Reactor stable at 30% power 6:45 a.m. -
Shift turnover 7:30 a.m.
8:41 a.m.
Commenced ramp down from 30% reactor power 11:17 a.m.
Power at 8%, 50 MWe, began pressure balance of MSR drain tank 11:30 a.m.
MSR drain tank at atmospheric pressure, 8.5%
reactor power, 52 MWe 11:45 a.m.
Log entry:
"cond vacuum decreasing, entered AP-14, vacuum stabilized at approximately 4.6 psia and immediately began to improve, submitted DR. Electrical output stable at 37 MW."
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The inspectors questioned the shift supervisor 12:15 p.m.
regarding requirements to trip the turbine and was iaformed that due to personnel safety considerations, the turbine was not tripped.
The shift supervisor indicated that station management was aware of the situation.
During this period, the new manway cover was installed.
12:19 p.m.
Log entry:
" Condenser vacuum is restored to less than 3.5 in-Hg."
12:45 p.m.
Unit power increase commenced 13:29 p.m.
At approximately 22% reactor power, it was determined by licensee management that the tank manway repairs were unsuccessful and a decision was made to shut down the unit for further repairs.
On April 5, the inspectors questioned the basis for the AP step.
The inspectors were informed that the AP-was revised in 1991 to incorporate Westinghouse recommendations for low power turbine operations with high backpressure.
The licensee had experienced turbine blade failures which were potentially due to operating at i
these conditions in 1986 and again in 1991.
The licensee j
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l contacted Westinghouse concerning this event. Westinghouse stated
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turbine during the next refueling outage.
On April 8, the inspectors interviewed the operating shift. The inspectors determined that the operators had received simulator training specifically for this evolution, including a i
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loss-of-vacuum condition requiring a trip. During that training, the turbine had been tripped in accordance with the AP.
During the actual event, the Unit Supervisor indicated that the order was given to trip the turbine.
The turbine operator l'
(a licensed reactor operator) was ready to trip the turbine and l
communicated to the phone talker at the MSR drain tank that the turbine would be tripped.
While they were waiting for the area to be cleared, the Superintendent, Operations, came to the control room to discuss the situation. About that same time, condenser vacuum started to recover. Approximately 34 minutes elapsed with condenser vacuum above the point requiring a manual turbine trip without action being taken.
Each operator involved indicated that plant management presence and knowledge of the situation gave tacit approval to their inaction concerning tripping the turbine.
An administrative procedures review determined that OPAP-0002, Operations Department Procedures, revision PN01-2, Section 6.3 Operating Procedure Usage required that in the judgement of the qualified operator performing a step, if completion of the step could result in an unsafe condition, then conduct of the procedure shall be stopped, the system and component placed in a safe condition and the Shift Supervisor notified. However, Section 6.3 specified that this requirement did not apply to APs. VPAP-0502, Procedure Process Control, revision 5, paragraph 6.3.10.a required that a cognizant individual shall present an intent change to SNSOC for approval prior to use.
Since not performing the immediate action to trip the turbine was an intent change and SNSOC appoval required a significant amount of time, operators had no options for administratively handling this situation.
Based on the above information, the inspectors identified the following weaknesses:
1)
The inspectors agreed that the safety of personnel needed to be considered prior to taking the action required by the AP.
However, operators failed to clearly maintain command and control of the situation. After the initial word to clear the area and trip the turbine was given, operators failed to either carry out or formally rescind the order.
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Specific administrative guidance for dealing with this and similar type events was not clearly establishe.
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As a result of the event, DR 94-413 was initiated. The DR response indicated that a policy concerning procedure deviations would be developed by June 30, 1994, to provide instructions for operators when faced with similar situations.
Pending development of this policy and associated instructions and subsequent review by the inspectors, this item is identified as URI 50-338, 339/94-07-01, Review Policy Concerning Procedure Deviations.
Also, identified corrective actions in DR 94-413 indicated that management would review the existing policy on management oversight of station evolutions and determine if changes are necessary.
Furthermore, the event was discussed with the shift personnel involved.
One URI was identified.
5.
Information Meetings with Local Officials On April 13 and 14, 1994, the inspectors and the regional Section Chief met with local officials. Officials attending these meetings included the Local Emergency Coordinators and other officials for the five Virginia counties (Spotsylvania, Caroline, Hanover, Louisa and Orange)
located within the North Anna Emergency Planning Zone. The inspectors briefed the local officials on NRC functions, discussed communications between the NRC and local officials, and briefed the officials on emergency response and other local interest items.
The inspectors found that the local officials generally praised the licensee for good communications concerning emergency planning issues.
6.
Licensee Event Report Followup (92700)
The following LER was reviewed.
The inspectors verified that reporting requirements had bean met, causes had been identified, corrective actions appeared appropriate, and generic applicability had been considered.
(Closed) LER 50-339/94-04, Multiple Individual Rod Position Indicators Inoperable Due To Faulty Capacitor The inspectors reviewed this LER and followed the licensee's corrective actions in replacing the defective component. TS action statement and reportability requirements were verified to be met (paragraph 3.a).
No violations or deviations were identified.
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Exit Interview The results were summarized on April 26 and May 4,1994, with those persons identified in paragraph 1.
The inspectors described the areas
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II inspected and discussed in detail the inspection results addressed in the Summary section and those listed below.
Iyng Item Number Status Description URI 50-338, 339/94-07-01 Opc Review Policy Concerning Procedure Deviations
(paragraph 4.b)
LER 50-339/94-04 Closed Multiple Individual Rod Position Indicators Inoperable Due To Faulty Capacitor (paragraph 6)
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
8.
Index of Acronyms and Initialisms AP ABNORMAL PROCEDURE CFR CODE OF FEDERAL REGULATIONS DR DEVIATION REPORT I&C INSTRUMENTATION AND CONTROL IRPI INDIVIDUAL ROD POSITION INDICATION LER LICENSEE EVENT REPORT LC0 LIMITING CONDITION FOR OPERATION MSR MOISTURE SEPARATOR REHEATER
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MWe MEGAWATTS ELECTRICAL
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NUMBERS
NRC NUCLEAR REGULATORY COMMISSION
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PAR PROCEDURE ACTION REQUEST QA QUALITY ASSURANCE SNSOC STATION NUCLEAR SAFETY AND OPERATING COMMITTEE TDAFW TURBINE-DRIVEN AUXILIARY FEEDWATER TS TECHNICAL SPECIFICATION i
URI UNRESOLVED ITEM
VPAP VIRGINIA POWER ADMINISTRATIVE PROCEDURE
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