IR 05000413/2006009: Difference between revisions

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{{Adams|number = ML061800329}}
{{Adams
| number = ML061800329
| issue date = 06/29/2006
| title = 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
| author name = Casto C A
| author affiliation = NRC/RGN-II/DRP
| addressee name = Jamil D M
| addressee affiliation = Duke Energy Corp
| docket = 05000413, 05000414
| license number = NPF-035, NPF-052
| contact person =
| document report number = IR-06-009
| document type = Inspection Report, Letter, License-Operator, Part 55 Examination Related Material
| page count = 48
}}


{{IR-Nav| site = 05000413 | year = 2006 | report number = 009 }}
{{IR-Nav| site = 05000413 | year = 2006 | report number = 009 }}
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==Dear Mr. Jamil:==
==Dear Mr. Jamil:==
On May 26, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an AugmentedInspection 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 ona 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 werebeing 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 generatorroom, 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 DEC2continued operation of the units. The team found some issues which will require additionalinspection 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 itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom 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).
On May 26, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an AugmentedInspection 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 ona 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 werebeing 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 generatorroom, 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 DEC2continued operation of the units. The team found some issues which will require additionalinspection 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 itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web si te at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).


Sincerely,/RA/Charles A. Casto, DirectorDivision of Reactor ProjectsDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52
Sincerely,/RA/Charles A. Casto, DirectorDivision of Reactor ProjectsDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52
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S. C. Department of Health and Environmental Control Electronic Mail DistributionR. Mike GandyDivision of Radioactive Waste Mgmt.
S. C. Department of Health and Environmental Control Electronic Mail DistributionR. Mike GandyDivision of Radioactive Waste Mgmt.


S. C. Department of Health and Environmental Control Electronic Mail DistributionElizabeth McMahonAssistant Attorney General S. C. Attorney General's Office Electronic Mail DistributionVanessa QuinnFederal Emergency Management Agency Electronic Mail DistributionNorth Carolina Electric Membership Corporation Electronic Mail DistributionCounty Manager of York County, SCElectronic Mail DistributionPiedmont Municipal Power AgencyElectronic Mail DistributionR. L. Gill, Jr., ManagerNuclear Regulatory Issues and Industry Affairs Duke Energy Corporation 526 S. Church Street Charlotte, NC 28201-0006 DEC4continued operation of the units. The team found some issues which will require additionalinspection 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 itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom 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).
S. C. Department of Health and Environmental Control Electronic Mail DistributionElizabeth McMahonAssistant Attorney General S. C. Attorney General's Office Electronic Mail Distribution Vanessa QuinnFederal Emergency Management Agency Electronic Mail DistributionNorth Carolina Electric Membership Corporation Electronic Mail DistributionCounty Manager of York County, SCElectronic Mail DistributionPiedmont Municipal Power AgencyElectronic Mail DistributionR. L. Gill, Jr., ManagerNuclear Regulatory Issues and Industry Affairs Duke Energy Corporation 526 S. Church Street Charlotte, NC 28201-0006  


Sincerely,/RA/Charles A. Casto, DirectorDivision of Reactor ProjectsDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52
_________________________OFFICERII:DRSRII:DRSRII:DRSRII:SummerRII:CatawbaRII:DRSSIGNATURE/RA//RA By JMoorman for//RA//RA//RA By JMoorman for//RA By JMoorman for/NAMEJMoormanMMerriweatherMErnstesLCainASabischWLewisDATE6/20/066/27/066/27/066/29/066/29/066/29/06 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:50-413, 50-414License 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 RoadYork, SC 29745Dates:May 23 - 31, 2006 Team Leader:James H. Moorman, III, ChiefOperations Branch Division of Reactor SafetyInspectors:L. Cain, Resident Inspector, V.C. SummerN. Merriweather, Senior Reactor Inspector A. Sabisch, Resident Inspector, Catawba W. Lewis, Reactor InspectorApproved by:Charles A. Casto, DirectorDivision of Reactor Projects  
 
===Enclosure:===
NRC Inspection Report 05000413/2006009 and 05000414/2006009
 
===w/Attachments:===
Supplemental InformationX PUBLICLY AVAILABLE G NON-PUBLICLY AVAILABLEG SENSITIVE X NON-SENSITIVEADAMS: X YesACCESSION NUMBER:_________________________OFFICERII:DRSRII:DRSRII:DRSRII:SummerRII:CatawbaRII:DRSSIGNATURE/RA//RA By JMoorman for//RA//RA//RA By JMoorman for//RA By JMoorman for/NAMEJMoormanMMerriweatherMErnstesLCainASabischWLewisDATE6/20/066/27/066/27/066/29/066/29/066/29/06 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO OFFICIAL RECORD COPY DOCUMENT NAME: C:\My Files\Copies\AIT Report - Final.2006009.wpd EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:50-413, 50-414License 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 RoadYork, SC 29745Dates:May 23 - 31, 2006 Team Leader:James H. Moorman, III, ChiefOperations Branch Division of Reactor SafetyInspectors:L. Cain, Resident Inspector, V.C. SummerN. Merriweather, Senior Reactor Inspector A. Sabisch, Resident Inspector, Catawba W. Lewis, Reactor InspectorApproved by:Charles A. Casto, DirectorDivision of Reactor Projects  


=SUMMARY OF FINDINGS=
=SUMMARY OF FINDINGS=
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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,
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."A.NRC-Identified and Self-Revealing FindingsTo be determined through the Reactor Oversight Program review of this report.B.Licensee Identified FindingsNone.An NRC Augmented Inspection Team was dispatched to the site on May 23 to review the lossof offsite power (LOOP) event and the partial flooding of the 1A diesel generator (DG) room.
"Augmented Inspection Team."A.
 
===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 lossof offsite power (LOOP) event and the partial flooding of the 1A diesel generator (DG) room.


The team found that the licensee's 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.
The team found that the licensee's 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=
=REPORT DETAILS=
Summary of Plant EventsOn May 20, 2006, at 2:01 p.m., an electrical fault in the Catawba 230kV switchyard causedseveral power circuit breakers (PCB's) 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 tothe 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 lossof 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), andsubsequently 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 16.9kV 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 toclogged 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 ScopeBased 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:
Summary of Plant EventsOn May 20, 2006, at 2:01 p.m., an electrical fault in the Catawba 230kV switchyard causedseveral power circuit breakers (PCB's) 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 tothe 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 lossof 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), andsubsequently 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 16.9kV 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 toclogged 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 ScopeBased 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 decisionpoints, from the time the LOOP occurred until both units were stabilized.*Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's classification of the event.
*Develop a complete sequence of events, including applicable management decisionpoints, from the time the LOOP occurred until both units were stabilized.*Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's classification of the event.


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==4OA5 Augmented Inspection==
==4OA5 Augmented Inspection==
{{IP sample|IP=IP 93800}}
{{IP sample|IP=IP 93800}}
.1Develop a complete sequence of events, including applicable management decisionpoints, from the time the LOOP occurred until both units were stabilized.
.1Develop a complete sequence of events, including applicable management decisionpoints, from the time the LOOP occurred until both units were stabilized
.


====a. Inspection Scope====
====a. Inspection Scope====
For the purposes of this Augmented Inspection, the team divided the charter elementinto 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:
For the purposes of this Augmented Inspection, the team divided the charter elementinto 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 operationcompleted and safety loads re-energized from the diesel generators.*Integrated plant response - Unit 1 stabilized in Mode 5 on Residual HeatRemoval (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 Attachment8, "Electrical Plant Sequence of Events."
*Electrical systems response - All diesels running, the load sequencer operationcompleted and safety loads re-energized from the diesel generators.*Integrated plant response - Unit 1 stabilized in Mode 5 on Residual HeatRemoval (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 Attachment8, "Electrical Plant Sequence of Events."


5On 20 May 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the currenttransformer (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 theCatawba main generator, transformers, and switchyard in Attachment 6 for specificbreaker and relay locations):The initial event that occurred was an internal fault in the X-phase CT associated withPower Circuit Breaker (PCB) 18. Initial indications of neutral overcurrent (74TM) on all four main step-up transformersand 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 - PCB's 15, 18, 21, 24, 27, 30 and 33 (*)*Red bus (87BR) differential - PCB's 10, 13, 16, 19, 22, 25, 28 and 31*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and Main Generator CircuitBreaker (GCB) 1A* It could not be confirmed that PCB 12 opened during the event. The breaker wassubsequently demonstrated to be able to cycle by both Transmission System and Catawba Nuclear Station personnel. The station's 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 sidecoils 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 - PCB's 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%
5On 20 May 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the currenttransformer (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 theCatawba main generator, transformers, and switchyard in Attachment 6 for specificbreaker and relay locations):The initial event that occurred was an internal fault in the X-phase CT associated withPower Circuit Breaker (PCB) 18. Initial indications of neutral overcurrent (74TM) on all four main step-up transformersand 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 - PCB's 15, 18, 21, 24, 27, 30 and 33 (*)*Red bus (87BR) differential - PCB's 10, 13, 16, 19, 22, 25, 28 and 31*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and Main Generator CircuitBreaker (GCB) 1A* It could not be confirmed that PCB 12 opened during the event. The breaker wassubsequently demonstrated to be able to cycle by both Transmission System and Catawba Nuclear Station personnel. The station's 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 sidecoils 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 - PCB's 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%
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6Unit 2 was attempting to feed 100% of its output through PCB 20 to the Pacolet TieStation down the Roddey Black transmission line. This line was designed to carry 56%
6Unit 2 was attempting to feed 100% of its output through PCB 20 to the Pacolet TieStation 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 becauseundervoltage 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 wouldhave 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 - PCB's 12, 15, 18, 21, 24, 27, 30 and 33*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and GCB 1A*Zone 2B (86B) lockout - PCB's 23, 24 (repeat signal) and GCB 2BBoth units would have runback to 48% main generator electrical output. In combinationwith 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 currenttransformer 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 HiFlux Rate Power Range" signal. Subsequent analysis of plant data determined that the 7actual cause of this signal was from an electrical perturbation on the instrument busresulting 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 byactuation 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 thecore on the two units.Both main turbines tripped upon receipt of the reactor trip signals. Following the loss ofall 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.
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 becauseundervoltage 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 wouldhave 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 - PCB's 12, 15, 18, 21, 24, 27, 30 and 33*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and GCB 1A*Zone 2B (86B) lockout - PCB's 23, 24 (repeat signal) and GCB 2BBoth units would have runback to 48% main generator electrical output. In combinationwith 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 currenttransformer 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 HiFlux Rate Power Range" signal. Subsequent analysis of plant data determined that the 7actual cause of this signal was from an electrical perturbation on the instrument busresulting 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 byactuation 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 thecore on the two units.Both main turbines tripped upon receipt of the reactor trip signals. Following the loss ofall 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 electricalpower from all offsite sources for more than 15 minutes with onsite power available.
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 electricalpower from all offsite sources for more than 15 minutes with onsite power available.
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The licensee developed unit-specific action item lists following the LOOP event. Thelists 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 identifiedfollowing 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.
The licensee developed unit-specific action item lists following the LOOP event. Thelists 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 identifiedfollowing 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.


11UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatusInitial reactor tripsignal 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 1NOPIP C-06-3874 wasinitiated to conduct an Apparent Cause assessment into the cause of the signal.(PIP C-06-3874)Loop B hot legRTD card failed several minutes into the eventThe cards requiredreplacement and calibration.YESThe cards werereplaced and recalibrated. (WO 98790462 /PIP C-06-3879)Excess letdowncontrol valve 1NV-122 would not open following the reactor tripThe valve was repairedand stroked successfully.YESRepairs werecompleted
11UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatusInitial reactor tripsignal 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 1NOPIP C-06-3874 wasinitiated to conduct an Apparent Cause
 
assessment into the cause of the signal.(PIP C-06-3874)Loop B hot legRTD card failed several minutes into the eventThe cards requiredreplacement and calibration.YESThe cards werereplaced and recalibrated. (WO 98790462 /PIP C-06-3879)Excess letdowncontrol valve 1NV-122 would not open following the reactor tripThe valve was repairedand stroked successfully.YESRepairs were completed
 
(PIP C-06-3873)Normal letdownvariable orifice control valve failed to re-open following eventThe valve has beenrepaired and stroked successfully.YESRepairs have beencompleted (WR 98375944)1D steamgenerator PORV was slow to openThe positioner requiredrecalibrationYESRepairs werecompleted.(PIP C-06-3883)
Unsealedelectrical conduits resulted in flooding of the 1A DG roomConduits between thecooling 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.YESAll penetrations intothe Unit 1 A and B diesel generator rooms were sealed per construction drawings.(PIP C-06-3902)12UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatus"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring wasreterminated.(WO 98791173 /PIP C-06-4037)Motor statorcoolers for the reactor coolant pumps and the LCVU coolers exhibited restricted flow following the eventOn a loss of offsitepower 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.YESAll 4 reactor coolantpump motor stator coolers and LCVU coolers were
 
cleaned.(PIP C-06-3935)1A1 and 1A2 WNsump pumps in the 1A DG room failed following being submerged after conduit flooding eventThe two sump pumpswere totally submerged after the 1A DG room flooded. The motors required replacement.NOThe motors werereplaced and tested.(WO 98791331)UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDigital FeedwaterControl System driver card for the 2B CFPT failed and switched to the backup cardThe primary cardneeds to be replaced and functional test performed.NOPrimary card hasbeen replaced and calibrated.(PIP C-06-3897)Zone B lockout occurred following the reactor tripThe Y Phase currenttransformer 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.NOThe currenttransformer for PCB 23 Y Phase was replaced with a new unit that was stored in the CNS Switchyard(PIP C-06-4089)13UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDRPI indicationfor rods H4 and D8 did not go to zero following the reactor tripSubsequent reviewdetermined that the indication was for the OAC only.NOProblem found on adigital input card in the OAC. Card was reset and indication problems cleared.(PIP C-06-3881)Tavg indicationdrifted high following the reactor tripTavg NSA carddetermined to require recalibrationYESRecalibrationperformed prior to restart.(PIP C-06-3991)VCT relief valvefailed to open at its 75 psig setpointThe VCT pressurereached 92 psig during the event. An analysis was performed to
 
assess the structural integrity impact due to this pressure transient.YESAnalysis showedthat the integrity of the tank and piping was not adversely affected. No replacement of the valve was planned.(PIP C-06-3927)"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring has beenreterminated.(WO 98791173 /PIP C-06-4037)14Station Electrical IssuesIssueActionsReq. for RestartStatusDue to theelectrical fault, possible damage may have occurred to the CT's on PCB's 17
 
& 18Perform Doble and/orSaturation testing on X, Y, and Z phases of


(PIP C-06-3873)Normal letdownvariable orifice control valve failed to re-open following eventThe valve has beenrepaired and stroked successfully.YESRepairs have beencompleted (WR 98375944)1D steamgenerator PORV was slow to openThe positioner requiredrecalibrationYESRepairs werecompleted.(PIP C-06-3883)Unsealedelectrical conduits resulted in flooding of the 1A DG roomConduits between thecooling tower cable trench and RN conduit manhole CMH-04A were not sealed per design drawings.
PCB's 17 and 18YESAll 3 phases of PCB17 and 18 were Doble tested; however, Saturation testing was not found to be required


Conduits between CMH-3 and the 1A DG room were not sealed per design drawings.YESAll penetrations intothe Unit 1 A and B diesel generator rooms were sealed per construction drawings.(PIP C-06-3902)12UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatus"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring wasreterminated.(WO 98791173 /PIP C-06-4037)Motor statorcoolers for the reactor coolant pumps and the LCVU coolers exhibited restricted flow following the eventOn a loss of offsitepower 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.YESAll 4 reactor coolantpump motor stator coolers and LCVU coolers were cleaned.(PIP C-06-3935)1A1 and 1A2 WNsump pumps in the 1A DG room failed following being submerged after conduit flooding eventThe two sump pumpswere totally submerged after the 1A DG room flooded. The motors required replacement.NOThe motors werereplaced and tested.(WO 98791331)UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDigital FeedwaterControl System driver card for the 2B CFPT failed and switched to the backup cardThe primary cardneeds to be replaced and functional test performed.NOPrimary card hasbeen replaced and calibrated.(PIP C-06-3897)Zone B lockoutoccurred following the reactor tripThe Y Phase currenttransformer 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.NOThe currenttransformer for PCB 23 Y Phase was replaced with a new unit that was stored in the CNS Switchyard(PIP C-06-4089)13UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDRPI indicationfor rods H4 and D8 did not go to zero following the reactor tripSubsequent reviewdetermined that the indication was for the OAC only.NOProblem found on adigital input card in the OAC. Card was reset and indication problems cleared.(PIP C-06-3881)Tavg indicationdrifted high following the reactor tripTavg NSA carddetermined to require recalibrationYESRecalibrationperformed prior to restart.(PIP C-06-3991)VCT relief valvefailed to open at its 75 psig setpointThe VCT pressurereached 92 psig during the event. An analysis was performed to assess the structural integrity impact due to this pressure transient.YESAnalysis showedthat the integrity of the tank and piping was not adversely affected. No replacement of the valve was planned.(PIP C-06-3927)"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring has beenreterminated.(WO 98791173 /PIP C-06-4037)14Station Electrical IssuesIssueActionsReq. for RestartStatusDue to theelectrical fault, possible damage may have occurred to the CT's on PCB's 17
on PCB 17.
& 18Perform Doble and/orSaturation testing on X, Y, and Z phases of PCB's 17 and 18YESAll 3 phases of PCB17 and 18 were Doble tested; however, Saturation testing was not found to be required on PCB 17.


WO 9879052 WO 9879053 WO 9879054The CT on the Xphase of PCB 18 failed, initiating the LOOP eventReplace the X-phaseCT on PCB 18 and any other damaged componentsYESThe CT andassociated wiring /
WO 9879052 WO 9879053 WO 9879054The CT on the Xphase of PCB 18 failed, initiating the LOOP eventReplace the X-phaseCT on PCB 18 and any other damaged componentsYESThe CT andassociated wiring /
conduits were replaced.WO 98790418Based on OEfrom MNS, the potential for degradation of the MOD contacts following a fault on the transmission line existedVisually inspect thedisconnects associated with PCB 17's and 18YESVisual inspectionscompleted and no repairs required.WO 98790594WO 98790593 WO 98790581 WO 98790580Inspect PCB's 17and 18 for damage or excessive build-up of arc extingushment
conduits were replaced.WO 98790418Based on OEfrom MNS, the potential for degradation of the MOD contacts following a fault on the transmission line existedVisually inspect thedisconnects associated with PCB 17's and 18YESVisual inspectionscompleted and no repairs required.WO 98790594WO 98790593 WO 98790581 WO 98790580Inspect PCB's 17and 18 for damage or excessive build-up of arc extingushment "salt"Perform Doble testingand visual inspections of the PCB'sYESDoble testingperformed satisfactorily, cleaned arcing contacts and replaced main contacts.WO 98790416WO 98790417 15Station Electrical IssuesIssueActionsReq. for RestartStatus Zone 2BProtective Relays need to be tested to verify calibration following the LOOPRelay calibrations wererequired and visual inspections of connections were performed to ensure no degradation existsYESAll relays were foundto be satisfactory in the "as-found" condition. No other repairs were required.WO 98790852Differential relayswere not set in IAW Power Delivery requirements Verify currentdifferential relays on the Red and Yellow busses and adjust as required to meet Power Delivery requirementsYESThe 87BY X-Y-Z(Yellow bus) and 87BR X-Y-Z (Red bus) differential relays were checked and reset as required.WO 98790851WO 98790853 WO 98790443Determine whythe 2B Zone Lockout occurredBased on Engineeringrecommendations, several tests were performed on the 2B transformerYESAfter disconnectingthe 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 98790412WO 98790413 WO 98790414 WO 98790415 16Station Electrical IssuesIssueActionsReq. for RestartStatusEnsure there isno issue related to the 1A transformer following the LOOP eventPerform post-trip Dobletesting to ensure no problems exist following differential actuationYESTesting indicatedthat there were no problems with the 1A transformerWO 98790430The MOD wasnot opened within 1 hour of the individual PCB's opening which may have resulted in the degradation of grading capacitors in the interrupter heads.Perform post-trip Dobletests on individual PCB's to ensure no degradation occurred.
"salt"Perform Doble testingand visual inspections of the PCB'sYESDoble testingperformed satisfactorily, cleaned arcing contacts and replaced main contacts.WO 98790416WO 98790417 15Station Electrical IssuesIssueActionsReq. for RestartStatusZone 2BProtective Relays need to be tested to verify calibration following the LOOPRelay calibrations wererequired and visual inspections of connections were performed to ensure no degradation existsYESAll relays were foundto be satisfactory in the "as-found" condition. No other repairs were required.WO 98790852Differential relayswere not set in IAW Power Delivery requirements Verify currentdifferential relays on the Red and Yellow busses and adjust as required to meet Power Delivery requirementsYESThe 87BY X-Y-Z(Yellow bus) and 87BR X-Y-Z (Red bus) differential relays were checked and reset as required.WO 98790851WO 98790853 WO 98790443Determine whythe 2B Zone Lockout occurredBased on Engineeringrecommendations, several tests were performed on the 2B transformerYESAfter disconnectingthe 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 98790412WO 98790413 WO 98790414 WO 98790415 16Station Electrical IssuesIssueActionsReq. for RestartStatusEnsure there isno issue related to the 1A transformer following the LOOP eventPerform post-trip Dobletesting to ensure no problems exist following differential actuationYESTesting indicatedthat there were no problems with the 1A transformerWO 98790430The MOD wasnot opened within 1 hour of the individual PCB's opening which may have resulted in the degradation of grading capacitors in the interrupter heads.Perform post-trip Dobletests on individual PCB's to ensure no degradation occurred.
 
PCB's 14, 17, 18, 20, 23, and 24 were tested.YESDoble testing completed satisfactorilyWO 98790433WO 98790434 WO 98790435 WO 98790436 WO 98790437 WO 98790438Investigate thecause of the PCB 18 CT failure. Gas concentration ofseveral PCB's scheduled to be checked based on past history and issues related to moisture intrusion into CT's.


PCB's 14, 17, 18, 20, 23, and 24 were tested.YESDoble testingcompleted satisfactorilyWO 98790433WO 98790434 WO 98790435 WO 98790436 WO 98790437 WO 98790438Investigate thecause of the PCB 18 CT failure. Gas concentration ofseveral PCB's scheduled to be checked based on past history and issues related to moisture intrusion into CT's.
PCB's to be checked include PCB 14, 15, 17, 18, 20, 21, 23 and


PCB's to be checked include PCB 14, 15, 17, 18, 20, 21, 23 and 24NOTesting was inprogress, no issues found to-date.WO 98790585WO 98790586 WO 98790587 WO 98790588 WO 98790589 WO 98790590 WO 98790591 WO 98790592Copper splatterwas found on the neutral bushing of the 2B Main S/U transformer due to the fault currentThe neutral bushingrequired cleaning following experiencing the high fault current associated with the eventYESThe bushing wascleanedWO 98791075 17Station Electrical IssuesIssueActionsReq. for RestartStatusDuring theinvestigation into the Unit 2 2B lockout, Power Delivery recommended that testing be conducted The CT's for the X, Yand Z phases on PCB's 23 and 24 were isolated and tested to check for damageYESAll 3 CT's on PCB24 tested satisfactorily. The Y phase CT on PCB 23 failed and was replaced. No other problems were identified.WO 98791140WO 98791142.4Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves (PORVs)
24NOTesting was inprogress, no issues found to-date.WO 98790585WO 98790586 WO 98790587 WO 98790588 WO 98790589 WO 98790590 WO 98790591 WO 98790592Copper splatterwas found on the neutral bushing of the 2B Main S/U transformer due to the fault currentThe neutral bushingrequired cleaning following experiencing the high fault current associated with the eventYESThe bushing was cleanedWO 98791075 17Station Electrical IssuesIssueActionsReq. for RestartStatusDuring theinvestigation into the Unit 2 2B lockout, Power Delivery recommended that testing be conducted The CT's for the X, Yand Z phases on PCB's 23 and 24 were isolated and tested to check for damageYESAll 3 CT's on PCB24 tested satisfactorily. The Y phase CT on PCB 23 failed and was replaced. No other problems were identified.WO 98791140WO 98791142.4Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves (PORVs)


====a. Inspection Scope====
====a. Inspection Scope====
Inspectors assessed the circumstances surrounding the multiple lifting and reseating ofthe 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 ObservationsEach unit is equipped with three pressurizer PORVs. The PORVs are air operatedvalves 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 reactorcoolant 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 duringa 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 2,235psig. The other two PORV's will lift when pressure reaches their respective lift setpoints.
Inspectors assessed the circumstances surrounding the multiple lifting and reseating ofthe 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 ObservationsEach unit is equipped with three pressurizer PORVs. The PORVs are air operatedvalves 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 reactorcoolant 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 duringa 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 2,235psig. The other two PORV's will lift when pressure reaches their respective lift setpoints.


