IR 05000413/2006009

IR 05000413-06-009, and IR 05000414-06-009, on 05/23/2006 - 05/31/2006, Duke Energy Corporation, NRC Augmented Inspection Team (AIT) Report

ML061800329
Person / Time
Site:	Catawba
Issue date:	06/29/2006
From:	Casto C Division Reactor Projects II
To:	Jamil D Duke Energy Corp
References
IR-06-009
Download: ML061800329 (48)

Text

June 29, 2006

SUBJECT:

CATAWBA NUCLEAR STATION - NRC AUGMENTED INSPECTION TEAM (AIT) REPORT 05000413/2006009 AND 05000414/2006009

Dear Mr. Jamil:

On May 26, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an Augmented Inspection at your Catawba Nuclear Station, Units 1 and 2. The enclosed report documents the inspection findings, which were preliminarily discussed on May 26 with you and other members of your staff. A public exit was conducted with you and members of your staff on May 31, 2006.

The events that led to the conduct of the Augmented Inspection can be summarized as follows:

On May 20, 2006, at approximately 2:01 p.m. EDT, a phase-to-ground electrical fault on a current transformer in the 230kV switchyard associated with the Catawba Unit 1 main step-up transformer 1A initiated a sequence of events that resulted in a Loss of Offsite Power (LOOP) event for both Unit 1 and Unit 2. A tap setting on bus differential relaying for the Red and Yellow busses within the breaker-and-a-half switchyard configuration scheme, which had been set incorrectly since prior to the initial commercial operation of the plant, was a major contributory element to this event.

On May 22, 2006, a second event, unrelated to the first, occurred as preparations were being made to restore the secondary-side plant on Unit 2 and return secondary-side heat removal to the steam dumps from the steam generator power operated relief valves. Water overflowing from the Unit 2 cooling towers traveled through unsealed electrical conduits in cable trenches and manholes and entered the 1A diesel generator room, resulting in the 1A diesel generator being declared inoperable.

Based on the risk and deterministic criteria specified in Management Directive 8.3, NRC Incident Investigation Program, and the significance of these operational events, an NRC Augmented Inspection Team (AIT) was dispatched to the site on May 23, 2006 in accordance with Inspection Procedure 93800, Augmented Inspection Team. The purpose of the inspection was to evaluate the facts and circumstances surrounding the events, as well as the actions taken by your staff in response to the events. The inspection focus areas are detailed in the Augmented Inspection Team Charter (Attachment 5). The team reviewed your immediate and planned corrective actions prior to restart, including your actions to improve the independence and reliability of offsite power sources, and found those actions appropriate for

DEC

continued operation of the units. The team found some issues which will require additional inspection followup. These issues are identified as unresolved items in the report.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Charles A. Casto, Director Division of Reactor Projects Docket Nos.: 50-413, 50-414 License Nos.: NPF-35, NPF-52

Enclosure:

NRC Inspection Report 05000413/2006009 and 05000414/2006009 w/Attachments: Supplemental Information

REGION II==

Docket Nos.:

50-413, 50-414 License Nos.:

NPF-35, NPF-52 Report Nos.:

05000413/2006009 and 05000414/2006009 Licensee:

Duke Energy Corporation Facility:

Catawba Nuclear Station, Units 1 & 2 Location:

4800 Concord Road York, SC 29745 Dates:

May 23 - 31, 2006 Team Leader:

James H. Moorman, III, Chief Operations Branch Division of Reactor Safety Inspectors:

L. Cain, Resident Inspector, V.C. Summer N. Merriweather, Senior Reactor Inspector A. Sabisch, Resident Inspector, Catawba W. Lewis, Reactor Inspector Approved by:

Charles A. Casto, Director Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000413/2006009, 05000414/2006009; 5/23-31/06; Catawba Nuclear Station, Units 1 and 2; Augmented Inspection.

This inspection was conducted by a team consisting of inspectors from the NRCs Region II office and resident inspectors from the Catawba and V.C. Summer Nuclear Stations. 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. An Augmented Inspection Team was established in accordance with NRC Management Directive 8.3, "NRC Incident Investigation Program" and implemented using Inspection Procedure 93800,

Augmented Inspection Team.

NRC-Identified and Self-Revealing Findings

To be determined through the Reactor Oversight Program review of this report.

B.

Licensee Identified Findings None.

An NRC Augmented Inspection Team was dispatched to the site on May 23 to review the loss of offsite power (LOOP) event and the partial flooding of the 1A diesel generator (DG) room.

The team found that the licensees response to the LOOP event and to the partial flooding of the 1A DG room was generally acceptable. The team identified four issues for inspection followup. These issues are tracked as unresolved items in this report.

REPORT DETAILS

Summary of Plant Events On May 20, 2006, at 2:01 p.m., an electrical fault in the Catawba 230kV switchyard caused several power circuit breakers (PCBs) to open resulting in a loss of all offsite power (LOOP)and a subsequent reactor trip of both units from 100 percent power. All reactor trip breakers opened as expected and all control rods fully inserted into the core on the two units. Both main turbines tripped upon receipt of the P4 protective signals following the reactor trips. Control room operators responded to the event using normal, abnormal and emergency operating procedures.

