ML16139B081
| ML16139B081 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/10/1995 |
| From: | Taylor J NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| To: | Pate Z INSTITUTE OF NUCLEAR POWER OPERATIONS |
| References | |
| NUDOCS 9507120279 | |
| Download: ML16139B081 (10) | |
Text
July 10, 1995 Mr. Zack T. Pate President and Chief Executive Officer Institute of Nuclear Power Operations 700 Galleria Parkway Atlanta, Georgia 30339-5957
Dear Mr. Pate:
On March 8, 1995, you informed me of a concern in which you believed an NRC Resident Inspector exceeded his regulatory authority by taking over operational control of the recovery actions at Oconee Unit 3, following a reactor trip on August 10, 1994. In response to your concern, I directed the NRC staff to conduct a review of the reactor trip and the circumstances surrounding the subsequent recovery actions.
Based upon a comprehensive review of available records and interviews with the key personnel involved in the event, including NRC staff and the Duke Power Company personnel, we have concluded that the Resident Inspector did not exceed his authority. While it was determined that some members of the Oconee Operations staff believed that the NRC delayed Oconee's response to the event, this perception was apparently due to a mis-communication by the licensee's management. I have enclosed the staff's detailed review of this event for your information (Enclosure 1).
Additionally, you indicated that there were two other events in which the NRC staff's actions may not have been appropriate. These issues will be addressed with Mr. Joe Colvin of the Nuclear Energy Institute (NEI) in separate correspondence.
I believe that these concerns serve to underscore the importance of clear communications between the NRC and licensees. The Commission recently issued a policy statement to.establish its expectations in this regard. It is enclosed for your information (Enclosure 2).
If you have any questions, please call me or Mr. James L. Milhoan.
Sincere1ginal SIgnod by 30" IA.
Trallor James M. Taylor Executive Director for Operations
Enclosures:
As stated DISTRIBUTION:
EDO rf DEDR rf Public JTaylor JMilhoan VMMcCree SEbneter CChristensen RO:DEDR C:RO:DEDR DEDR ED HOChristensen VMMcCree JLMilhoan JM ylor 06/30/95 06/30/95 07/06/95 document name:q:\\dedr\\pate enc doc names:g:\\dedr\\pate2: policy.vmm 9507120279 950710 L, CENT COPY PDR ADOCK 05000287 G
PDR 1_
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-4001 June 30, 1995 Mr. J. W. Hampton Vice President, Oconee Site Duke Power Company P. 0. Box 1439 Seneca, South Carolina 29679
SUBJECT:
SUPPLEMENTAL RESPONSE TO IE BULLETIN 80 OCONEE UNITS 1, 2, AND 3
Dear Mr. Hampton:
By letter dated August 19, 1993, you informed us of a conceptual design modification to address the issue of potential containment overpressurization as a result of a main steamline break (MSLB) inside containment and a schedule for implementation of the modification. This schedule would implement the modification on Oconee Unit 3 during the end-of-cycle (EOC) 15 outage (start June 1995), Oconee Unit 1 during the EOC-16 outage (start October 1995), and Oconee Unit 2 during the EOC-15 outage (start March 1996).
Our letter dated October 6, 1993, found that the approach described in your letter was an acceptable response to address the concerns of Inspection and Enforcement Bulletin (IEB) 80-04, and found the implementation schedule acceptable.
Your letter dated June 14, 1995, informed us of a delay in the implementation schedule for Oconee Unit 3, and provided a description of changes to the original conceptual design of the proposed modification. For the same reasons we found your original schedule acceptable, we find the delay in the schedule for Oconee Unit 3 until the EOC-16 outage (start November 1996) acceptable.
However, it must be stressed that we expect licensees to meet committed schedules, and changes to such schedules should be supported by adequate justification. Notification of the need for a schedule change should be made as soon as known to allow for staff evaluation and appropriate action.
If you have questions regarding this matter, contact me at (301) 415-1495.
Sincerely, conard A.Wiens, Senior Project Manager Project Directorate 11-2 Division of Reactor Projects-I/Il Office of Nuclear Reactor Regulation Docket Nos. 50-269, 50-270 and 50-287 cc: See next page REVIEW OF NRC INVOLVEMENT IN OCONEE STEAM GENERATOR DRYOUT EVENT
- 1.
Concern A concern was expressed that on August 10, 1995, a Resident Inspector at Oconee exceeded his regulatory authority by taking over operational control of an event. Specifically, it was stated that following a reactor trip with a stuck open turbine bypass valve, which led to dryout of one of the two steam generators, a Resident Inspector told Oconee operators not to refill the steam generators until after a conference call was held with the NRC staff.
- 2.
Approach A comprehensive review of this concern was conducted by reading all available records of the event and by interviewing the key NRC and licensee personnel.
