IR 05000366/2006012

IR 05000366-06-012 on 04/10/2006 - 04/12/2006 for Edwin I. Hatch, Unit 2; Special Inspection

ML061450166
Person / Time
Site:	Hatch
Issue date:	05/24/2006
From:	Casto C Division Reactor Projects II
To:	Sumner H Southern Nuclear Operating Co
References
IR-06-012
Download: ML061450166 (16)

Text

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT - NRC SPECIAL INSPECTION REPORT 05000366/2006012

Dear Mr. Sumner:

On April 12, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed a Special Inspection at your Hatch Unit 2 facility. On April 5, 2006, the Unit 2 turbine tripped, with a subsequent reactor scram. Because automatic steam sealing equipment was isolated, lowering condenser vacuum resulted in a loss of the only operating feedwater pump. These events were evaluated by the NRC in accordance with Management Directive 8.3, NRC Incident Investigation Program, and a Special Inspection was initiated because the event involved significant unexpected system interactions, and the risk evaluation value exceeded the minimum required for a Special Inspection.

The enclosed report documents the inspection results, which were discussed on April 12, April 21 and April 27, 2006, with Mr. Dennis Madison and other members of your staff. The determination that the inspection would be conducted was made by the NRC on April 6, 2006, and the inspection started on April 10, 2006.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of

SNC 2 NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Charles Casto, Director Division of Reactor Projects Docket No.: 50-366 License No: NPF-5

Enclosure:

Inspection Report 05000366/2006012 w/Attachments Attachments: 1. Supplemental Information 2. Sequence of Events

__ML061450166 OFFICE RII:DRP RII:DRP SIGNATURE DSS NPG by email NAME DSimpkins NGarrett DATE 05/24/06 05/19/06 5/ /2006 5/ /2006 5/ /2006 5/ /2006 5/ /2006 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

SNC 3

REGION II==

Docket No.: 05000366 License Nos.: NPF-5 Report No.: 05000366/2006012 Licensee: Southern Nuclear Operating Company, Inc.

Facility: Edwin I. Hatch Nuclear Plant Location: P.O. Box 2010 Baxley, Georgia 31515 Dates: April 10 through April 12, 2006 Inspectors: D. Simpkins, Senior Resident Inspector (Lead Inspector)

N. Garrett, Senior Resident Inspector Approved by: Charles Casto, Director Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000366/2006-012; 04/10/2006 - 04/12/2006; Edwin I. Hatch Nuclear Plant, Unit 2; Special

Inspection This Special Inspection was conducted by two Region II Senior Resident Inspectors using Inspection Procedure 93812 to investigate the of the loss of all normal feedwater. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

Licensee-Identified Violations

None.

REPORT DETAILS

EVENT OVERVIEW On April 5, 2006, while calibrating the megavars recorder for the Unit 2 turbine generator, a power-load imbalance signal was generated from maintenance activities which resulted in a turbine trip/reactor scram. When both recirculation pumps automatically tripped by design and eight safety relief valves opened, reactor water level increased to above the Reactor Feedwater Pumps (RFP) trip setpoint, and both RFPs tripped. When reactor water level sufficiently lowered, the operators restarted the 2A RFP. However, because of reliability problems in the automatic pressure regulator portion of the steam seal system, sealing steam was being controlled manually. Because the manual control valve had not been adjusted properly, there was insufficient sealing steam to the turbine, which caused condenser vacuum to decrease, and the 2A RFP tripped again because of low condenser vacuum. Operators were eventually able to restore sealing steam in automatic control and stabilized condenser vacuum before the automatic isolation of the bypass valves was reached. The operators manually initiated RCIC and HPCI to restore water level.

Special Inspection Team Charter Based on the criteria specified in Management Directive 8.3, NRC Incident Investigation Procedures, a Special Inspection was initiated in accordance with NRC Inspection Procedure (IP) 93812, Special Inspection. The objectives of the inspection are listed below and are addressed in the following sections.

(1) Develop a sequence of events including applicable management decision points from the time of the previous Unit 2 outage through recovery and unit restart from the event.

(2) Review licensee documents to assess if the licensee knew that a loss of condenser vacuum would occur after a turbine trip without operator action. Specifically, assess the following areas:

! Operational Decision Making

! Operator Workaround assessment

! Impact on Maintenance Rule implementation

(3) Assess any corrective action the licensee took prior to the event to address the steam seal control problem and determine if the actions were appropriate and timely.