Following the LOOP, the four

(4) emergency diesel generators started and supplied power to the 4.16kV vital busses. Designated vital equipment was re-energized in accordance with the plant design through the diesel generator load sequencers.

A Notice of Unusual Event (NOUE) was declared at 2:14 p.m. on May 20, 2006, due to the loss of AC electrical power from all offsite sources for more than 15 minutes with onsite power available. The Technical Support Center (TSC), Operations Support Center (OSC), and subsequently the Emergency Operations Facility (EOF) were all activated on a precautionary basis to provide support as required.

Power was restored to the Unit 2 6.9kV busses at 8:27 p.m. on May 20, 2006, and to the Unit 1 6.9kV busses at 8:40 p.m. Due to existing lockouts on the 1A and 2B main transformers, full realignment of breakers to provide offsite power to the vital busses and securing of all four diesel generators did not occur until approximately 1:10 a.m. on May 21, 2006. The NOUE was terminated at 1:45 a.m. on May 21, 2006.

In an unrelated event, on May 22, 2006, water overflowing from the Unit 2 cooling towers due to clogged screens entered the 1A diesel generator (DG) room through unsealed electrical conduits resulting in the 1A DG being declared inoperable. Following conduit seal repairs, inspection of DG support equipment and functional testing, the 1A DG was returned to operable status on May 24, 2006.

Inspection Scope Based on the probabilistic risk and deterministic criteria specified in Management Directive 8.3, NRC Incident Investigation Program, Inspection Procedure 71153, Event Followup, and the significance of the operational events which occurred, an Augmented Inspection was initiated in accordance with Inspection Procedure 93800, Augmented Inspection Team.

The inspection focus areas included the following charter items:

• Develop a complete sequence of events, including applicable management decision points, from the time the LOOP occurred until both units were stabilized.

• Identify and evaluate the effectiveness of the immediate actions taken by the licensee in response to this event including the accuracy and timeliness of the licensees classification of the event.

• Identify additional actions planned by the licensee in response to this event, including the time line for their completion of the investigation and follow-on analysis.

• Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1 and Unit 2 pressurizer power operated relief valves.

• Determine if there are any generic issues related to this event which warrant an additional NRC response. As part of this review, assess the implications of a common cause failure of the emergency diesel generators due to external flooding. [Added to the charter after the May 22 event.] Promptly communicate any potential generic issues to regional management.

4OA5 Augmented Inspection

.1 Develop a complete sequence of events, including applicable management decision

points, from the time the LOOP occurred until both units were stabilized.

a. Inspection Scope

For the purposes of this Augmented Inspection, the team divided the charter element into three separate sequences of events; 1) electric plant response, 2) integrated plant response and 3) Emergency Response Organization response. The inspection team reviewed unified control room logs, operator aid and plant computer alarm and data logs, sequence of event recorder reports, and an event chronology developed by licensee personnel. The inspection team also interviewed several licensee and Duke Energy Power Delivery Department (i.e., Transmission) personnel in order to validate and further establish the sequence of events.

For the purpose of this inspection, Unit Stabilization was defined as follows:

• Electrical systems response - All diesels running, the load sequencer operation completed and safety loads re-energized from the diesel generators.

• Integrated plant response - Unit 1 stabilized in Mode 5 on Residual Heat Removal (ND) due to issues related to reactor coolant pump motor cooling caused by biological debris fouling. Unit 2 stabilized in Mode 3 with forced circulation and secondary side heat removal restored to the main condenser via steam dumps.

• Emergency Organization response - Termination of the Notice of Unusual Event.

b.1 Electrical Systems Response:

A list of the significant electrical plant events and time stamps is provided in Attachment 8, Electrical Plant Sequence of Events.

On 20 May 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the current transformer (CT) on the Catawba Unit 1 main step-up transformer 1A line position occurred within the 230kV switchyard resulting in a Loss of Offsite Power (LOOP) event for both Unit 1 and Unit 2. The entire sequence of events progressed so rapidly as to preclude any possible operator response to prevent the end result, but the sequence of events is presented in order to facilitate its understanding.

Actual Electrical Plant Response to the Event (See the simplified diagram of the Catawba main generator, transformers, and switchyard in Attachment 6 for specific breaker and relay locations):

The initial event that occurred was an internal fault in the X-phase CT associated with Power Circuit Breaker (PCB) 18.

Initial indications of neutral overcurrent (74TM) on all four main step-up transformers and overcurrent on both generators X and Z phase windings were received by the plant computer. Fault protection provided by the Unit 1 A main step-up transformer differential protective relaying, as well as bus differential protective relaying actuated, resulting in the following breakers opening:

• Yellow bus (87BY) differential - PCBs 15, 18, 21, 24, 27, 30 and 33 (*)

• Red bus (87BR) differential - PCBs 10, 13, 16, 19, 22, 25, 28 and 31

• Zone 1A (86A) lockout - PCBs 18 (repeat signal), 17 and Main Generator Circuit Breaker (GCB) 1A

• It could not be confirmed that PCB 12 opened during the event. The breaker was subsequently demonstrated to be able to cycle by both Transmission System and Catawba Nuclear Station personnel. The stations corrective action program was scheduled to conduct additional testing and relay checks to verify that the breaker is fully functional.