Specifically, a review was conducted of Duke Power Company's 50.72 report, licensee event report (LER), and the NRC's Preliminary Notification, inspection report, Notice of Violation, and related NRC/Duke Power Company correspondence.
Following the review of the documents, interviews were conducted in Region II, at the site, and at NRC Headquarters in Washington with the following people:
Region II Region II Deputy Regional Administrator Reactor Projects Section Chief Reactor Projects Project Engineer for Oconee NRC Headquarters Director, Division of Reactor Projects -
I/II, NRR Deputy Director, Division of Engineering, NRR Director, Division of Reactor Controls and Human Factors, NRR Oconee Project Manager, NRR Oconee Site Oconee Site Vice President (Duke Power Company)
Oconee Plant Manager (Duke Power Company)
Senior Resident Inspector (RH)
All three Resident Inspectors (RH)
The results of the document review and interviews are provided in Sections 4 and 5 of this attachment.
0 0
-2
- 3.
Background
At 4:25 a.m., on August 10, 1994, Oconee Unit 3 experienced a reactor trip from 100 percent power. The cause of the trip was the loss of both main feedwater (MFW) pumps. The automatic trip of both main feedwater pumps occurred as required when the associated Integrated Control System (ICS) temporarily lost power (less than 1 second).
The temporary loss of ICS power occurred when fuses internal to the 3KI inverter blew.
Power to the ICS was restored when the "ASCO" transfer switch, immediately downstream of the inverter, automatically transferred to the alternate power source (AC Regulated Power System). When the ICS was repowered, the Turbine Bypass Valve (TBV) went to manual and randomly positioned at 22% open for the steam generator 3B valves and 11% open for the steam generator 3A valves. The operators did not immediately recognize the temporary loss of panel board KI, or the status of the TBVs. Due to the subsequent divergence of steam generator pressures (i.e., steam generator 3B at 600 psig and steam generator 3A at 800 psig) and Reactor Coolant System (RCS) cooldown, a steam leak was suspected.
This prompted the isolation of the 3B steam generator, which was completed at 4:27 a.m., with the 3B steam generator pressure at 550 psig. A Notice of Unusual Event (NOUE) was made at 4:57 a.m.,
due to the secondary side depressurization, which required entry into the "Excessive Heat Transfer" section of the Emergency Operating Procedures (EOP).
The lowest post-trip RCS temperature was 524 degrees fahrenheit. The lowest pressurizer level was 35 inches. After the isolation of the 3B steam generator, RCS average temperature (Tave) was maintained at approximately 538 degrees fahrenheit with the 3A Motor Driven Emergency Feedwater (MDEFW) pump and the Turbine Driven Emergency Feedwater (TDEFW) pump feeding the 3A steam generator. Additionally, a small amount of emergency feedwater was leaking past isolation valve FDW-316 into the 38 steam generator. This leakage was not enough to establish any level in the 3B steam generator, but did maintain steam generator pressure at approximately 800 psig on 3B (saturation pressure for water at 538 degrees fahrenheit is 946.88 psia). The steam generator pressure readings indicated that the 3B steam generator was dry with only a steam atmosphere. The leakage into the 3B steam generator only became apparent much later (7:51 a.m.), after the TDEFW pump was secured and the 3B steam generator pressure began to decrease.
With the primary plant stable, and the 3B steam generator maintaining approximately 800 psig, the operators elected to maintain the 3B steam generator isolated until after shift turnover (6:30 a.m.).
This was due in part to the perceived risk of feeding this essentially dry steam generator with relatively cold emergency feedwater.
Although guidance existed in the licensee's EOP for recovering a hot/dry steam generator, due to the amount of time the SG had been isolated, the licensee contacted the steam generator vendor (Babcock & Wilcox) to
-3 consult over concerns of possible thermal shock to the tube sheet region upon initiation of feedwater. B&W indicated that there were no additional concerns associated with recovering the steam generator and that they should follow their existing EOP guidance. At approximately 7:51 a.m., the TDEFW pump was secured which caused the 3B steam generator pressure to slowly decrease. After the 3B steam generator pressure began decreasing, the differential temperature between the steam generator shell and tubes began to increase. As the licensee prepared to recover the 3B steam generator, they became aware that there was a limit of 60 degrees for the differential temperature (tubes hotter than the shell) listed in the Babcock & Wilcox Technical Basis Document.
At 11:33 a.m., the 3B MDEFW pump was restarted, which due to the leakage past 3FDW-316, allowed some recovery of pressure (and differential temperature) in the 3B SG. At approximately 11:50 a.m.,
MFW pump B was restarted and used to feed SG 3A. At 12:02 p.m., a combination of MFW and EFW was used to feed SG 3B through the auxiliary feedwater ring. At approximately-1:00 p.m., the level and pressure in steam generator 3B were recovered. At 1:37 p.m., on August 10, 1994, the licensee exited the NOUE and remained in hot shutdown to conduct their post trip review.