18Specific to the May 20, 2006 LOOP event, Unit 1 PORVs 1NC-32B and 1NC-34Aactuated 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.
18Specific to the May 20, 2006 LOOP event, Unit 1 PORVs 1NC-32B and 1NC-34Aactuated 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.
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During the inspection team's 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 computeralarm 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.
During the inspection team's 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 computeralarm 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 SettingsThe inspectors reviewed the design of the offsite power system for compliance with therequirements 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 fewseconds 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 KVswitchyard 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 withthe relay setpoint calculations developed in 1981 by Duke Energy's 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 EventOn 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 loadsequencer 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 wereentered. 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.
b.1 Switchyard Design and Relay SettingsThe inspectors reviewed the design of the offsite power system for compliance with therequirements 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 fewseconds 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 KVswitchyard 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 withthe relay setpoint calculations developed in 1981 by Duke Energy's 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 EventOn 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 loadsequencer 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 wereentered. 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.


20Inspections were performed on all other electrical conduits that entered the auxiliarybuilding through below-grade penetrations to ensure they were properly sealed.
20Inspections were performed on all other electrical conduits that entered the auxiliarybuilding 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 andcontributing 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 theextent 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.4OA6MeetingsExit Meeting SummaryOn May 26, 2006, the inspection team presented the preliminary inspection results toMr. 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 AugmentedInspection 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 -  
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 andcontributing 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 theextent 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.4OA6MeetingsExit Meeting SummaryOn May 26, 2006, the inspection team presented the preliminary inspection results toMr. 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 AugmentedInspection 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=
=SUPPLEMENTAL INFORMATION=
Line 153: Line 190:
: [[contact::K. Thomas]], Corporate Manager, Regulatory Compliance, SEIT Leader
: [[contact::K. Thomas]], Corporate Manager, Regulatory Compliance, SEIT Leader
: [[contact::C. Trezise]], Operations Superintendent
: [[contact::C. Trezise]], Operations Superintendent
: [[contact::T. Wingo]], System EngineerNRC
: [[contact::T. Wingo]], System Engineer
NRC
: [[contact::C. Casto]], Director DRP, Region II
: [[contact::C. Casto]], Director DRP, Region II
: [[contact::C. Payne]], Acting Branch Chief, Region II, Branch 1
: [[contact::C. Payne]], Acting Branch Chief, Region II, Branch 1
Line 195: Line 233:
: 2Attachment 3Miscellaneous DocumentsDow Corning 732 Multi-Purpose Sealant Product Data SheetNSD-407, Maintenance Interface Agreement for Nuclear Generation, Electric Transmission, Information Management, and Power Generation Departments, Rev. 06
: 2Attachment 3Miscellaneous DocumentsDow Corning 732 Multi-Purpose Sealant Product Data SheetNSD-407, Maintenance Interface Agreement for Nuclear Generation, Electric Transmission, Information Management, and Power Generation Departments, Rev. 06
: NSD-409, Engineering Guidlines for Nuclear Station Switchyard and Main Step-Up Transformer Activities, Rev. 06
: NSD-409, Engineering Guidlines for Nuclear Station Switchyard and Main Step-Up Transformer Activities, Rev. 06
: NSD-502, Corporate Conduct of Operations in the Switchyard, Rev. 07Work OrdersWO
: NSD-502, Corporate Conduct of Operations in the Switchyard, Rev. 07
: Work OrdersWO
: 98791331;
: 98791331;
: 1A1 and 1A2 WN sump pumps failed meggar testing following submergence  when water drained from manhole
: 1A1 and 1A2 WN sump pumps failed meggar testing following submergence  when water drained from manhole
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: WO 98791075
: WO 98791075
: WO 98791140
: WO 98791140
: WO 98791142PIPsPIP C-06-4180, Need to incorporate the pressurizer PORV operation into future training and
: WO 98791142PIPsPIP C-06-4180, Need to incorporate the pressurizer PORV operation into future training and  
: Operating Experience
===Operating Experience===
: PIP C-06-4150, PORC meeting held on 5/29/06 for the restart of Unit 1
: PIP C-06-4150, PORC meeting held on 5/29/06 for the restart of Unit 1
: PIP C-06-4149, Operability assessment for the conduit between manholes
: PIP C-06-4149, Operability assessment for the conduit between manholes
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==LIST OF ACRONYMS==
==LIST OF ACRONYMS==
ACAlternating CurrentAITAugmented Inspection Team
ACAlternating CurrentAITAugmented Inspection Team
: [[APA]] [[bnormal Operating Procedure]]
APAbnormal Operating Procedure
: [[CFP]] [[]]
CFPTMain Feedwater Pump Turbine
: [[TM]] [[ain Feedwater Pump Turbine]]
CFRCode of Federal Regulations
: [[CF]] [[]]
CLACold Leg Accumulator
: [[RC]] [[ode of Federal Regulations]]
CMHConduit Manhole
: [[CL]] [[]]
DFCSDigital Feedwater Control System
: [[AC]] [[old Leg Accumulator]]
DGEmergency Diesel Generator
: [[CM]] [[]]
DRPIDigital Rod Position Indication
: [[HC]] [[onduit Manhole]]
EITEvent Investigation Team
: [[DFC]] [[]]
EMEmergency Management (off-site agencies)
SDigital Feedwater Control System
EOFEmergency Operations Facility
: [[DGE]] [[mergency Diesel Generator]]
EPEmergency Operating Procedure
: [[DRP]] [[]]
EROEmergency Response Organization
: [[ID]] [[igital Rod Position Indication]]
FIPFailure Investigation Process
: [[EI]] [[]]
FSARFinal Safety Analysis Report
TEvent Investigation Team
GCBGenerator Circuit Breaker
: [[EME]] [[mergency Management (off-site agencies)]]
GDCGeneral Design Criteria
: [[EO]] [[]]
KVKilovolt
FEmergency Operations Facility
LCVULower Containment Ventilation Unit
: [[EPE]] [[mergency Operating Procedure]]
LOOPLoss of Offsite Power
: [[ER]] [[]]
NCVNon-Cited Violation
: [[OE]] [[mergency Response Organization]]
NDResidual Heat Removal System
: [[FI]] [[]]
NOUENotice of Unusual Event
: [[PF]] [[ailure Investigation Process]]
NRCNuclear Regulatory Commission
: [[FSA]] [[]]
NVChemical Volume and Control System
: [[RF]] [[inal Safety Analysis Report]]
OACOperator Aid Computer
: [[GC]] [[]]
OPNormal Operating Procedure
: [[BG]] [[enerator Circuit Breaker]]
OSCOperations Support Center
: [[GD]] [[]]
OSMOperations Shift Manager
CGeneral Design Criteria
PCBPower Circuit Breaker
: [[KVK]] [[ilovolt]]
PIPProblem Investigation Process (report)
: [[LCV]] [[]]
PORVPower Operated Relief Valve
: [[UL]] [[ower Containment Ventilation Unit]]
RNNuclear Service Water System
: [[LOO]] [[]]
RTDResistance Temperature Detector
: [[PL]] [[oss of Offsite Power]]
SDPSignificance Determination Process
: [[NC]] [[]]
SEITSpecial Event Investigation Team
VNon-Cited Violation
SOESequence of Event Recorder
: [[NDR]] [[esidual Heat Removal System]]
TSAILTechnical Specification Action Item Log
: [[NOU]] [[]]
TSCTechnical Support Center
: [[EN]] [[otice of Unusual Event]]
URIUnresolved Item
: [[NR]] [[]]
VCTVolume Control Tank
CNuclear Regulatory Commission
2Attachment 4WNEmergency Diesel Room Sump Pump SystemWOWork Order
: [[NVC]] [[hemical Volume and Control System]]
: [[OA]] [[]]
COperator Aid Computer
: [[OPN]] [[ormal Operating Procedure]]
: [[OS]] [[]]
: [[CO]] [[perations Support Center]]
: [[OS]] [[]]
: [[MO]] [[perations Shift Manager]]
: [[PC]] [[]]
: [[BP]] [[ower Circuit Breaker]]
: [[PI]] [[]]
: [[PP]] [[roblem Investigation Process (report)]]
: [[POR]] [[]]
VPower Operated Relief Valve
: [[RNN]] [[uclear Service Water System]]
: [[RT]] [[]]
: [[DR]] [[esistance Temperature Detector]]
: [[SD]] [[]]
: [[PS]] [[ignificance Determination Process]]
: [[SEI]] [[]]
: [[TS]] [[pecial Event Investigation Team]]
: [[SO]] [[]]
: [[ES]] [[equence of Event Recorder]]
: [[TSAI]] [[]]
: [[LT]] [[echnical Specification Action Item Log]]
: [[TS]] [[]]
: [[CT]] [[echnical Support Center]]
: [[UR]] [[]]
: [[IU]] [[nresolved Item]]
: [[VC]] [[]]
TVolume Control Tank
2Attachment
: [[4WNE]] [[mergency Diesel Room Sump Pump System]]
WOWork Order
WRWork Request
WRWork Request
YCControl Room Chilled Water System
YCControl Room Chilled Water System
YVContainment Chilled Water System
YVContainment Chilled Water System
5May 25,
5May 25, 2006MEMORANDUM TO: James H. Moorman, ChiefOperations Branch
: [[2006MEMORA]] [[]]
NDUM TO: James H. Moorman, ChiefOperations Branch
Division of Reactor SafetyFROM: William
Division of Reactor SafetyFROM: William
: [[D.]] [[Travers, Regional Administrator /]]
: [[D.]] [[Travers, Regional Administrator /]]
: [[RA]] [[/SUBJECT:]]
: [[RA]] [[/SUBJECT: REVISED AUGMENTED INSPECTION]]
: [[REVISE]] [[D]]
: [[AUGMEN]] [[TED]]
: [[INSPEC]] [[]]
: [[TION]] [[]]
: [[TEAM]] [[]]
: [[TEAM]] [[]]
CHARTERAn Augmented Inspection Team (AIT) was established on May 23, 2006, for Catawba NuclearStation to inspect and assess the facts surrounding a loss of offsite power (LOSP) andsubsequent dual unit reactor trip at Catawba on or around May 20, 2006.The team composition and the objectives of the inspection are unchanged. However, theenclosed charter has been revised to clarify and expand on the actions to be accomplished by
CHARTERAn Augmented Inspection Team (AIT) was established on May 23, 2006, for Catawba NuclearStation to inspect and assess the facts surrounding a loss of offsite power (LOSP) andsubsequent dual unit reactor trip at Catawba on or around May 20, 2006.The team composition and the objectives of the inspection are unchanged. However, theenclosed charter has been revised to clarify and expand on the actions to be accomplished by
Line 390: Line 389:
AIT Charter
AIT Charter
Docket Nos.:  50-413 and 50-414License Nos.:
Docket Nos.:  50-413 and 50-414License Nos.:
: [[NPF]] [[-35 and]]
: [[NPF]] [[-35 and NPF-52Distribution:cc:]]
: [[NPF]] [[-52Distribution:cc:]]
: [[W.]] [[Kane,]]
: [[W.]] [[Kane,]]
: [[OEDO]] [[]]
: [[OEDO]] [[]]
Line 409: Line 407:
: [[RII]] [[]]
: [[RII]] [[]]
: [[V.]] [[McCree,]]
: [[V.]] [[McCree,]]
: [[RII]] [[2Attachment]]
: [[RII]] [[2Attachment 5REVISED AUGMENTED INSPECTION]]
: [[5REVISE]] [[D]]
: [[AUGMEN]] [[TED]]
: [[INSPEC]] [[]]
: [[TION]] [[]]
: [[TEAM]] [[(]]
: [[TEAM]] [[(]]
: [[AIT]] [[)]]
: [[AIT]] [[) CHARTERCATAWBA]]
: [[CHARTE]] [[]]
: [[RCATAW]] [[BA]]
: [[LOSS]] [[]]
: [[LOSS]] [[]]
: [[OF]] [[]]
: [[OF]] [[OFFSITE]]
: [[OFFSIT]] [[E]]
: [[POWER]] [[]]
: [[POWER]] [[]]
: [[AND]] [[]]
: [[AND]] [[]]
: [[DUAL]] [[]]
: [[DUAL]] [[]]
: [[UNIT]] [[]]
: [[UNIT]] [[REACTOR TRIPBasis for the Formation of the]]
: [[REACTO]] [[R]]
: [[AIT]] [[- On May 20, 2006, an electrical fault occurred apparentlycausing several power circuit breakers (]]
: [[TRIPB]] [[asis for the Formation of the]]
PCB's) to open in the Catawba switchyard. This fault
AIT - On May 20, 2006, an electrical fault occurred apparentlycausing several power circuit breakers (PCB's) to open in the Catawba switchyard. This fault
apparently caused several other PCB's to open resulting in a loss of offsite power (LOSP) and
apparently caused several other
: [[PCB]] [['s to open resulting in a loss of offsite power (]]
LOSP) and
trip of both Catawba reactors. In accordance with Management Directive (MD) 8.3, "NRC
trip of both Catawba reactors. In accordance with Management Directive (MD) 8.3, "NRC
Incident Investigation Program," deterministic and conditional risk criteria were used to evaluate
Incident Investigation Program," deterministic and conditional risk criteria were used to evaluate
Line 436: Line 424:
circumstances of the event met the MD 8.3 deterministic criteria due to an apparent single
circumstances of the event met the MD 8.3 deterministic criteria due to an apparent single
electrical failure causing a loss of offsite power to both operating units and reactor trips. The
electrical failure causing a loss of offsite power to both operating units and reactor trips. The
risk review indicated the
risk review indicated the CCDP for the event met the criterion for an Augmented Inspection.
: [[CC]] [[]]
DP for the event met the criterion for an Augmented Inspection.
Subsequently, Region
Subsequently, Region
: [[II]] [[determined that the appropriate level of]]
: [[II]] [[determined that the appropriate level of]]
Line 447: Line 433:
and investigation of the event; (3) identify any generic issues associated with the event; and (4)
and investigation of the event; (3) identify any generic issues associated with the event; and (4)
conduct an independent extent of condition review.To accomplish these objectives, the following will be performed:
conduct an independent extent of condition review.To accomplish these objectives, the following will be performed:
a.Develop a complete sequence of events, including applicable management decisionpoints, from the time the
a.Develop a complete sequence of events, including applicable management decisionpoints, from the time the LOOP occurred until both units were stabilized.b.Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's
: [[LO]] [[]]
OP occurred until both units were stabilized.b.Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's
classification of the event.c.Identify additional actions planned by the licensee in response to this evnet, includingthe time line for their completion of the investigation and follow-on analysis.d.Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves.e.Determine if there are any generic issues related to this event which warrant anadditional NRC response. As part of this review, assess the implications of a common
classification of the event.c.Identify additional actions planned by the licensee in response to this evnet, includingthe time line for their completion of the investigation and follow-on analysis.d.Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves.e.Determine if there are any generic issues related to this event which warrant anadditional 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
cause failure of the emergency diesel generators due to external flooding. Promptly
Line 455: Line 439:
: [[6CATAWB]] [[A]]
: [[6CATAWB]] [[A]]
: [[HIGH]] [[]]
: [[HIGH]] [[]]
: [[VOLTAG]] [[E]]
VOLTAGE SWITCHYARD SIMPLIFIED DIAGRAMWith both units at 100% power, all of the breakers shown in the simplified diagram above are inthe CLOSED position.
: [[SWITCH]] [[YARD]]
: [[SIMPLI]] [[]]
: [[FIED]] [[]]
: [[DIAGRA]] [[]]
: [[MW]] [[ith both units at 100% power, all of the breakers shown in the simplified diagram above are inthe]]
: [[CLOS]] [[]]
: [[ED]] [[position.]]
: [[6CATAWB]] [[A]]
: [[6CATAWB]] [[A]]
: [[MAIN]] [[]]
: [[MAIN]] [[]]
: [[GENERA]] [[]]
GENERATOR / SWITCHYARD SIMPLIFIED DIAGRAM
: [[TOR]] [[/]]
: [[8ELECTR]] [[ICAL]]
: [[SWITCH]] [[]]
: [[YARD]] [[]]
: [[SIMPLI]] [[]]
: [[FIED]] [[]]
: [[DIAGR]] [[]]
: [[AM]] [[]]
: [[8ELECTR]] [[]]
: [[ICAL]] [[]]
: [[PLANT]] [[]]
: [[PLANT]] [[]]
: [[SEQUEN]] [[CE]]
: [[SEQUEN]] [[CE]]
: [[OF]] [[]]
: [[OF]] [[]]
EVENTSUnitTimeSeconds fromEvent InitiationEvent114:01:45.4480.000Fault occurs on the X-phase Current Transformer(CT) of Power Circuit Breaker (PCB) 18114:01:45.4650.017Unit 1 Zone A protective lockout actuates (due totransformer 1A differential) to trip PCB's 17 and 18
EVENTSUnitTimeSeconds fromEvent InitiationEvent114:01:45.4480.000Fault occurs on the X-phase Current Transformer(CT) of Power Circuit Breaker (PCB) 18114:01:45.4650.017Unit 1 Zone A protective lockout actuates (due totransformer 1A differential) to trip PCB's 17 and 18
and Generator Circuit Breaker (GCB)
and Generator Circuit Breaker (GCB) 1ADifferential protective relaying actuates to clear theRed and Yellow busses (PCB 12 operation in
: [[1AD]] [[ifferential protective relaying actuates to clear theRed and Yellow busses (]]
PCB 12 operation in
response cannot be confirmed)214:01:45.4910.043Unit 2 Zone B protective lockout actuates (due totransformer 2B differential) to trip PCB's 23, 24
response cannot be confirmed)214:01:45.4910.043Unit 2 Zone B protective lockout actuates (due totransformer 2B differential) to trip PCB's 23, 24