The X-phase CT fault on PCB 18 induced a subsequent fault on the secondary side coils of the Y-phase CT associated with PCB 23. This coil provides an input to the Unit 2 B main step-up transformer differential protective relaying and resulted in its actuation causing the following breakers opening:

• Zone 2B (86B) lockout - PCBs 23, 24 (repeat signal) and GCB 2B Both units received a runback signal which would have reduced electrical output to 48%

as designed; however, this rapid sequence of events left Unit 1 attempting to feed 100%

of its output through PCB 14 to the Newport Tie Station down the Allison Creek Black transmission line. This line was designed to carry 56% of rated station output (one hour summer rating). The Allison Creek Black line remote end breaker tripped at the Newport tie-station on over current and PCB 14 tripped open approximately 18 seconds later. The exact cause of the PCB 14 breaker trip was still under investigation.

Unit 2 was attempting to feed 100% of its output through PCB 20 to the Pacolet Tie Station down the Roddey Black transmission line. This line was designed to carry 56%

of rated station output (one hour summer rating). The Roddey Black line distance (21)relay actuated, opening the remote end breakers and tripping PCB 20.

The Unit 1 and Unit 2 blackout logic was initiated upon loss of the 4.16kV bus because undervoltage conditions existed on all four of the vital electrical busses. All four diesel generators received auto-start signals. They were loaded by the blackout load sequencers and the safety loads were loaded back onto the vital busses and re-energized in their designated load groups per design.

Design Electrical Plant Response to the Event:

If the actual relay settings in the switchyard had been set appropriately, the event would have been limited to the actuation of main step-up transformer 1A differential protective relaying and the Yellow bus differential protective relaying to address the fault on the X-phase of the CT associated with PCB 18. Actuation of the main step-up transformer 2B differential protective relaying would have occurred to address the fault on the Y-phase of the CT associated with PCB 23. This would have resulted in the following breakers opening:

• Yellow bus (87BY) differential - PCBs 12, 15, 18, 21, 24, 27, 30 and 33

• Zone 1A (86A) lockout - PCBs 18 (repeat signal), 17 and GCB 1A

• Zone 2B (86B) lockout - PCBs 23, 24 (repeat signal) and GCB 2B Both units would have runback to 48% main generator electrical output. In combination with the number of transmission lines available, the design of the switchyard should have prevented Units 1 and 2 from losing offsite power.

b.2 Integrated Plant Response:

A detailed time line of events and time/date stamps is provided in Attachment 10, Integrated Plant Response Sequence of Events.

On 20 May 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the current transformer on the Catawba Unit 1 main step-up transformer 1A line position occurred within the 230kV switchyard resulting in a Loss of Offsite Power (LOOP) event for both Unit 1 and Unit 2. Both reactors tripped from 100 percent power, as expected. Control room operators entered emergency operating procedure EP/1(2)/A/5000/E-0, Reactor Trip or Safety Injection, for both units and then transitioned to emergency operating procedure EP/1(2)/A/5000/ES-0.1, Reactor Trip Response.

The first-out annunciator on Unit 1 indicated the reactor trip was caused by an NI Hi Flux Rate Power Range signal. Subsequent analysis of plant data determined that the actual cause of this signal was from an electrical perturbation on the instrument bus resulting from the large fault in the switchyard. It was confirmed that an actual increase in reactor power significant enough to have generated an NI Hi Flux Rate - Power Range signal did not occur prior to the transient and reactor trip. All other expected reactor trip signals for the conditions present were received.

The first-out annunciator on Unit 2 indicated that the reactor trip was caused by actuation of the under frequency relays associated with the reactor coolant pump electrical busses. This is an expected reactor trip signal for the condition present.

All reactor trip breakers opened as expected and all control rods fully inserted into the core on the two units.

Both main turbines tripped upon receipt of the reactor trip signals. Following the loss of all offsite electrical power, the four

(4) emergency diesel generators started and supplied power to the 4.16kV vital busses. Designated vital equipment was re-energized in accordance with the plant design through the diesel generator load sequencers.

Operators implemented Abnormal Operating Procedure AP/1(2)/A/5500/007; Loss of Normal Power, to respond to the electrical transient.

A NOUE was declared at 2:14 p.m. on May 20, 2006, due to the loss of AC electrical power from all offsite sources for more than 15 minutes with onsite power available.

The TSC, OSC, and subsequently the EOF were all activated on a precautionary basis.

The auxiliary feedwater pumps (3 per unit) started automatically to maintain water levels in the steam generators following the loss of the main feedwater pumps. Secondary-side pressure control transitioned from the steam dumps to the steam generator power operated relief valves (PORVs) once steam generator pressure dropped below 775 psig and a main steam line isolation signal was generated. Two of the three pressurizer PORVs on Unit 1 and one of the three PORVs on Unit 2 cycled during the initial phase of the transient to maintain primary system pressure.