The timeline of the event and recovery actions is attached.
- 4.
Results of the Review of the Concern The Senior Resident Inspector was notified of the event by the licensee, and responded to the site at approximately 6:30 a.m. At this time, the event had occurred two hours earlier, the steam generator was still dry, and the licensee had decided to wait until after shift change to refill it.
The Senior Resident Inspector called his supervisor in the Region at approximately 7:00 a.m., leaving a Resident Inspector in the control room to monitor the event. During the 7:00 a.m. call to the Region, the decision was made to request a conference call between the licensee, NRR, and Region II in order to assure the event was clearly understood by the NRC. The Senior Resident conveyed this request to the Plant Manager, and 10:00 a.m. was agreed upon as a convenient time.
Subsequent discussions with the Plant Manager as part of the review of the concern confirmed that he understood this request did not place an operational hold on refilling the steam generator. In fact, the Plant Manager welcomed the opportunity to brief all the involved parties within the NRC at one time, understanding that the quality and currency of the information on the event used by the NRC would influence the decision made regarding NRC's response to the event.
By 7:30 a.m., the Resident Inspector assigned lead responsibility for Unit 3 had relieved the Resident Inspector in the Unit 3 Unit Control Room who was monitoring the recovery activities. Shortly after his arrival in the control room, the Unit 3 Resident Inspector was told by a
-4 member of the licensee's operations support staff that NRC had placed a hold on refilling the steam generator until after a 10:00 a.m.
conference call.
The Resident Inspector immediately contacted the Senior Resident who confirmed with the Plant Manager and Operations Manager that no hold had been placed onOconee with regard to their response to the event. Both the Plant Manager and the Operations Manager stated they understood and had not inferred otherwise. In subsequent discussions with the Plant Manager as part of the review of this concern, he indicated that he and the Operations Manager understood the reason for delaying the refill of the steam generator was based solely on Duke Power Company's decision to proceed cautiously, but his instructions to his subordinates regarding his agreement to a 10:00 a.m.
conference call with NRC had been misinterpreted by some to constitute a hold point in the refilling evolution.
At 10:00 a.m., the conference call was held as scheduled between Region II, NRR, and Duke Power Company. During this call, an NRR reviewer from Mechanical Engineering Branch began asking questions about the EOPs, their basis, and the appropriateness of following them if the result is to trickle feed a dry steam generator with cold emergency feedwater.
Shortly after this line of questioning emerged, the Region II Deputy Regional Aministrator contacted the Director of the Division of Reactor Projects -I/II, NRR (DRP I/II) on a separate telephone line to assure that the operational situation was clearly understood, and that any concerns with Oconee's EOPs or their plan to implement them were conveyed at the appropriate management level.
Following this conversation, the Director, DRP I/II called the Deputy Director, Division of Engineering, NRR (DE) away from the conference call in progress, discussed the issue, and the DE returned to the call and clarified that NRR had no technical problems with Oconee's EOPs. The Deputy Regional Administrator then stated that Region II was neither questioning Oconee's EOPs nor Duke's authority to implement them.
Subsequent discussions with the Plant Manager as part of the review of this issue revealed that the brief discussion and questions about the basis of Oconee's EOPs was a minor distraction, but did not result in any lasting confusion, nor was it a particularly memorable occurrence.
What was memorable to the Plant Manager was that this had been his first event related conference call with the NRC as Oconee Plant Manager and he felt he could have done a better job of organizing and presenting the facts of the event and the recovery plan. In fact, the Plant Manager recalled that the Region II Deputy Regional Administrator had called him the following day to inform him that Duke managers had left the impression of rushing to restart the unit, rather than pursuing a careful and deliberate analysis of the initiating failure, its cause and consequences. The Plant Manager felt this feedback was useful and has helped him improve subsequent communications with the NRC.
-5
- 5.
Conclusions The concern that a Resident Inspector at Oconee exceeded his regulatory authority by taking over operational control of an event was reviewed and found to be without basis. While this perception was held to be true by some of the Oconee operations.staff, it was the result of a miscommunication on the part of Duke management, rather than inappropriate actions by the Resident.
Attachment:
Oconee Steam Generator Timeline
OCONEE STEAM GENERATOR DRYOUT TIMELINE August 10, 1994 0426 Unit 3 tripped due to a momentary loss of the Integrated Control System's power. This loss of power tripped both main feed pumps by providing a false high S/G level -signal and caused the turbine bypass valves to fail partially open (22% for S/G 3B and 11% for S/G 3A).
0427 Operators isolated S/G 3B due to a suspected steam leak.
0442 Unit 3 was stabilized in hot shutdown with decay heat removal via forced RCS flow with 3A S/G being fed by emergency feedwater and 3B S/G, isolated and essentially dry.