and GCB 2B214:01:46.0680.620Line distance relaying on the Roddey transmissionline actuates to trip the remote line breaker and
and
: [[GCB]] [[2B214:01:46.0680.620Line distance relaying on the Roddey transmissionline actuates to trip the remote line breaker and]]
PCB 20, serving to isolate Unit 2 from all offsite
PCB 20, serving to isolate Unit 2 from all offsite
power214:01:45.5101.062Unit 2 reactor trip occurs due to underfrequencyconditions on the reactor coolant pump electrical
power214:01:45.5101.062Unit 2 reactor trip occurs due to underfrequencyconditions on the reactor coolant pump electrical
Line 500: Line 468:
to have produced a valid flux rate trip signal.
to have produced a valid flux rate trip signal.
2Attachment
2Attachment
: [[8ELECTR]] [[]]
: [[8ELECTR]] [[ICAL]]
: [[ICAL]] [[]]
: [[PLANT]] [[]]
: [[PLANT]] [[]]
: [[SEQUEN]] [[CE]]
: [[SEQUEN]] [[CE]]
Line 526: Line 493:
seconds following sequencer initiation.1 / 2All blackout loads are successfully re-energizedvia the diesel generators.
seconds following sequencer initiation.1 / 2All blackout loads are successfully re-energizedvia the diesel generators.
3Attachment
3Attachment
: [[9EMERGE]] [[]]
: [[9EMERGE]] [[NCY RESPONSE ORGANIZATION SEQUENCE]]
: [[NCY]] [[]]
: [[RESPON]] [[]]
: [[SE]] [[]]
: [[ORGANI]] [[]]
: [[ZATION]] [[]]
: [[SEQUEN]] [[]]
: [[CE]] [[]]
: [[OF]] [[]]
: [[OF]] [[]]
: [[EVENTS]] [[The following table provides a summary of the actions taken by the Catawba EmergencyResponse Organization following the]]
: [[EVENTS]] [[The following table provides a summary of the actions taken by the Catawba EmergencyResponse Organization following the]]
Line 542: Line 502:
busses as designed.1413Emergency ResponseOrganization (ERO)Pager messagePagers set off to alert
busses as designed.1413Emergency ResponseOrganization (ERO)Pager messagePagers set off to alert
: [[ERO]] [[to activate]]
: [[ERO]] [[to activate]]
: [[TSC]] [[and]]
: [[TSC]] [[and OSCfor]]
: [[OSC]] [[for]]
: [[LOOP]] [[event1414Notice of Unusual Event is declared based on the lossof all]]
LOOP event1414Notice of Unusual Event is declared based on the lossof all AC power from offsite sources for more than 15
AC power from offsite sources for more than 15
minutes with onsite power available. (Sent from the
minutes with onsite power available. (Sent from the
Control Room)1421Group call made to notify 4 of 5 state/local emergencymanagement agencies. York County not available on
Control Room)1421Group call made to notify 4 of 5 state/local emergencymanagement agencies. York County not available on
Line 555: Line 515:
TSC staff 61 minutes late. The one hour
TSC staff 61 minutes late. The one hour
notification was not made as required by the Control
notification was not made as required by the Control
Room Offsite Agency Communicator.1626Message #3Event update provided to State and local agencies(Sent from the
Room Offsite Agency Communicator.1626Message #3Event update provided to State and local agencies(Sent from the TSC)1717Message #4Event update provided to State and local agencies(Sent from the TSC)
: [[TSC]] [[)1717Message #4Event update provided to State and local agencies(Sent from the]]
TSC)
2Attachment 91810Message #5Event update provided to State and local agencies(Sent from the
2Attachment 91810Message #5Event update provided to State and local agencies(Sent from the
: [[TSC]] [[)May 20, 2006 (continued)]]
: [[TSC]] [[)May 20, 2006 (continued)TIMECOMMENTDESCRIPTION1819- - - - -Emergency Operations Facility (EOF) activated at therequest of the]]
: [[TIMECO]] [[MMENTDESCRIPTION1819- - - - -Emergency Operations Facility (EOF) activated at therequest of the]]
: [[TSC]] [[Emergency Coordinator. The]]
: [[TSC]] [[Emergency Coordinator. The]]
EOF
EOF
provided support to the site by assuming the
provided support to the site by assuming the
responsibility of conducting offsite agency
responsibility of conducting offsite agency
communications and performing dose projections.1858Message #6Event update provided to State and local agencies(Sent from the
communications and performing dose projections.1858Message #6Event update provided to State and local agencies(Sent from the EOF)1949Message #7Event update provided to State and local agencies(Sent from the EOF)2041Message #8Event update provided to State and local agencies(Sent from the EOF). Offsite power restoration in
: [[EOF]] [[)1949Message #7Event update provided to State and local agencies(Sent from the]]
progress. Message content "Offsite power partiallyrestored to Unit 2 at 2027
EOF)2041Message #8Event update provided to State and local agencies(Sent from the EOF). Offsite power restoration in
"2054Message #9Event update provided to State and local agencies(Sent from the EOF). Message content "Offsite powerrestoration in progress. Offsite power partially restored
progress. Message content "Offsite power partiallyrestored to Unit 2 at 2027"2054Message #9Event update provided to State and local agencies(Sent from the EOF). Message content "Offsite powerrestoration in progress. Offsite power partially restored
to both Unit 1 and Unit 2.
to both Unit 1 and Unit 2."2148Message #10Event update provided to State and local agencies(Sent from the
"2148Message #10Event update provided to State and local agencies(Sent from the EOF). Message content "Power restoration to plant
: [[EOF]] [[). Message content "Powerrestoration to plant systems in progress."2246Message #11Event update provided to State and local agencies(Sent from the]]
systems in progress
EOF). Message content "Power andequipment restoration continues. Commencing
."2246Message #11Event update provided to State and local agencies(Sent from the EOF). Message content "Power andequipment restoration continues. Commencing
cooldown to comply with facility Technical
cooldown to comply with facility Technical
Specifications."2339Message #12Event update provided to State and local agencies(Sent from the EOF). Message content "Power andequipment restoration continues. Cooldown on both
Specifications
."2339Message #12Event update provided to State and local agencies(Sent from the EOF). Message content "Power andequipment restoration continues. Cooldown on both
units in progress to comply with facility Technical
units in progress to comply with facility Technical
Specifications."
Specifications
3Attachment 9May 21,
."
: [[2006TIMECO]] [[]]
3Attachment 9May 21, 2006TIMECOMMENTDESCRIPTION0033Message #13Event update provided to State and local agencies(Sent from the EOF). Message content "Equipmentand power restoration continues. Power has been
MMENTDESCRIPTION0033Message #13Event update provided to State and local agencies(Sent from the EOF). Message content "Equipmentand power restoration continues. Power has been
restored to 3 of 4 essential busses. Cooldown
restored to 3 of 4 essential busses. Cooldown
continues on both units to comply with facility
continues on both units to comply with facility
Technical Specifications."0123Message #14Event update provided to State and local agencies(Sent from the EOF). Message content "Cooldown nolonger necessary and temperatures are being
Technical Specifications.
"0123Message #14Event update provided to State and local agencies(Sent from the EOF). Message content "Cooldown nolonger necessary and temperatures are being
maintained steady. Power has now been restored to
maintained steady. Power has now been restored to
all 4 essential busses from offsite sources."0145Message #15Event update provided to State and local agencies(Sent from the EOF). Message content "Power hasbeen restored to all essential busses. Plant conditions
all 4 essential busses from offsite sources
are stable. Unusual Event has been terminated."
."0145Message #15Event update provided to State and local agencies(Sent from the EOF). Message content "Power hasbeen restored to all essential busses. Plant conditions
: [[10INTEGR]] [[]]
are stable. Unusual Event has been terminated
: [[ATED]] [[]]
."
: [[10INTEGR]] [[ATED]]
: [[PLANT]] [[]]
: [[PLANT]] [[]]
: [[SEQUEN]] [[CE]]
: [[SEQUEN]] [[CE]]
: [[OF]] [[]]
: [[OF]] [[]]
: [[EVENTS]] [[Catawba Unit]]
EVENTSCatawba Unit 1TIMEEVENT DESCRIPTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red
: [[1TIMEEV]] [[]]
: [[ENT]] [[]]
: [[DESCRI]] [[]]
PTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red
busses and a 1A Zone lockout.14:01:49The first-out annunciator was "NI Hi Flux Rate - Power Range"; however, areview of reactor power traces do not show any valid increase or change in
busses and a 1A Zone lockout.14:01:49The first-out annunciator was "NI Hi Flux Rate - Power Range"; however, areview of reactor power traces do not show any valid increase or change in
reactor power at this time (NOTE: The licensee is reviewing data to determine
reactor power at this time (NOTE: The licensee is reviewing data to determine
Line 605: Line 560:
open on demand. Normal letdown was subsequently re-established through the
open on demand. Normal letdown was subsequently re-established through the
fixed orifice line due to the variable orifice control valve failing closed following
fixed orifice line due to the variable orifice control valve failing closed following
the
the LOOP and not re-opening.14:08:02Main Steam Isolation signal is received when the 1C steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitions to the
: [[LO]] [[]]
steam generator PORV's.14:12Intermediate Range nuclear instrumentation drops below 1E-10 amps (P6setpoint).14:14Operations Shift Manager declared a Notice of Unusual Event (EmergencyAction Level 4.5.U.1, "AC electrical power from all offsite sources has been lost
OP and not re-opening.14:08:02Main Steam Isolation signal is received when the 1C steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitions to the
steam generator
: [[PORV]] [['s.14:12Intermediate Range nuclear instrumentation drops below 1E-10 amps (P6setpoint).14:14Operations Shift Manager declared a Notice of Unusual Event (EmergencyAction Level 4.5.U.1, "]]
AC electrical power from all offsite sources has been lost
for more than 15 minutes with onsite power available") due to the dual unit loss
for more than 15 minutes with onsite power available") due to the dual unit loss
of offsite power. Emergency Response Organization page sent to activate the
of offsite power. Emergency Response Organization page sent to activate the
Line 616: Line 567:
Emergency Event Notification timeline for details on the licensee's response to
Emergency Event Notification timeline for details on the licensee's response to
the event).
the event).
2Attachment 1014:22Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), two of three pressurizer
2Attachment 1014:22Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), two of three pressurizer PORV's begin to cycle to
: [[PO]] [[]]
RV's begin to cycle to
control primary system pressure.  (See section 4OA5.4 for details on the
control primary system pressure.  (See section 4OA5.4 for details on the
pressurizer
pressurizer PORV lifts). No pressurizer safety valves opened during the event.14:55Normal letdown is restored through the fixed orifice line.
: [[PO]] [[]]
RV lifts). No pressurizer safety valves opened during the event.14:55Normal letdown is restored through the fixed orifice line.
20:34Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through
20:34Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through
the use of auxiliary feedwater and steam generator
the use of auxiliary feedwater and steam generator PORV's.20:40Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress toenergize the 4.16kV vital busses from offsite power and secure the diesel
: [[PO]] [[]]
RV's.20:40Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress toenergize the 4.16kV vital busses from offsite power and secure the diesel
generators.21:55Final pressurizer
generators.21:55Final pressurizer
: [[PORV]] [[actuation. Total number of actuations during event on]]
: [[PORV]] [[actuation. Total number of actuations during event on]]
: [[PORV]] [[]]
: [[PORV]] [[1NC-34A was 57 cycles and on]]
: [[1NC]] [[-34A was 57 cycles and on]]
: [[PORV]] [[1]]
: [[PORV]] [[]]
NC-32B, five cycles.23:034.16kV vital bus 1ETB is aligned to offsite power.
: [[1NC]] [[-32B, five cycles.23:034.16kV vital bus 1]]
ETB is aligned to offsite power.
23:061B diesel generator output breaker is opened. Actions initiated to secure the 1Bdiesel generator and place it in stand-by.May 21, 200601:114.16kV vital bus
23:061B diesel generator output breaker is opened. Actions initiated to secure the 1Bdiesel generator and place it in stand-by.May 21, 200601:114.16kV vital bus
: [[1ETA]] [[is aligned to offsite power. Due to the 1A Zone lockout,power is being supplied from the Unit 2 A]]
: [[1ETA]] [[is aligned to offsite power. Due to the 1A Zone lockout,power is being supplied from the Unit 2 A]]
Line 648: Line 591:
in-service at 21:17. Repair and recovery actions are initiated.
in-service at 21:17. Repair and recovery actions are initiated.
: [[10CATAWB]] [[A]]
: [[10CATAWB]] [[A]]
: [[UNIT]] [[]]
: [[UNIT]] [[2]]
: [[2TIMEEV]] [[]]
TIMEEVENT DESCRIPTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red
: [[ENT]] [[]]
: [[DESCRI]] [[]]
PTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red
busses and a 2B Zone lockout.14:01:46The first-out annunciator is "Under Frequency Conditions on the Reactor CoolantPump Busses" as sensed by the reactor coolant pump monitoring circuit. Both
busses and a 2B Zone lockout.14:01:46The first-out annunciator is "Under Frequency Conditions on the Reactor CoolantPump Busses" as sensed by the reactor coolant pump monitoring circuit. Both
reactor trip breakers open and control rods insert. The main turbine trips on
reactor trip breakers open and control rods insert. The main turbine trips on
Line 660: Line 600:
(two motor-driven and one turbine-driven) start automatically and provide
(two motor-driven and one turbine-driven) start automatically and provide
inventory makeup to the steam generators.14:08:05Letdown isolation occurs when pressurizer level reaches 17%. Excess letdownis placed in service. Normal letdown was subsequently re-established.14:08:21Main Steam Isolation signal is received when the 2A steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitioned to
inventory makeup to the steam generators.14:08:05Letdown isolation occurs when pressurizer level reaches 17%. Excess letdownis placed in service. Normal letdown was subsequently re-established.14:08:21Main Steam Isolation signal is received when the 2A steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitioned to
the steam generator
the steam generator PORV's.14:27Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), one of three pressurizer PORV's begins to cycle to
: [[PORV]] [['s.14:27Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), one of three pressurizer]]
PORV's begins to cycle to
control primary system pressure.  (See section 4OA5.4 for details on the
control primary system pressure.  (See section 4OA5.4 for details on the
pressurizer
pressurizer
Line 675: Line 613:
PORV 2NC-34A was 35 cycles.
PORV 2NC-34A was 35 cycles.
2Attachment 10----------Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through
2Attachment 10----------Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through
the use of auxiliary feedwater and steam generator
the use of auxiliary feedwater and steam generator PORV's.20:27Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress tore-energize the 4.16kV vital busses from offsite power and secure the diesel
: [[PO]] [[]]
RV's.20:27Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress tore-energize the 4.16kV vital busses from offsite power and secure the diesel
generators.23:314.16kV vital bus 2ETA is aligned to offsite power.
generators.23:314.16kV vital bus 2ETA is aligned to offsite power.
23:362A diesel generator output breaker is opened. Actions initiated to secure the 2Adiesel generator and place it in stand-by.23:534.16kV vital bus
23:362A diesel generator output breaker is opened. Actions initiated to secure the 2Adiesel generator and place it in stand-by.23:534.16kV vital bus
Line 685: Line 621:
: [[EP]] [[and transitioned to]]
: [[EP]] [[and transitioned to]]
OP/2/A/6100/002;
OP/2/A/6100/002;
Controlling Procedure for Unit Shutdown12:00The unit was stabilized at 460 F and 1900 psig in Mode 3. Recovery actions areinitiated.May 22, 200611:00Vacuum is reestablished in the main condenser allowing secondary pressurecontrol to be transferred from the steam generator
Controlling Procedure for Unit Shutdown12:00The unit was stabilized at 460 F and 1900 psig in Mode 3. Recovery actions areinitiated.May 22, 200611:00Vacuum is reestablished in the main condenser allowing secondary pressurecontrol to be transferred from the steam generator PORV's to the steam dumps
: [[PO]] [[]]
RV's to the steam dumps
and conserve inventory required to feed the steam generators.
and conserve inventory required to feed the steam generators.
}}
}}