The Technical Specifications for several safety-related systems required both on and offsite power to be available. The loss of the offsite power sources placed both units in Technical Specification 3.0.3 necessitating a natural circulation cooldown be performed in order to be in Mode 4 within 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of the initiating event. Operators entered emergency procedure EP/1(2)/A/5000/ES-0.2; Natural Circulation Cooldown; and proceeded to reduce primary pressure and temperature in accordance with the guidance contained in the procedures. Once offsite power had been re-established, the cooldown was terminated and the units stabilized at approximately 470F and 1850 psig.

Power was restored to the Unit 2 6.9kV busses at 8:27 p.m. on May 20, 2006, and to the Unit 1 6.9kV busses at 8:40 p.m. Due to lockouts on the 1A and 2B main transformers, full realignment of breakers to provide offsite power to the vital busses and securing of all four diesel generators did not occur until approximately 1:10 a.m. on May 21, 2006.

The Notice of Unusual Event was terminated at 1:45 a.m. on May 21, 2006.

Reactor Coolant Pumps were started to re-establish forced circulation on Unit 1 at 3:20 p.m. on May 21, 2006. Due to biological debris fouling of the Unit 1 reactor coolant pump motor coolers, all reactor coolant pumps were secured on May 22, the unit cooled down to Mode 5 on natural circulation and the residual heat removal system placed in-service. Following resolution of all issues required for restart, Unit 1 was returned to service on June 10, 2006.

Forced circulation was re-established on Unit 2 at 11:06 a.m. on May 21, 2006 and the unit remained in Mode 3 until all issues tied to restart had been resolved. Unit 2 was returned to service on May 26, 2006.

b

.3 Emergency Response Organization Response:

A detailed time line of Emergency Response Organization actions is provided in 9, Emergency Response Organization Sequence of Events.

On May 20, 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the current transformer on the Catawba Unit 1 main step-up transformer 1A line position occurred within the 230kV switchyard resulting in a Loss of Offsite Power (LOOP) event for both Unit 1 and Unit 2. The Operations Shift Manager (OSM) declared a Notice of Unusual Event at 2:14 p.m. based on the existing Emergency Plan entry condition of the loss of all offsite power to essential busses for greater than 15 minutes with all emergency diesel generators supplying power to their respective 4.16kV busses.

The Control Room Offsite Agency Communicator made the required initial verbal notifications to local and State agencies. The notification to York County Emergency Management (EM) was delayed due to a problem with the selective signal system. The problem was subsequently traced to a blown fuse in York Countys system. York County emergency response personnel were notified via a second phone call during which the event declaration information was read over the phone and transcribed remotely.

The first follow-up update was also made by the Control Room Offsite Agency Communicator; however, the notifications took longer than usual because the loss of non-essential power resulted in the control room fax machines being unavailable. The communicator was required to call the individual offsite agencies and read the notification message to the state and county warning point telecommunicators while that person wrote down the information on a blank notification form. The loss of the fax capabilities resulted in the follow-up update being completed within 74 minutes of the initial notification versus the expected 60 minute time period (a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> requirement for follow-up notifications exists).

The OSM activated the TSC and OSC as a precautionary measure to ensure any necessary resources were readily available on-site to respond to the LOOP event. The TSC and OSC were activated at 3:50 p.m. at which time responsibility for offsite agency communications was transferred to the TSC from the Control Room Offsite Agency Communicator. During the event, the NRC Operations Center was not notified within one hour of the initial NOUE declaration as required by 10 CFR 50.72(a)(3). This oversight was identified by TSC personnel and the NRC Operations Center was notified of the event at 4:15 p.m., which was 61 minutes late. The NRC Resident Inspectors had been notified at 2:14 p.m. as part of the initial Emergency Response Organization pager call-out and had responded to the site within 30 minutes of this notification.

The EOF was activated at 6:19 p.m. at the request of the TSC Emergency Coordinator.

The EOF staff provided support to the site by assuming the responsibility for offsite agency communication. Hourly updates were provided to state and local agencies, as required, by the EOF staff.

At 1:45 a.m. on May 21, 2006, after offsite power was restored to all four 4.16kV essential busses, the NOUE was terminated. The EOF, TSC, and OSC organizations were released and the Outage Control Center was staffed to support stabilization and recovery activities for both units.

Additional assessment of the timeliness of the licensees emergency response organization response to the LOOP is required and identified as Unresolved Item (URI)05000413, 414/2006009-01, Timeliness of Notification to the NRC of Loss of Offsite Power Event on May 20, 2006.

.2 Identify and evaluate the effectiveness of the immediate actions taken by the licensee in

response to the LOOP event including the accuracy and timeliness of the licensees classification of the event

a. Inspection Scope

The inspectors evaluated the response of the licensees staff to the LOOP from the start of the event until the NOUE was terminated through the review of logs, completed procedures and statements, conducting interviews with Operations and Emergency Response Organization personnel, as well as actual observations of recovery activities in the control room, Operations Support Center, and Technical Support Center immediately following the event conducted by the Catawba Resident Inspectors.

b. Findings and Observations

The LOOP event started at 2:01 p.m. on Saturday, May 20, 2006. Therefore, the site was staffed at weekend levels; i.e., limited engineering, maintenance and support staff available. The on-shift crew responded to the event through actions in the control room by licensed operators and throughout the plant by non-licensed operators. Additional support was provided by all other available on-site personnel prior to the arrival of the staff called out as part of the Emergency Response Organization. A second Senior Reactor Operator (SRO) in the control room allowed an SRO to be dedicated to each unit in order to direct the actions dictated by the Emergency Operating procedures implemented following the LOOP and reactor trips. While the operators experienced some minor equipment malfunctions, the procedures in-use allowed them to respond to those issues and stabilize plant conditions on both units.