0457 NOUE declared due to secondary side depressurization and entry into EOP for excessive heat transfer.
0513 50.72 Report made which stated, "the Resident Inspector will be notified." Resident(s) subsequently respond to the site.
0630 Residents arrive on site. Shift change occurs. The transient was discussed with station management by the Resident Inspectors. A conference call was requested which would include Oconee site management, NRC regional management, NRR, and the Residents to brief the NRC on the event. As a result, some licensee participants concluded the NRC position was that 3B S/G should not be fed without prior NRC concurrence. When the Resident realized this impression was given, he clarified that the licensee had the authority to decide on actions to cope with plant transients.
1000 The conference call requested by Region II management to discuss Oconee's plan to trickle feed the dry S/G with emergency feedwater is conducted.
1115 Licensee completed S/G Recovery Plan development after contacting the S/G vendor (B&W) and considering the potential problems with cold feeding a S/G.
1205 Licensee begins feeding 3B S/G with a combination of main (hot) and emergency (cold) feedwater.
1330 3B S/G is refilled.
1337 NOUE is exited.
0 nclosure 2 NRC POLICY ON COMMUNICATIONS BETWEEN THE NRC AND LICENSEES In 1991 the Commission established the NRC Principles of Good Regulation, a copy of which is attached for reference. As noted in the Principles, the Commission believes that good regulation must be transacted publicly and candidly and that open communications must be maintained with Congress, other government agencies, licensees, and the public. Regulatory actions should always be fully consistent with regulations and should be promptly, fairly, and decisively administered.
The Commission encourages and expects open communications at all levels between its employees and those it regulates. Licensees should feel unconstrained in communicating with the NRC. The Commission also expects that the NRC staff exercise initiative in maintaining open lines of communication and ensure that its regulatory activities are high quality, appropriate and consistent. The Commission recognizes that honest, well intentioned differences in opinions between the staff and the licensee will occasionally occur, and therefore encourages open communications to foster an environment where such differences receive constructive and prompt resolution.
Open communication also extends to the reporting of perceived inappropriate regulatory actions by NRC staff when dealing with licensees. The Commission encourages licensees to provide specific information regarding such concerns.
The NRC will not tolerate inappropriate regulatory actions!J by the NRC staff, nor will it tolerate retaliation or the threat of retaliation against those licensees who communicate concerns to the agency. NRC staff whose actions are found to be contrary to this policy could be subject to disciplinary actions in accordance with the NRC Management Directive 10.99, "Chapter 4171, Discipline, Adverse Actions and Separations," or in accordance with the Collective Bargaining Agreement Between the U.S. Nuclear Regulatory Commission and National Treasury Employees Union.
Inappropriate regulatory actions include activities which exceed the agency's regulatory authority, involve improper application of agency requirements, or adversely affect the agency's regulatory functions.
Examples of inappropriate regulatory actions include, but are not limited to, unjustified inconsistent application of regulations and guidance by NRC staff or management that significantly affect licensee activities and inappropriate action on the part of NRC staff and management that disrupts effective communication with the licensee.
NRC PRINCIPLES OF GOOD REGULATION INDEPENDENT. Nothing but the highest possible standards of ethical performance and professionalism should influence regulation. However, independence does not imply isolation. All available facts and opinions must be sought openly from licensees and other interested members of the public. The many and possibly conflicting public interests involved must be considered. Final decisions must be based on objective, unbiased assessments of all information, and must be documented with reasons explicitly stated.
OPEN. Nuclear regulation is the public's business, and it must be transacted publicly and candidly. The public must be informed about and have the opportunity to participate in the regulatory processes as required by law. Open channels of communication must be maintained with Congress, other government agencies, licensees, and the public, as well as with the international nuclear community.
EFFICIENT. The American taxpayer, the rate-paying consumer, and licensees are all entitled to the best possible management and administration of regulatory activities. The highest technical and managerial competence is required, and must be a constant agency goal.
NRC must establish means to evaluate and continually upgrade its regulatory capabilities. Regulatory activities should be consistent with the degree of risk reduction they achieve. Where several effective alternatives are available, the option which minimizes the use of resources should be adopted. Regulatory decisions should be made without undue delay.
CLEAR. Regulations should be coherent, logical, and practical.
There should be a clear nexus between regulations and agency goals and objectives where explicitly or implicitly stated. Agency positions should be readily understood and easily applied.
RELIABLE. Regulations should be based on the best available knowledge from research and operational experience. Systems interactions, technological uncertainties, and the diversity of licensees and regulatory activities must all be taken into account so that risks are maintained at an acceptably low level.
Once established, regulation should be perceived to be reliable and not unjustifiably in a state of transition. Regulatory actions should always be fully consistent with written regulations and should be promptly, fairly, and decisively administered so as to lend stability to the nuclear operational and planning processes.