Revision as of 02:51, 27 October 2018

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  Duke Energy icon.png
Issue date: 06/29/2006
From: Casto C A
Division Reactor Projects II
To: Jamil D M
Duke Energy Corp
References
IR-06-009
Download: ML061800329 (48)
v • d • e


Text

June 29, 2006

Duke Energy CorporationATTN:Mr. D. M. JamilSite Vice President Catawba Site4800 Concord Road York, SC 29745-9635

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 AugmentedInspection 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 ona 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 werebeing 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 generatorroom, 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 DEC2continued operation of the units. The team found some issues which will require additionalinspection 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 itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web si te at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Charles A. Casto, DirectorDivision of Reactor ProjectsDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52

Enclosure:

NRC Inspection Report 05000413/2006009 and 05000414/2006009

w/Attachments:

Supplemental Informationcc w/encl: (See page 3)

DEC3cc w/encl:Randy D. Hart Regulatory Compliance Manager Duke Energy Corporation Electronic Mail DistributionLisa VaughnAssociate General Counsel Duke Energy Corporation 526 South Church Street Mail Code EC 07H Charlotte, NC 28202Timika Shafeek-HortonAssistant General Counsel Duke Energy Corporation 526 South Church Street-EC07H Charlotte, NC 28202David A. RepkaWinston & Strawn LLP Electronic Mail DistributionNorth Carolina MPA-1Electronic Mail DistributionHenry J. Porter, Asst. DirectorDiv. of Radioactive Waste Mgmt.

S. C. Department of Health and Environmental Control Electronic Mail DistributionR. Mike GandyDivision of Radioactive Waste Mgmt.

S. C. Department of Health and Environmental Control Electronic Mail DistributionElizabeth McMahonAssistant Attorney General S. C. Attorney General's Office Electronic Mail Distribution Vanessa QuinnFederal Emergency Management Agency Electronic Mail DistributionNorth Carolina Electric Membership Corporation Electronic Mail DistributionCounty Manager of York County, SCElectronic Mail DistributionPiedmont Municipal Power AgencyElectronic Mail DistributionR. L. Gill, Jr., ManagerNuclear Regulatory Issues and Industry Affairs Duke Energy Corporation 526 S. Church Street Charlotte, NC 28201-0006

_________________________OFFICERII:DRSRII:DRSRII:DRSRII:SummerRII:CatawbaRII:DRSSIGNATURE/RA//RA By JMoorman for//RA//RA//RA By JMoorman for//RA By JMoorman for/NAMEJMoormanMMerriweatherMErnstesLCainASabischWLewisDATE6/20/066/27/066/27/066/29/066/29/066/29/06 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:50-413, 50-414License 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 RoadYork, SC 29745Dates:May 23 - 31, 2006 Team Leader:James H. Moorman, III, ChiefOperations Branch Division of Reactor SafetyInspectors:L. Cain, Resident Inspector, V.C. SummerN. Merriweather, Senior Reactor Inspector A. Sabisch, Resident Inspector, Catawba W. Lewis, Reactor InspectorApproved by:Charles A. Casto, DirectorDivision of Reactor Projects

SUMMARY OF FINDINGS

IR 05000413/2006009, 05000414/2006009; 5/23-31/06; Catawba Nuclear Station, Units 1 and2; Augmented Inspection.This inspection was conducted by a team consisting of inspectors from the NRC's Region IIoffice 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."A.

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 lossof offsite power (LOOP) event and the partial flooding of the 1A diesel generator (DG) room.

The team found that the licensee's 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 EventsOn May 20, 2006, at 2:01 p.m., an electrical fault in the Catawba 230kV switchyard causedseveral power circuit breakers (PCB's) 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 tothe 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 lossof 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), andsubsequently 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 16.9kV 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 toclogged 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 ScopeBased 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 decisionpoints, from the time the LOOP occurred until both units were stabilized.*Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's classification of the event.

4*Identify additional actions planned by the licensee in response to this event, includingthe time line for their completion of the investigation and follow-on analysis.*Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 pressurizer power operated relief valves.*Determine if there are any generic issues related to this event which warrant anadditional 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 issuesto regional management.4.OTHER ACTIVITIES

4OA5 Augmented Inspection

Main article: IP 93800

.1Develop a complete sequence of events, including applicable management decisionpoints, 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 elementinto 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 operationcompleted and safety loads re-energized from the diesel generators.*Integrated plant response - Unit 1 stabilized in Mode 5 on Residual HeatRemoval (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 Attachment8, "Electrical Plant Sequence of Events."