The OSM declared a NOUE at 2:14 p.m. due to the loss of all offsite power for greater than 15 minutes with onsite power available. The decision to declare a NOUE was made 2 minutes prior to meeting the actual Emergency Plan entry conditions based on the recognition that offsite power would not be imminently restored. The Emergency Response Organization was notified by pager at that time and instructed to activate the TSC and OSC on a precautionary basis. Both of these facilities were staffed and activated by 3:50 p.m. and the responsibility for communicating with offsite agencies was assumed by TSC personnel. The EOF was activated at the request of the TSC Emergency Coordinator at 6:19 p.m.

Overall, operator response to the LOOP event was deliberate and effective in stabilizing the units and restoring offsite power through the use of approved station procedures.

The Emergency Response Organization responded to the event promptly. With the exception of initial NRC Operations Center notification as discussed in Section 4OA5.1.b.3, the Emergency Planning program was successfully implemented from initial declaration of the NOUE until the event was terminated following restoration of offsite power to all 4.16kV vital electrical busses.

.3 Identify additional actions planned by the licensee in response to this event, including

the time line for their completion of the investigation and follow-on analysis

a. Inspection Scope

The inspectors reviewed the licensees Trip and Transient Investigation report for each unit. An independent review of operator aid computer data, control room logs, emergency response organization logs, PIPs and work orders was performed to determine if all equipment-related issues following the loss of offsite power event were identified and properly prioritized. Discussions were held with members of the stations Failure Investigation Process (FIP) Team as well as the corporate Special Event Investigation Team (SEIT) conducting an independent review of the event.

b. Findings and Observations

The licensee developed unit-specific action item lists following the LOOP event. The lists identified actions that were either required to be completed prior to the restart of each unit or were either generic in nature or required additional time to complete and not required for restart.

The following tables contain a summary of equipment-related issues that were identified following the loss of offsite power event of May 20, 2006 and the 1A diesel generator room flooding of May 22, 2006, if they were required to be resolved prior to restart and the actions taken by the licensee to address them. Due to the extent of actions tied to the electrical plant following the LOOP, those issues are contained in a separate table.

UNIT 1 : Non-Electrical Issues Issue Details Req. for Restart Status Initial reactor trip signal was on Hi Flux Rate; however, actual conditions for this signal did not exist.

The signal was attributed to an electrical perturbation caused by the power range NI grounding system. This response was seen on a previous LOOP at Catawba 1 NO PIP C-06-3874 was initiated to conduct an Apparent Cause assessment into the cause of the signal.

(PIP C-06-3874)

Loop B hot leg RTD card failed several minutes into the event The cards required replacement and calibration.

YES The cards were replaced and recalibrated.

(WO 98790462 /

PIP C-06-3879)

Excess letdown control valve 1NV-122 would not open following the reactor trip The valve was repaired and stroked successfully.

YES Repairs were completed

(PIP C-06-3873)

Normal letdown variable orifice control valve failed to re-open following event The valve has been repaired and stroked successfully.

YES Repairs have been completed (WR 98375944)1D steam generator PORV was slow to open The positioner required recalibration YES Repairs were completed.

(PIP C-06-3883)

Unsealed electrical conduits resulted in flooding of the 1A DG room Conduits between the cooling tower cable trench and RN conduit manhole CMH-04A were not sealed per design drawings.

Conduits between CMH-3 and the 1A DG room were not sealed per design drawings.

YES All penetrations into the Unit 1 A and B diesel generator rooms were sealed per construction drawings.

(PIP C-06-3902)

UNIT 1 : Non-Electrical Issues Issue Details Req. for Restart Status A Control Area chilled water chiller failed to auto start following the event A loose wire on the Program Timer within the chiller control panel was found.

YES Wiring was reterminated.

(WO 98791173 /

PIP C-06-4037)

Motor stator coolers for the reactor coolant pumps and the LCVU coolers exhibited restricted flow following the event On a loss of offsite power the normal cooling source (YV)swapped to the backup source (RN). Debris in no-flow sections on the RN piping was flushed into the motor stator coolers and LCVU coolers requiring disassembly and cleaning.

YES All 4 reactor coolant pump motor stator coolers and LCVU coolers were cleaned.

(PIP C-06-3935)1A1 and 1A2 WN sump pumps in the 1A DG room failed following being submerged after conduit flooding event The two sump pumps were totally submerged after the 1A DG room flooded. The motors required replacement.

NO The motors were replaced and tested.