(4) Assess operating procedures and operator training concerning this scenario and determine if the procedures and training were adequate for operators to compensate for the lack of the automatic seal steam control function.

(5) Review post-scram cooldown data and determine if operator actions to control cooldown response were within procedural guidance.

(6) Collect data necessary to support completion of the significance determination process.

(7) Review this event for generic safety implications.

4OA3 Event Followup (IP 93812)

.1 Develop a sequence of events and assess corrective actions (Objectives 1, 3 and 6)

a. Inspection Scope

The inspectors developed a detailed sequence of events leading up to the event based on the licensees sequence of events, a review of plant logs, completed work orders and condition reports. The sequence of events (Attachment 2) includes a timeline of observations, corrective actions and work activities that occurred since the previous refueling outage to the time of the event.

b. Findings and Observations

The steam seal system had a history of operational issues prior to the previous refueling outage. Because the system is effectively only in operation to 30% power (above 30%,

the steam sealing function is provided by normal steam leakage from the turbine), few opportunities existed to identify issues and repair the system. However, those opportunities available were appropriately captured and entered into the corrective action program.

.2 Review licensee documents to assess if the licensee knew that a loss of condenser

vacuum would occur after a turbine trip without operator action (Objective 2)

a. Inspection Scope

The inspectors reviewed post-scram interviews, condition reports, and operator logs as well as conducted interviews to determine the extent to which the licensee realized a loss of condenser vacuum would occur after a turbine trip without operator action.

1. Operational Decision Making

The licensee did not consider the automatic steam seal system isolation as applicable to the Operational Decision Making Issue evaluation process, since the limits of the equipment degradation had been reached when the automatic system had been taken out of service via caution tags (i.e., it could not get any worse). Therefore, there were no clear-cut management decision points using this process.

2. Operator Workaround assessment The licensee did not consider the isolated automatic pressure control portion of the steam seal system to be an operator workaround. Therefore, the condition of the system did not receive the attention and resources which could have been available had it been properly categorized. Additionally, the operators were not necessarily as cognizant of the issue as they could have been had this been an operator workaround.

This issue was determined to not be a finding because the licensee was not specifically committed to using the operator workaround program.

3. Impact on Maintenance Rule implementation The Maintenance Rule Scoping Manual Performance Criteria defined a functional failure for the Steam Seal system as a failure which results in a turbine trip or down power of greater than 20%, and furthermore stated this criteria would effectively monitor the performance of the system. However, the inspectors noted such a high threshold for monitoring may not have permitted the licensee to effectively monitor the functional condition of the system. As noted in the sequence of events, numerous condition reports and maintenance work orders had been written for the system, but none had reached the threshold established by the maintenance rule for increased monitoring. As a result, the overall system degradation continued to the point the automatic steam seal function had been isolated.

.3 Assess operating procedures and operator training concerning this scenario and

determine if the procedures and training were adequate for operators to compensate for the lack of the automatic sealing steam control function (Objective 4)

a. Inspection Scope

The inspectors reviewed operating procedures, simulator training programs, Beginning-of-Shift Training, Night Orders, and Operating Orders to determine if the procedures and training were adequate for operators to compensate for the lack of the automatic sealing steam function.

b. Findings and Observations

Although there were several mechanisms which could have been used to provide guidance to operators, the inspectors did not find sufficient training was provided for the operators to compensate for the lack of automatic sealing steam function.

The status of the automatic sealing steam function was tracked via the Unit Supervisor and Control Board Operator turnover sheets on a daily basis. Although the summary section of two condition reports had stated operations personnel were aware of the potential for a loss of condenser vacuum upon a turbine trip, there was no formal guidance given to operators for actions for manually lowering condenser vacuum. Also, the licensee did not revise 34AR-650-125-2, STEAM SEAL PRESS LOW alarm response procedure, to provide guidance for the board operators to control sealing steam pressure in manual in accordance with the caution tag guidance and the system operating procedure. The licensee did, however, send a procedural change notice to the operations staff when the licensee procedure 34SO-N33-001-2, Seal Steam System, had been changed to provide guidance for manual sealing steam pressure control, but there was no tracking or verification of who read the changes.