5On 20 May 2006 at 2:01 p.m. EDT, a phase-to-ground electrical fault within the currenttransformer (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 theCatawba main generator, transformers, and switchyard in Attachment 6 for specificbreaker and relay locations):The initial event that occurred was an internal fault in the X-phase CT associated withPower Circuit Breaker (PCB) 18. Initial indications of neutral overcurrent (74TM) on all four main step-up transformersand 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 - PCB's 15, 18, 21, 24, 27, 30 and 33 (*)*Red bus (87BR) differential - PCB's 10, 13, 16, 19, 22, 25, 28 and 31*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and Main Generator CircuitBreaker (GCB) 1A* It could not be confirmed that PCB 12 opened during the event. The breaker wassubsequently demonstrated to be able to cycle by both Transmission System and Catawba Nuclear Station personnel. The station's 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 sidecoils 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 - PCB's 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.

6Unit 2 was attempting to feed 100% of its output through PCB 20 to the Pacolet TieStation 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 becauseundervoltage 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 wouldhave 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 - PCB's 12, 15, 18, 21, 24, 27, 30 and 33*Zone 1A (86A) lockout - PCB's 18 (repeat signal), 17 and GCB 1A*Zone 2B (86B) lockout - PCB's 23, 24 (repeat signal) and GCB 2BBoth units would have runback to 48% main generator electrical output. In combinationwith 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 currenttransformer 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 HiFlux Rate Power Range" signal. Subsequent analysis of plant data determined that the 7actual cause of this signal was from an electrical perturbation on the instrument busresulting 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 byactuation 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 thecore on the two units.Both main turbines tripped upon receipt of the reactor trip signals. Following the loss ofall 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 electricalpower 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 levelsin 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 (PORV's) once steam generator pressure dropped below 775 psig and a main steam line isolation signal was generated. Two of the three pressurizer PORV's on Unit 1 and one of the three PORV's 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 andoffsite 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 performedin 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 theUnit 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.

8Reactor Coolant Pumps were started to re-establish forced circulation on Unit 1 at 3:20p.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 theunit 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 inAttachment 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 currenttransformer 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 verbalnotifications 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 County's 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 AgencyCommunicator; 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 anynecessary 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 9communications was transferred to the TSC from the Control Room Offsite AgencyCommunicator. 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 4.16kVessential 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 licensee's emergency responseorganization 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 inresponse to the LOOP event including the accuracy and timeliness of the licensee'sclassification of the event

a. Inspection Scope

The inspectors evaluated the response of the licensee's staff to the LOOP from the startof 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 sitewas 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 10some minor equipment malfunctions, the procedures in-use allowed them to respond tothose 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 greaterthan 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 stabilizingthe 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..3Identify additional actions planned by the licensee in response to this event, includingthe time line for their completion of the investigation and follow-on analysis

a. Inspection Scope

The inspectors reviewed the licensee's Trip and Transient Investigation report for eachunit. An independent review of operator aid computer data, control room logs, emergency response organization logs, PIP's 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 station's 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. Thelists 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 identifiedfollowing 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.

11UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatusInitial reactor tripsignal 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 1NOPIP C-06-3874 wasinitiated to conduct an Apparent Cause

assessment into the cause of the signal.(PIP C-06-3874)Loop B hot legRTD card failed several minutes into the eventThe cards requiredreplacement and calibration.YESThe cards werereplaced and recalibrated. (WO 98790462 /PIP C-06-3879)Excess letdowncontrol valve 1NV-122 would not open following the reactor tripThe valve was repairedand stroked successfully.YESRepairs were completed

(PIP C-06-3873)Normal letdownvariable orifice control valve failed to re-open following eventThe valve has beenrepaired and stroked successfully.YESRepairs have beencompleted (WR 98375944)1D steamgenerator PORV was slow to openThe positioner requiredrecalibrationYESRepairs werecompleted.(PIP C-06-3883)

Unsealedelectrical conduits resulted in flooding of the 1A DG roomConduits between thecooling 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.YESAll penetrations intothe Unit 1 A and B diesel generator rooms were sealed per construction drawings.(PIP C-06-3902)12UNIT 1 : Non-Electrical IssuesIssueDetailsReq. for RestartStatus"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring wasreterminated.(WO 98791173 /PIP C-06-4037)Motor statorcoolers for the reactor coolant pumps and the LCVU coolers exhibited restricted flow following the eventOn a loss of offsitepower 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.YESAll 4 reactor coolantpump motor stator coolers and LCVU coolers were

cleaned.(PIP C-06-3935)1A1 and 1A2 WNsump pumps in the 1A DG room failed following being submerged after conduit flooding eventThe two sump pumpswere totally submerged after the 1A DG room flooded. The motors required replacement.NOThe motors werereplaced and tested.(WO 98791331)UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDigital FeedwaterControl System driver card for the 2B CFPT failed and switched to the backup cardThe primary cardneeds to be replaced and functional test performed.NOPrimary card hasbeen replaced and calibrated.(PIP C-06-3897)Zone B lockout occurred following the reactor tripThe Y Phase currenttransformer 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.NOThe currenttransformer for PCB 23 Y Phase was replaced with a new unit that was stored in the CNS Switchyard(PIP C-06-4089)13UNIT 2 : Non-Electrical IssuesIssueActionsReq. for RestartStatusDRPI indicationfor rods H4 and D8 did not go to zero following the reactor tripSubsequent reviewdetermined that the indication was for the OAC only.NOProblem found on adigital input card in the OAC. Card was reset and indication problems cleared.(PIP C-06-3881)Tavg indicationdrifted high following the reactor tripTavg NSA carddetermined to require recalibrationYESRecalibrationperformed prior to restart.(PIP C-06-3991)VCT relief valvefailed to open at its 75 psig setpointThe VCT pressurereached 92 psig during the event. An analysis was performed to

assess the structural integrity impact due to this pressure transient.YESAnalysis showedthat the integrity of the tank and piping was not adversely affected. No replacement of the valve was planned.(PIP C-06-3927)"A" Control Areachilled water chiller failed to auto start following the eventA loose wire on theProgram Timer within the chiller control panel was found.YESWiring has beenreterminated.(WO 98791173 /PIP C-06-4037)14Station Electrical IssuesIssueActionsReq. for RestartStatusDue to theelectrical fault, possible damage may have occurred to the CT's on PCB's 17

& 18Perform Doble and/orSaturation testing on X, Y, and Z phases of

PCB's 17 and 18YESAll 3 phases of PCB17 and 18 were Doble tested; however, Saturation testing was not found to be required

on PCB 17.

WO 9879052 WO 9879053 WO 9879054The CT on the Xphase of PCB 18 failed, initiating the LOOP eventReplace the X-phaseCT on PCB 18 and any other damaged componentsYESThe CT andassociated wiring /

conduits were replaced.WO 98790418Based on OEfrom MNS, the potential for degradation of the MOD contacts following a fault on the transmission line existedVisually inspect thedisconnects associated with PCB 17's and 18YESVisual inspectionscompleted and no repairs required.WO 98790594WO 98790593 WO 98790581 WO 98790580Inspect PCB's 17and 18 for damage or excessive build-up of arc extingushment "salt"Perform Doble testingand visual inspections of the PCB'sYESDoble testingperformed satisfactorily, cleaned arcing contacts and replaced main contacts.WO 98790416WO 98790417 15Station Electrical IssuesIssueActionsReq. for RestartStatus Zone 2BProtective Relays need to be tested to verify calibration following the LOOPRelay calibrations wererequired and visual inspections of connections were performed to ensure no degradation existsYESAll relays were foundto be satisfactory in the "as-found" condition. No other repairs were required.WO 98790852Differential relayswere not set in IAW Power Delivery requirements Verify currentdifferential relays on the Red and Yellow busses and adjust as required to meet Power Delivery requirementsYESThe 87BY X-Y-Z(Yellow bus) and 87BR X-Y-Z (Red bus) differential relays were checked and reset as required.WO 98790851WO 98790853 WO 98790443Determine whythe 2B Zone Lockout occurredBased on Engineeringrecommendations, several tests were performed on the 2B transformerYESAfter disconnectingthe 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 98790412WO 98790413 WO 98790414 WO 98790415 16Station Electrical IssuesIssueActionsReq. for RestartStatusEnsure there isno issue related to the 1A transformer following the LOOP eventPerform post-trip Dobletesting to ensure no problems exist following differential actuationYESTesting indicatedthat there were no problems with the 1A transformerWO 98790430The MOD wasnot 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 PCB's opening which may have resulted in the degradation of grading capacitors in the interrupter heads.Perform post-trip Dobletests on individual PCB's to ensure no degradation occurred.

PCB's 14, 17, 18, 20, 23, and 24 were tested.YESDoble testing completed satisfactorilyWO 98790433WO 98790434 WO 98790435 WO 98790436 WO 98790437 WO 98790438Investigate thecause of the PCB 18 CT failure. Gas concentration ofseveral PCB's scheduled to be checked based on past history and issues related to moisture intrusion into CT's.

PCB's to be checked include PCB 14, 15, 17, 18, 20, 21, 23 and

24NOTesting was inprogress, no issues found to-date.WO 98790585WO 98790586 WO 98790587 WO 98790588 WO 98790589 WO 98790590 WO 98790591 WO 98790592Copper splatterwas found on the neutral bushing of the 2B Main S/U transformer due to the fault currentThe neutral bushingrequired cleaning following experiencing the high fault current associated with the eventYESThe bushing was cleanedWO 98791075 17Station Electrical IssuesIssueActionsReq. for RestartStatusDuring theinvestigation into the Unit 2 2B lockout, Power Delivery recommended that testing be conducted The CT's for the X, Yand Z phases on PCB's 23 and 24 were isolated and tested to check for damageYESAll 3 CT's on PCB24 tested satisfactorily. The Y phase CT on PCB 23 failed and was replaced. No other problems were identified.WO 98791140WO 98791142.4Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves (PORVs)

a. Inspection Scope

Inspectors assessed the circumstances surrounding the multiple lifting and reseating ofthe 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 ObservationsEach unit is equipped with three pressurizer PORVs. The PORVs are air operatedvalves 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 reactorcoolant 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 duringa 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 2,235psig. The other two PORV's will lift when pressure reaches their respective lift setpoints.

18Specific to the May 20, 2006 LOOP event, Unit 1 PORVs 1NC-32B and 1NC-34Aactuated 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 ofcycles 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 PORV's 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 a1996 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 plantpressure.

.5 Determine if there are any generic issues related to this event which warrant anadditional NRC response.

As part of this review, assess the implications of a commoncause failure of the emergency diesel generators due to external flooding. Promptlycommunicate any potential generic issues to regional management.

a. Inspection Scope

During the inspection team's 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 computeralarm 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 SettingsThe inspectors reviewed the design of the offsite power system for compliance with therequirements 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 fewseconds 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 KVswitchyard 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 withthe relay setpoint calculations developed in 1981 by Duke Energy's 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 EventOn 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 loadsequencer 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 wereentered. 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.

20Inspections were performed on all other electrical conduits that entered the auxiliarybuilding 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 andcontributing 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 theextent 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.4OA6MeetingsExit Meeting SummaryOn May 26, 2006, the inspection team presented the preliminary inspection results toMr. 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 AugmentedInspection 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

2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened05000413, 414/2006009-01URITimeliness of Notification to the NRC ofLoss of Offsite Power Event on May 20,

2006.(Section 4OA5.1.b.3)05000413, 414/2006009-02URIImproper relay settings in the Catawba230kV switchyard resulted in a total loss of

offsite power following failure of a PCB

current transformer (Section 4OA5.5.b.1)05000413/2006009-03URIReview of failure to seal conduits intomanholes and the 1A DG room as required

by design and construction documents

(Section 4OA5.5.b.2)05000413, 414/2006009-04 URIReview the extent of condition andcorrective actions to address degraded

seals on below-grade electrical conduits

entering the auxiliary building

(Section 4OA5.5.b.2)

3

LIST OF DOCUMENTS REVIEWED

Technical SpecificationsCatawba Nuclear Station UFSAR Chapter 5Catawba Nuclear Station Technical Specifications 3.4, 3.5, 3.8