(WO 98791331)

UNIT 2 : Non-Electrical Issues Issue Actions Req. for Restart Status Digital Feedwater Control System driver card for the 2B CFPT failed and switched to the backup card The primary card needs to be replaced and functional test performed.

NO Primary card has been replaced and calibrated.

(PIP C-06-3897)

Zone B lockout occurred following the reactor trip The Y Phase current transformer associated with PCB 23, and specifically the secondary winding utilized in the Zone 2B differential protection circuit actuated during the LOOP, was found to be damaged during a current transformer saturation test.

NO The current transformer for PCB 23 Y Phase was replaced with a new unit that was stored in the CNS Switchyard (PIP C-06-4089)

UNIT 2 : Non-Electrical Issues Issue Actions Req. for Restart Status DRPI indication for rods H4 and D8 did not go to zero following the reactor trip Subsequent review determined that the indication was for the OAC only.

NO Problem found on a digital input card in the OAC. Card was reset and indication problems cleared.

(PIP C-06-3881)

Tavg indication drifted high following the reactor trip Tavg NSA card determined to require recalibration YES Recalibration performed prior to restart.

(PIP C-06-3991)

VCT relief valve failed to open at its 75 psig setpoint The VCT pressure reached 92 psig during the event. An analysis was performed to assess the structural integrity impact due to this pressure transient.

YES Analysis showed that the integrity of the tank and piping was not adversely affected. No replacement of the valve was planned.

(PIP C-06-3927)

A Control Area chilled water chiller failed to auto start following the event A loose wire on the Program Timer within the chiller control panel was found.

YES Wiring has been reterminated.

(WO 98791173 /

PIP C-06-4037)

Station Electrical Issues Issue Actions Req. for Restart Status Due to the electrical fault, possible damage may have occurred to the CTs on PCBs 17

& 18 Perform Doble and/or Saturation testing on X, Y, and Z phases of PCBs 17 and 18 YES All 3 phases of PCB 17 and 18 were Doble tested; however, Saturation testing was not found to be required on PCB 17.

WO 9879052 WO 9879053 WO 9879054 The CT on the X phase of PCB 18 failed, initiating the LOOP event Replace the X-phase CT on PCB 18 and any other damaged components YES The CT and associated wiring /

conduits were replaced.

WO 98790418 Based on OE from MNS, the potential for degradation of the MOD contacts following a fault on the transmission line existed Visually inspect the disconnects associated with PCB 17's and 18 YES Visual inspections completed and no repairs required.

WO 98790594 WO 98790593 WO 98790581 WO 98790580 Inspect PCBs 17 and 18 for damage or excessive build-up of arc extingushment salt Perform Doble testing and visual inspections of the PCBs YES Doble testing performed satisfactorily, cleaned arcing contacts and replaced main contacts.

WO 98790416 WO 98790417 Station Electrical Issues Issue Actions Req. for Restart Status Zone 2B Protective Relays need to be tested to verify calibration following the LOOP Relay calibrations were required and visual inspections of connections were performed to ensure no degradation exists YES All relays were found to be satisfactory in the as-found condition. No other repairs were required.

WO 98790852 Differential relays were not set in IAW Power Delivery requirements Verify current differential relays on the Red and Yellow busses and adjust as required to meet Power Delivery requirements YES The 87BY X-Y-Z (Yellow bus) and 87BR X-Y-Z (Red bus) differential relays were checked and reset as required.

WO 98790851 WO 98790853 WO 98790443 Determine why the 2B Zone Lockout occurred Based on Engineering recommendations, several tests were performed on the 2B transformer YES After disconnecting the high and low side of the transformer, the post-trip Doble test was completed satisfactorily. The transformer was demagnetized as the excitation results were not within the normal range. All tests were Satisfactory at the completion.

WO 98790412 WO 98790413 WO 98790414 WO 98790415 Station Electrical Issues Issue Actions Req. for Restart Status Ensure there is no issue related to the 1A transformer following the LOOP event Perform post-trip Doble testing to ensure no problems exist following differential actuation YES Testing indicated that there were no problems with the 1A transformer WO 98790430 The MOD was not opened within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of the individual PCBs opening which may have resulted in the degradation of grading capacitors in the interrupter heads.

Perform post-trip Doble tests on individual PCBs to ensure no degradation occurred.

PCBs 14, 17, 18, 20, 23, and 24 were tested.

YES Doble testing completed satisfactorily WO 98790433 WO 98790434 WO 98790435 WO 98790436 WO 98790437 WO 98790438 Investigate the cause of the PCB 18 CT failure.

Gas concentration of several PCBs scheduled to be checked based on past history and issues related to moisture intrusion into CTs.

PCBs to be checked include PCB 14, 15, 17, 18, 20, 21, 23 and NO Testing was in progress, no issues found to-date.

WO 98790585 WO 98790586 WO 98790587 WO 98790588 WO 98790589 WO 98790590 WO 98790591 WO 98790592 Copper splatter was found on the neutral bushing of the 2B Main S/U transformer due to the fault current The neutral bushing required cleaning following experiencing the high fault current associated with the event YES The bushing was cleaned WO 98791075 Station Electrical Issues Issue Actions Req. for Restart Status During the investigation into the Unit 2 2B lockout, Power Delivery recommended that testing be conducted The CTs for the X, Y and Z phases on PCBs 23 and 24 were isolated and tested to check for damage YES All 3 CTs on PCB 24 tested satisfactorily. The Y phase CT on PCB 23 failed and was replaced. No other problems were identified.