This lack of training and guidance became evident when, during the event, the operators chose to restore the automatic sealing steam system as guided by the alarm response procedure rather than follow the guidance on the caution tags to manually restore condenser vacuum. Although these actions successfully restored condenser vacuum, previous maintenance and operational history showed it was more fortuitous, rather than expected, that the automatic sealing steam system functioned normally. Had the automatic sealing steam system failed, the operators would have had to recognize the failure, remove the automatic steam seal system from operation and begin controlling the steam seal system in manual, all before condenser vacuum lowered sufficiently to isolate the bypass valves and lose the condenser heat sink. This was not a violation of regulatory requirements because the licensee had not specifically committed to controlling the system in manual.

Additionally, the Maintenance Rule Scoping Manual clearly stated that, although not risk-significant, the loss of sealing steam may require plant shutdown or may cause a plant trip on low condenser vacuum and can result in a loss of feedwater.

.4 Review post-scram cooldown data and determine if operator actions to control cooldown

response was within procedural guidance (Objective 5)

a. Inspection Scope

The inspectors reviewed operator logs, the scram/transient analysis, computer data traces, procedures and cooldown data to determine if operators took the proper actions to control plant cooldown.

b. Findings and Observations

Based on the review, the operators controlled the cooldown in accordance with licensee procedures. However, the operator response was slowed by the decrease in condenser vacuum and trip of the only RFP.

When the reactor scrammed, the recirculation pumps tripped by design, and temperatures in the vessel increased because of a lack of forced circulation. Licensee procedure 34AB-C71-001-2, Scram Procedure, cautions operators the bottom head temperature will decrease rapidly with no forced circulation, and further states if forced circulation cannot be re-established within 30 minutes, an aggressive cooldown may have to be initiated, limited to less than 100EF cooldown rate in any one hour.

Approximately 30 minutes after the scram, operators were able to restore water level and lower pressure to allow feeding with a condensate booster pump. Ten minutes later, operators started the 2A recirculation pump, and the water temperature in the bottom of the reactor vessel decreased approximately 129EF. However, the metal temperature on the bottom of the reactor only decreased approximately 39EF. Because of the complications with the loss of all normal feedwater, the operator was delayed approximately 40 minutes after the scram to restart a recirculation pump. Once the recirculation pump was restarted, cooldown was controlled to less than 100EF per hour.

The Hatch technical specifications require cooldown be controlled to less than 100EF in one hour. If the cooldown rate exceeds this value, the cooldown must be evaluated. In September 1992, the licensee completed an analysis using General Electric information that determined a maximum water cooldown rate of 165EF in one hour still would not violate pressure and temperature limits, maximum stress on the lower head, and fatigue impact. As a result, the licensee determined the cooldown did not have any adverse consequences on the reactor pressure vessel.

.5 Review this event for generic safety implications

a. Inspection Scope

The inspectors evaluated if there could be industry-wide generic implications concerning the loss of normal feedwater following a turbine trip.

b. Observations Although the Steam Seal system is considered a non-risk significant and non-safety related system, the loss of the automatic function of the system created difficulties for the operators during the event. Additionally, this was compounded by the fact the status and operational guidance of the automatic portion of the system was tenuous at best.

Given the circumstances surrounding the event, generic consideration could be given to reinforce the importance of mitigation equipment not normally emphasized during risk considerations for equipment outages. Although the manual control was available to the operators, guidance and training were not sufficient to provide a timely operator response to restore sealing steam.

4OA6 Meetings

On April 12, 2006, the inspectors presented the inspection results to Mr. Dennis Madison, and other members of his staff who acknowledged the observations.

Additional exits were conducted on April 21 and 27, 2006, with Mr. Steve Douglas and Mr. Dennis Madison, respectively, and other members of their staff to present the results of additional information reviews. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

s: 1. Supplemental Information 2. Sequence of Events

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Ajluni, Assistant General Manager - Plant Support

J. Dixon, Health Physics Manager

S. Douglas, Assistant General Manager - Plant Operations

M. Googe, Maintenance Manager

J. Hammonds, Operations Manager

J. Lewis, Training and Emergency Preparedness Manager

D. Madison, General Manager - Nuclear Plant

R. Varnadore, Engineering Manager

NRC

R. Bernhard, Senior Risk Analyst

C. Casto, Director, Division of Reactor Projects Region II

J. Hickey, Resident Inspector

J. Shea, Deputy Director, Division of Reactor Projects Region II