Catawba Nuclear Station Technical Specification Bases 3.4, 3.5, 3.8Calculations / SpecificationsCNS-1465.00-00-0021, Design Basis Specification for the Plant and Offsite Power Protective
Relaying, Rev. 0
CNS-1553.NC-00-0001, Design Basis Specification for the Reactor Coolant (NC) System, Rev.
25
CNS-1465.00-00-0005, Design Basis Specification for the Design Basis Event, Rev. 2
CNC-1223.12-00-0051, Effect of PORV Operation on CLA Nitrogen Pressure and NI System Operability CalculationDrawingsCN-1938-01; Electrical Equipment Layout; Outdoor Area; General Plan
CN-1938-04, 05, 06 and 07; Electrical Equipment Layout; Outdoor Area; Section and DetailsProcedures / SurveillancesEP/1/A/5000/E-0; Reactor Trip or Safety Injection; Rev. 27EP/1/A/5000/ES-0.1; Reactor Trip Response, Rev. 22
EP/1/A/5000/ES-0.2; Natural Circulation Cooldown, Rev. 19
AP/1/A/5500/007; Loss of Normal Power; Rev. 49
AP/1/A/5500/012; Loss of Charging or Letdown; Rev. 23
EP/2/A/5000/E-0; Reactor Trip or Safety Injection; Rev. 26
EP/2/A/5000/ES-0.1; Reactor Trip Response, Rev. 22
EP/2/A/5000/FR-1.1; Response to High Pressurizer Level, Rev. 11
AP/2/A/5500/012; Loss of Charging or Letdown; Rev. 19
AP/2/A/5500/007; Loss of Normal Power; Rev. 49
PT/0/A/4150/002A; Transient Investigation; Rev. 0 (For Unit 1 and Unit 2)
IP/0/B/3112/008; Calibration of RN System Conduit Manhole Sump Level Switches, Rev. 004
IP/0/A/3850/013B; Procedure for Sealing Rigid Steel Field Run Conduit; Rev. 10
EP/1/A/5000/E-0; Reactor Trip or Safety Injection, Rev. 027
IP/1/B/3222/063; Calibration Procedure for Pressurizer Pressure Control, Rev. 027
2Attachment 3Miscellaneous DocumentsDow Corning 732 Multi-Purpose Sealant Product Data SheetNSD-407, Maintenance Interface Agreement for Nuclear Generation, Electric Transmission, Information Management, and Power Generation Departments, Rev. 06
NSD-409, Engineering Guidlines for Nuclear Station Switchyard and Main Step-Up Transformer Activities, Rev. 06
NSD-502, Corporate Conduct of Operations in the Switchyard, Rev. 07
Work OrdersWO
98791331;
1A1 and 1A2 WN sump pumps failed meggar testing following submergence when water drained from manhole
CMH-3 into the 1A diesel generator room.
WO 98790811;
2B Digital Feedwater Control System primary driver card failed and swapped to the backup card.
WO 98766406; Remove hatches and inspect manholes
CMH-18A and B
WO 9879087; Seal conduits in CMH-18A
WO 9879098; Seal conduits in
CMH-18BWork Orders associated with the switchyard and main generator activitiesWO
9879052
WO 9879053
WO 9879054
WO 98790418
WO 98790594
WO 98790593
WO 98790581
WO 98790580
WO 98790416
WO 98790417
WO 98790852
WO 98790851
WO 98790853
WO 98790443
WO 98790412
WO 98790413
WO 98790414
WO 98790415
WO 98790430
WO 98790433
WO 98790434
WO 98790435
3Attachment 3WO 98790436WO 98790437
WO 98790438
WO 98790585
WO 98790586
WO 98790587
WO 98790588
WO 98790589
WO 98790590
WO 98790591
WO 98790592
WO 98791075
WO 98791140
WO 98791142PIPsPIP C-06-4180, Need to incorporate the pressurizer PORV operation into future training and

Operating Experience

PIP C-06-4150, PORC meeting held on 5/29/06 for the restart of Unit 1
PIP C-06-4149, Operability assessment for the conduit between manholes
CMH-2, 3, 18A and
18B and their respective diesel rooms due to the conduit now being sealed on both ends.
PIP C-06-4112, Questions / concerns raised over the inspections performed on conduit seals in manholes
CMH-18A&B which required rework
PIP C-06-4106, Critique of the Trip and Transient process following the LOOP
PIP C-06-4089, Y Phase Current Transformer associated with
PCB 23 found to be damaged.
PIP C-06-4087, Resident Inspector identified that spare conduits were to be stubbed out and capped per the drawing.
Conduit was sealed instead.
Need to resolve difference.
PIP C-06-4049, Action items from the PORC meeting held on 5/24/06 to discuss the cause(s)

of the Unit 1 and Unit 1 LOOP event

PIP C-06-4037, PORC action items from plant transient investigation into the Unit 2 reactor trip following the LOOP on 5/20/06
PIP C-06-4012, E1 work request written to inspect cooling tower trenches for water barrier integrity
PIP C-06-4007, E1 wqork request written to inspect and seal conduit sleeves for CMH-16B
PIP C-06-3983, E1 work requests written to inspect essential cabinets for water intrusion after
1A diesel generator flooding
PIP C-06-3947, E1 work request issued to repair the 1A DG prelube pump which will not start
PIP C-06-3941, Power Delivery questioned the testing methods used at Catawba for transformer saturation testing
PIIP C-06-3934, Need to assess the flooding design basis for the RN conduit penetrations into the diesel generator rooms
4Attachment 3PIP C-06-3902, Unit 2 cooling towers overflowed causing water intrusion into the 1A diesel generator room
PIP C-06-3893, Cooling towers overflowing excessively causing water to build up on the ground surrounding the towers
PIP C-06-3889, Reactor Engineering review of dual unit LOOP
PIP C-06-3886, Unit 2 containment walkdown inspection results
PIP C-06-3883, Steam Generator 1D PORV was slow to respond
PIP C-06-3874, Unit 1 reactor trip investigation following loss of offsite power
PIP C-03-3297, During the flush of 1B NS heat exchanger, the sump pump for the RN conduit manhole
CMH-4A started pumping down
PIP C-03-2716, Inspection of structural components in site RN conduit manholes
PIP C-01-3842, Documentation of entries into RN conduit manholes
PIP C-06-3864, Unit 1 Loss of Offsite Power
PIP C-06-3865, Unit 2 Loss of Offsite Power
PIP C-06-3873, 1NV-122B (Excess letdown isolation) failed to open
PIP C-06-3880, 2NC-34A opened at lower pressure than setpoint during LOOP event
PIP C-06-3927, Unit 2 VCT Relief Valve (2NV223) did not function properly during dual unit Loss of Offsite Power event on 5/20/06
PIP C-06-4091, During the recent duel unit LOOP event, there was a similar drop in pressure of psig in NI CLA 1A and 18 psig in NI CLA 2A.
On both units, CLA pressure decreased after aligning N2 supply to the PZR PORVs 1(2)NC-34A.
As identified below, the number of PZRPORV cycles for each unit 1 and 2 PZR PORV was incorrectly reported as 107 strokes and 35 strokes, respectively.
This led the NRC to question reliable operation of unit 2 PZR PORV,
2NC-34A (due to similar N2 usage for significantly fewer cycles).
PIP C-96-0306, Pressurizer PORV Issues during Unit 2 LOOP
PIP C-95-1400, Calculation review identified potential grid/unit stability concerns.
Analysis will be done to address these concerns
PIP C-01-1556, This PIP is to document an evaluation that has been initiated to determine if any elective NSM's should be originated for generator protection in the event of a three phase fault to ground, within 1/2 mile of CNS, in conjunction with a breaker failure to trip.
This was previously identified in PIP C-95-01400
4

LIST OF ACRONYMS

ACAlternating CurrentAITAugmented Inspection Team

APAbnormal Operating Procedure

CFPTMain Feedwater Pump Turbine

CFRCode of Federal Regulations

CLACold Leg Accumulator

CMHConduit Manhole

DFCSDigital Feedwater Control System

DGEmergency Diesel Generator

DRPIDigital Rod Position Indication

EITEvent Investigation Team

EMEmergency Management (off-site agencies)

EOFEmergency Operations Facility

EPEmergency Operating Procedure

EROEmergency Response Organization

FIPFailure Investigation Process

FSARFinal Safety Analysis Report

GCBGenerator Circuit Breaker

GDCGeneral Design Criteria

KVKilovolt

LCVULower Containment Ventilation Unit

LOOPLoss of Offsite Power

NCVNon-Cited Violation

NDResidual Heat Removal System

NOUENotice of Unusual Event

NRCNuclear Regulatory Commission

NVChemical Volume and Control System

OACOperator Aid Computer

OPNormal Operating Procedure

OSCOperations Support Center

OSMOperations Shift Manager

PCBPower Circuit Breaker

PIPProblem Investigation Process (report)

PORVPower Operated Relief Valve

RNNuclear Service Water System

RTDResistance Temperature Detector

SDPSignificance Determination Process

SEITSpecial Event Investigation Team

SOESequence of Event Recorder

TSAILTechnical Specification Action Item Log

TSCTechnical Support Center

URIUnresolved Item

VCTVolume Control Tank

2Attachment 4WNEmergency Diesel Room Sump Pump SystemWOWork Order

WRWork Request

YCControl Room Chilled Water System

YVContainment Chilled Water System

5May 25, 2006MEMORANDUM TO: James H. Moorman, ChiefOperations Branch

Division of Reactor SafetyFROM: William

D. Travers, Regional Administrator /
RA /SUBJECT: REVISED AUGMENTED INSPECTION
TEAM [[]]

CHARTERAn Augmented Inspection Team (AIT) was established on May 23, 2006, for Catawba NuclearStation to inspect and assess the facts surrounding a loss of offsite power (LOSP) andsubsequent dual unit reactor trip at Catawba on or around May 20, 2006.The team composition and the objectives of the inspection are unchanged. However, theenclosed charter has been revised to clarify and expand on the actions to be accomplished by

Item "e" to assess the implications of a common cause failure of the emergency diesel

generators due to external flooding.For the period during which you are leading this inspection and documenting the results, youwill report directly to me. The guidance in Inspection Procedure 93800, "Augmented Inspection

Team," and Management Directive 8.3, "NRC Incident Investigation Program," applies to your

inspection.If you have any questions regarding the objectives of the enclosed revised charter, contactCharles

A. Casto at (404) 562-4500.Enclosure:

AIT Charter

Docket Nos.: 50-413 and 50-414License Nos.:

NPF -35 and NPF-52Distribution:cc:
W. Kane,
OEDO [[]]
S. Lee,
OEDO [[]]
J. Dyer,
NRR [[]]
C. Haney,
NRR [[]]
R. Martin,
NRR [[]]
R. Zimmerman,
NSIR [[]]
L. Plisco,
RII [[]]
C. Casto,
RII [[]]
V. McCree,
RII 2Attachment 5REVISED AUGMENTED INSPECTION
TEAM (
AIT ) CHARTERCATAWBA
LOSS [[]]
OF OFFSITE
POWER [[]]
AND [[]]
DUAL [[]]
UNIT REACTOR TRIPBasis for the Formation of the
AIT - On May 20, 2006, an electrical fault occurred apparentlycausing several power circuit breakers (

PCB's) to open in the Catawba switchyard. This fault

apparently caused several other PCB's to open resulting in a loss of offsite power (LOSP) and

trip of both Catawba reactors. In accordance with Management Directive (MD) 8.3, "NRC

Incident Investigation Program," deterministic and conditional risk criteria were used to evaluate

the level of NRC response for this operational event. The review concluded that the

circumstances of the event met the MD 8.3 deterministic criteria due to an apparent single

electrical failure causing a loss of offsite power to both operating units and reactor trips. The

risk review indicated the CCDP for the event met the criterion for an Augmented Inspection.

Subsequently, Region

II determined that the appropriate level of

NRC response was the

conduct of an Augmented Inspection.This Augmented Inspection is chartered to identify the circumstances surrounding this eventand review the licensee's actions following discovery of the conditions.Objectives of the

AIT - The objectives of the inspection are to: (1) review the facts surroundingthe

LOSP on May 20, 2006, and related plant complications; (2) assess the licensee's response

and investigation of the event; (3) identify any generic issues associated with the event; and (4)

conduct an independent extent of condition review.To accomplish these objectives, the following will be performed:

a.Develop a complete sequence of events, including applicable management decisionpoints, from the time the LOOP occurred until both units were stabilized.b.Identify and evaluate the effectiveness of the immediate actions taken by the licensee inresponse to this event including the accuracy and timeliness of the licensee's

classification of the event.c.Identify additional actions planned by the licensee in response to this evnet, includingthe time line for their completion of the investigation and follow-on analysis.d.Assess the circumstances surrounding the multiple lifting and reseating of the Unit 1and Unit 2 primary power operated relief valves.e.Determine if there are any generic issues related to this event which warrant anadditional 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.f.Document the inspection findings and conclusions in an inspection report within 30 daysof the inspection.

6CATAWB A
HIGH [[]]

VOLTAGE SWITCHYARD SIMPLIFIED DIAGRAMWith both units at 100% power, all of the breakers shown in the simplified diagram above are inthe CLOSED position.