WO 98791140 WO 98791142

.4 Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1

and Unit 2 primary power operated relief valves (PORVs)

a. Inspection Scope

Inspectors assessed the circumstances surrounding the multiple lifting and reseating of the Unit 1 and Unit 2 pressurizer PORVs to determine if the PORVs responded appropriately during the event. System Engineering personnel were interviewed and design documents and calibration procedures were reviewed to support this assessment.

b. Findings and Observations

Each unit is equipped with three pressurizer PORVs. The PORVs are air operated valves each having a relief capacity of 210,000 lbm/hr at a nominal lift setpoint of 2,335 psig. The PORVs are designed to maintain primary plant pressure below the pressurizer pressure high reactor trip setpoint of 2,385 psig following a step reduction of 50% of full load with steam dump operation. The PORVs minimize challenges to the pressurizer safety valves and may also be used for low temperature over pressure protection (LTOP). The PORVs and their associated block valves may also be used by plant operators to depressurize the reactor coolant system (RCS) to recover from certain transients if normal pressurizer spray is not available.

During a LOOP, normal pressurizer spray is not available due to a loss of all reactor coolant pumps. Primary system pressure control is then automatically provided via the PORVs and the pressurizer pressure master controller. The pressurizer pressure master controller is a proportional plus integral (P-I) controller with a nominal PORV setpoint designated as Pref of 2,235 psig. As primary system pressure increases during a LOOP event, the pressurizer pressure master controller will cycle one PORV (NC-34A) over a 20 psig band to return RCS pressure to a nominal Pref setpoint of 2,235 psig. The other two PORVs will lift when pressure reaches their respective lift setpoints.

Specific to the May 20, 2006 LOOP event, Unit 1 PORVs 1NC-32B and 1NC-34A actuated appropriately. 1NC-34A cycled in automatic a total of 57 times as the P-I controller attempted to return RCS pressure to the 2,235 psig Pref setpoint. PORV 1NC-32B cycled a total of five times as RCS pressure exceeded its 2,335 psig lift setpoint.

The Unit 2 PORV, 2NC-34A automatically cycled a total of 35 times as the P-I controller attempted to return RCS pressure to the 2,235 psig Pref setpoint. The total number of cycles differs between the units due to Unit 1's higher initial pressurizer level and subsequent higher pressurizer pressure and the associated recovery time required to re-establish normal RCS letdown flow. Graphs showing the pressurizer pressure versus time following the LOOP for both units which demonstrate how the PORVs were operating to return pressure to the Pref setpoint are provided as Attachment 7.

A comparison of the May 20, 2006 plant response to historical data obtained from a 1996 Unit 2 LOOP event was conducted. This review revealed similar and consistent PORV cycling to maintain RCS pressure for the similar event.

In summary, the PORVs on both units operated as designed to control primary plant pressure.

.5 Determine if there are any generic issues related to this event which warrant an

additional NRC response. As part of this review, assess the implications of a common cause failure of the emergency diesel generators due to external flooding. Promptly communicate any potential generic issues to regional management.

a. Inspection Scope

During the inspection teams investigation into the event; equipment issues, procedures, and design documents were reviewed to determine if there were any generic issues that required additional review by NRC personnel. In addition, the partial flooding of the 1A diesel generator room that occurred on May 22, 2006 was also reviewed by the team for generic implications.

The inspectors reviewed unified control room logs, operator aid and process computer alarm logs, sequence of event recorder reports, emergency response organization logs from the TSC, OSC and EOF, statements from individuals involved in the event and timelines developed by licensee personnel. The inspectors also interviewed licensee personnel to validate and clarify the sequence of events which occurred on May 20, 2006. Notes generated by the Resident Inspectors who responded to the event and were in the control room, OSC, and TSC until the NOUE was terminated were also reviewed. To identify potential generic implications of the events, the Final Safety Analysis Report (FSAR), design basis documents, Catawba calculations, relay setpoint sheets from the Power Delivery Department, 10 CFR 50 Appendix A, General Design Criteria, and corrective action program documents were reviewed by the inspection team members.

b.1 Switchyard Design and Relay Settings The inspectors reviewed the design of the offsite power system for compliance with the requirements of 10 CFR 50, Appendix A, General Design Criterion 17. This criterion requires two physically independent circuits from the transmission network to the onsite electrical distribution system, with one of these circuits being available within a few seconds following a loss-of-coolant accident to ensure that core cooling, containment integrity, and other vital safety functions are maintained. The team found no regulatory issues with the overall as-designed switchyard configuration nor theory of operation.

However, the Red bus differential relay actuation, resulting in opening of all the 230 KV switchyard Red bus tie-breakers was apparently caused by incorrect setting of the relays. This issue remains unresolved pending further inspection to review the root and contributing causes, the extent of condition, and the corrective actions, specifically the latent presence of inappropriate setpoints in the bus differential relaying associated with the Red and Yellow buses. It is identified as URI 05000413, 414/2006009-02, Improper relay settings in the Catawba 230kV switchyard resulted in a total loss of offsite power following failure of a PCB current transformer.

The licensee determined that the differential relays had not been set in accordance with the relay setpoint calculations developed in 1981 by Duke Energys Power Delivery Department. The setpoints had been developed in 1981, which was prior to commercial operation of either Catawba unit and the establishment of site System Engineering.

b.2 Description of 1A Diesel Generator Room Flooding Event On May 22, 2006, the control room was notified of water flooding into the 1A DG room.

Operators were dispatched and identified that the flooding was coming in through below-grade electrical conduits on the south wall. The source of the water was determined to be overflow from the Unit 2 cooling towers, through the cooling tower cable trench, into two safety-related manholes and finally into the 1A DG room. Once the cooling towers had been secured, the in-leakage stopped. The conduits into the manholes and the 1A DG room were found not to be sealed as required per design and construction documents.

The water flowed over the starting air compressors, DG battery enclosure, and load sequencer cabinets, and collected in the DG sump. The rate of flooding exceeded the capacity of the installed DG sump pumps. Additional sump pumps had to be brought in to keep the water from reaching the lube oil sump tank and the generator. Neither of these components were wetted.

The 1A DG was declared inoperable and the applicable Technical Specifications were entered. An operability assessment and several additional inspections were required to be performed prior to declaring the diesel generator operable. In addition, the electrical conduits entering manhole CMH-4A from the cooling tower cable trench and those entering the 1A DG room from manhole CMH-3 were sealed in accordance with design drawings.

Inspections were performed on all other electrical conduits that entered the auxiliary building through below-grade penetrations to ensure they were properly sealed.

Approximately 45 electrical conduits required repairs of the moisture seals to restore them to their as-built design condition.

The team identified Unresolved Item 05000413/2006009-03 to review the root and contributing causes, the extent of condition, and the corrective actions associated with the failure to seal conduits into manholes and the 1A DG room as required by design and construction documents.

The team also identified Unresolved Item 05000413, 414/2006009-04 to review the extent of condition and corrective actions taken to address degraded seals found on below-grade electrical conduits entering areas of the auxiliary building containing safety-related equipment.

4OA6 Meetings

Exit Meeting Summary

On May 26, 2006, the inspection team presented the preliminary inspection results to Mr. Jamil and members of his staff of the Augmented Inspection in progress. On May 31, 2006, the Region II Director, Division of Reactor Projects, the Augmented Inspection Team Leader and the Catawba Senior Resident Inspector presented the results of the inspection in a public meeting at the Rock Hill City Hall to Mr. Jamil and other members of his staff. Mr. Jamil acknowledged the findings and observations of the team at that time. All proprietary information reviewed by the team was returned to the licensee.

ATTACHMENT -

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. Beadle, Emergency Planning Manager

G. Black, Civil System Engineer

J. Caldwell, I&C / Electrical Maintenance Manager

K. Caldwell, Electrical System Engineer

T. Daniels, Emergency Planning

A. Dickard, Senior Engineer, Electrical Systems

A. Dubois, Power Deliver Services (PDS)

J. Ferguson, Safety Assurance Manager,

R. Freudenberger, EIT Leader

G. Hamrick, Mechanical / Civil Engineering Manager

R. Hart, Regulatory Compliance

J. Herrington, Senior Engineer, Primary Systems

W. Hogan, Fire Protection Engineer, MCE

D. Jamil, Site Vice President

K. Lyle, FIP Team Leader

S. Mays, Reactor Coolant System Engineer

G. Mitchell, Emergency Planning

V. Paterson, Public Relations

M. Patrick, Work Control Superintendent

T Pitesa, Station Manager

T. Ray, Maintenance Superintendent

R. Repko, Engineering Manager

R. Smith, Emergency Planning

G. Strickland, Regulatory Compliance Specialist

K. Thomas, Corporate Manager, Regulatory Compliance, SEIT Leader

C. Trezise, Operations Superintendent

T. Wingo, System Engineer

NRC

C. Casto, Director DRP, Region II

C. Payne, Acting Branch Chief, Region II, Branch 1

J. Stang, Project Manager, NRR

W. Travers, Region II Regional Administrator

W. Rogers, RII Senior Reactor Analyst

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000413, 414/2006009-01 URI Timeliness of Notification to the NRC of Loss of Offsite Power Event on May 20, 2006.(Section 4OA5.1.b.3)

05000413, 414/2006009-02 URI Improper relay settings in the Catawba 230kV switchyard resulted in a total loss of offsite power following failure of a PCB current transformer (Section 4OA5.5.b.1)

05000413/2006009-03 URI Review of failure to seal conduits into manholes and the 1A DG room as required by design and construction documents (Section 4OA5.5.b.2)

05000413, 414/2006009-04 URI Review the extent of condition and corrective actions to address degraded seals on below-grade electrical conduits entering the auxiliary building (Section 4OA5.5.b.2)