6CATAWB A
MAIN [[]]

GENERATOR / SWITCHYARD SIMPLIFIED DIAGRAM

8ELECTR ICAL
PLANT [[]]
SEQUEN CE
OF [[]]

EVENTSUnitTimeSeconds fromEvent InitiationEvent114:01:45.4480.000Fault occurs on the X-phase Current Transformer(CT) of Power Circuit Breaker (PCB) 18114:01:45.4650.017Unit 1 Zone A protective lockout actuates (due totransformer 1A differential) to trip PCB's 17 and 18

and Generator Circuit Breaker (GCB) 1ADifferential protective relaying actuates to clear theRed and Yellow busses (PCB 12 operation in

response cannot be confirmed)214:01:45.4910.043Unit 2 Zone B protective lockout actuates (due totransformer 2B differential) to trip PCB's 23, 24

and

GCB 2B214:01:46.0680.620Line distance relaying on the Roddey transmissionline actuates to trip the remote line breaker and

PCB 20, serving to isolate Unit 2 from all offsite

power214:01:45.5101.062Unit 2 reactor trip occurs due to underfrequencyconditions on the reactor coolant pump electrical

busses. The reactor protection system (RPS)

generates a P4 protection signal which trips the

main turbine214:01:46.5531.105Unit

2 GCB 2B is tripped by the sequentialprotective tripping logic. Vital 4.16kV bus 2

ETB

loses power and activates the blackout logic which

sends a start signal to the 2B diesel generator114:01:48.1722.724Overcurrent conditions at the Newport Tie Stationactuate a remote breaker trip, serving to isolate

Unit 1 from all offsite power114:01:49.3943.946Unit 1 reactor trip occurs due to receipt of a "NI HiFlux Rate - Power Range" signal. The cause of

this signal has been attributed to an electrical

perturbation on the instrument bus resulting from

the large fault in the switchyard and not from an

actual change in reactor power significant enough

to have produced a valid flux rate trip signal.

2Attachment

8ELECTR ICAL
PLANT [[]]
SEQUEN CE
OF [[]]
EVENTS (continued)UnitTimeSeconds fromEvent InitiationEvent1 / 214:01:49.5814.133The
RPS generates a P4 protection signal whichtrips the main turbine. Vital 4.16kV busses 1
ETA ,
1ETB and 2

ETA lose power and the blackout logic

is activated which sends a start signal to the

respective diesel generators214:01:55.61010.162The 2B diesel generator receives a start signal andbegins to come up to speed in preparation for re-

energizing the vital busses114:02:04.09418.646Bus underfrequency conditions result in relayactuation to trip

PCB 14114:02:04.61019.162Unit 1

GCB 1A is tripped by the sequentialprotective tripping logic114:02:04.61019.162The 1A and 1B diesel generators receive startsignals and begin to come up to speed in

preparation for re-energizing the vital busses214:02:13.82028.372The 2A diesel generator receives a start signal andbegins to come up to speed in preparation for re-

energizing the vital busses1 / 2The load sequencers on all four (4) dieselgenerators initiate per design to energize the

necessary blackout loads in the prescribed

sequence ensuring the diesel generators are not

overloaded. Under the blackout loading, Load

Groups 1, 2, 3, 6, 7, 8, 9, 10, 11 and 12 are

automatically re-energized by the diesel

generators. Equipment in Load Group 13 is given

a manual start permissive 11 minutes and 50

seconds following sequencer initiation.1 / 2All blackout loads are successfully re-energizedvia the diesel generators.

3Attachment

9EMERGE NCY RESPONSE ORGANIZATION SEQUENCE
OF [[]]
EVENTS The following table provides a summary of the actions taken by the Catawba EmergencyResponse Organization following the
LOOP event of May 20, 2006.May 20, 2006

TIMECOMMENTDESCRIPTION1401Event StartsFault in the 230kV switchyard results in the loss ofoffsite power to both Catawba units and dual reactor

trips from 100% power. All four emergency diesel

generators start and re-energize the 4.16kV vital

busses as designed.1413Emergency ResponseOrganization (ERO)Pager messagePagers set off to alert

ERO to activate
TSC and OSCfor
LOOP event1414Notice of Unusual Event is declared based on the lossof all

AC power from offsite sources for more than 15

minutes with onsite power available. (Sent from the

Control Room)1421Group call made to notify 4 of 5 state/local emergencymanagement agencies. York County not available on

selective signal call group.1430- - - - -Site Assembly initiated

1458York County notified by commercial telephone line

1532- - - - -Site Assembly completed, all personnel accounted for

1535Message #2Event update provided to 4 of 5 state/local emergencymanagement agencies by selective signal call group.

York County notified by commercial telephone line. 1550- - - - -Technical Support Center (TSC) and OperationsSupport Center (OSC) activated 1615- - - - - The

NRC Operations Center was notified of the eventby

TSC staff 61 minutes late. The one hour

notification was not made as required by the Control

Room Offsite Agency Communicator.1626Message #3Event update provided to State and local agencies(Sent from the TSC)1717Message #4Event update provided to State and local agencies(Sent from the TSC)

2Attachment 91810Message #5Event update provided to State and local agencies(Sent from the

TSC )May 20, 2006 (continued)TIMECOMMENTDESCRIPTION1819- - - - -Emergency Operations Facility (EOF) activated at therequest of the
TSC Emergency Coordinator. The

EOF

provided support to the site by assuming the

responsibility of conducting offsite agency

communications and performing dose projections.1858Message #6Event update provided to State and local agencies(Sent from the EOF)1949Message #7Event update provided to State and local agencies(Sent from the EOF)2041Message #8Event update provided to State and local agencies(Sent from the EOF). Offsite power restoration in

progress. Message content "Offsite power partiallyrestored to Unit 2 at 2027

"2054Message #9Event update provided to State and local agencies(Sent from the EOF). Message content "Offsite powerrestoration in progress. Offsite power partially restored

to both Unit 1 and Unit 2.

"2148Message #10Event update provided to State and local agencies(Sent from the EOF). Message content "Power restoration to plant

systems in progress

."2246Message #11Event update provided to State and local agencies(Sent from the EOF). Message content "Power andequipment restoration continues. Commencing

cooldown to comply with facility Technical

Specifications

."2339Message #12Event update provided to State and local agencies(Sent from the EOF). Message content "Power andequipment restoration continues. Cooldown on both

units in progress to comply with facility Technical

Specifications

."

3Attachment 9May 21, 2006TIMECOMMENTDESCRIPTION0033Message #13Event update provided to State and local agencies(Sent from the EOF). Message content "Equipmentand power restoration continues. Power has been

restored to 3 of 4 essential busses. Cooldown

continues on both units to comply with facility

Technical Specifications.

"0123Message #14Event update provided to State and local agencies(Sent from the EOF). Message content "Cooldown nolonger necessary and temperatures are being

maintained steady. Power has now been restored to

all 4 essential busses from offsite sources

."0145Message #15Event update provided to State and local agencies(Sent from the EOF). Message content "Power hasbeen restored to all essential busses. Plant conditions

are stable. Unusual Event has been terminated

."

10INTEGR ATED
PLANT [[]]
SEQUEN CE
OF [[]]

EVENTSCatawba Unit 1TIMEEVENT DESCRIPTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red

busses and a 1A Zone lockout.14:01:49The first-out annunciator was "NI Hi Flux Rate - Power Range"; however, areview of reactor power traces do not show any valid increase or change in

reactor power at this time (NOTE: The licensee is reviewing data to determine

the cause of this signal). Both reactor trip breakers open and control rods insert.

The main turbine trips on receipt of the reactor trip signal.14:02:13Diesel generators 1A and 1B start and re-energize the

1ETA and 1

ETB 4.16kVemergency busses as designed.14:02:30Both main feedwater pumps trip on Lo-Lo suction pressure as a result of the lossof the hotwell and condensate booster pumps. The auxiliary feedwater pumps

(two motor-driven and one turbine-driven) start automatically and provide

inventory makeup to the steam generators.14:07:34Letdown isolation occurs when pressurizer level reaches 17%. Excess letdowncould not be established due to the failure of the excess letdown control valve to

open on demand. Normal letdown was subsequently re-established through the

fixed orifice line due to the variable orifice control valve failing closed following

the LOOP and not re-opening.14:08:02Main Steam Isolation signal is received when the 1C steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitions to the

steam generator PORV's.14:12Intermediate Range nuclear instrumentation drops below 1E-10 amps (P6setpoint).14:14Operations Shift Manager declared a Notice of Unusual Event (EmergencyAction Level 4.5.U.1, "AC electrical power from all offsite sources has been lost

for more than 15 minutes with onsite power available") due to the dual unit loss

of offsite power. Emergency Response Organization page sent to activate the

Technical Support Center (TSC) and Operations Support Center (OSC) (See

Emergency Event Notification timeline for details on the licensee's response to

the event).

2Attachment 1014:22Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), two of three pressurizer PORV's begin to cycle to

control primary system pressure. (See section 4OA5.4 for details on the

pressurizer PORV lifts). No pressurizer safety valves opened during the event.14:55Normal letdown is restored through the fixed orifice line.

20:34Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through

the use of auxiliary feedwater and steam generator PORV's.20:40Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress toenergize the 4.16kV vital busses from offsite power and secure the diesel

generators.21:55Final pressurizer

PORV actuation. Total number of actuations during event on
PORV 1NC-34A was 57 cycles and on
PORV 1

NC-32B, five cycles.23:034.16kV vital bus 1ETB is aligned to offsite power.

23:061B diesel generator output breaker is opened. Actions initiated to secure the 1Bdiesel generator and place it in stand-by.May 21, 200601:114.16kV vital bus

1ETA is aligned to offsite power. Due to the 1A Zone lockout,power is being supplied from the Unit 2 A

SAT using procedural guidance to

establish the required alignment.01:141A diesel generator output breaker is opened. Actions initiated to secure the 1Adiesel generator and place it in stand-by.01:40Notice of Unusual Event is terminated following restoration of offsite power to allunit busses.15:17The 1B reactor coolant pump is placed in service restoring forced circulation inthe primary system and providing normal pressurizer sprays for pressure control

if required. Primary system is stabilized at 475 F and 1850 psig in Mode 3.

3Attachment 10May 22, 200606:03The 1B reactor coolant pump motor stator winding temperatures increase to295°F requiring the pump to be secured. The 1A reactor coolant pump is

started.08:35Stator winding temperatures on the 1A reactor coolant pump motor increase andapproach the 300°F operating limit. The pump is secured and the decision made

to cool down to Mode 5 using natural circulation in order to place residual heatremoval in service. (NOTE: The elevated temperatures were determined to have

been caused by biological debris being swept into the motor coolers when the

source of cooling water swapped from the normal containment chilled water

system to the backup nuclear service water system on the loss of offsite power).08:49Briefing conducted to initiate a natural circulation Cooldown to Mode 5.

16:07Unit 1 enters Mode 4May 23, 200609:09Unit 1 enters Mode 5---------The unit is stabilized at 170°F and 295 psig in Mode 5. The A train of residualheat removal is placed in-service for decay heat removal. The B train is placed

in-service at 21:17. Repair and recovery actions are initiated.

10CATAWB A
UNIT 2

TIMEEVENT DESCRIPTIONMay 20, 200614:01:45An internal fault occurred in a current transformer associated with power circuitbreaker (PCB) 18. This fault resulted in a loss of the 230 kV Yellow and Red

busses and a 2B Zone lockout.14:01:46The first-out annunciator is "Under Frequency Conditions on the Reactor CoolantPump Busses" as sensed by the reactor coolant pump monitoring circuit. Both

reactor trip breakers open and control rods insert. The main turbine trips on

receipt of the reactor trip signal.14:02Diesel generators 2A and 2B start and re-energize the

2ETA and 2

ETB 4.16kVemergency busses as designed.14:02Both main feedwater pumps trip on Lo-Lo suction pressure as a result of the lossof the hotwell and condensate booster pumps. The auxiliary feedwater pumps

(two motor-driven and one turbine-driven) start automatically and provide

inventory makeup to the steam generators.14:08:05Letdown isolation occurs when pressurizer level reaches 17%. Excess letdownis placed in service. Normal letdown was subsequently re-established.14:08:21Main Steam Isolation signal is received when the 2A steam generator pressurereached 775 psig on 2/3 channels. Secondary pressure control transitioned to

the steam generator PORV's.14:27Due to the loss of pressurizer spray (no forced circulation following the loss ofthe reactor coolant pumps), one of three pressurizer PORV's begins to cycle to

control primary system pressure. (See section 4OA5.4 for details on the

pressurizer

PORV lifts). No pressurizer safety valves opened during the event.14:13Intermediate Range nuclear instrumentation drops below 1E-10 amps (P6setpoint).14:14Operations Shift Manager declares a Notice of Unusual Event (EmergencyAction Level 4.5.U.1, "

AC electrical power from all offsite sources has been lost

for more than 15 minutes with onsite power available") due to the dual unit loss

of offsite power. Emergency Response Organization page is sent to activate the

Technical Support Center (TSC) and Operations Support Center (OSC). (See

Emergency Event Notification timeline for details on the licensee's response to

the event)18:10Final pressurizer

PORV actuation. Total number of actuations during event on

PORV 2NC-34A was 35 cycles.

2Attachment 10----------Unit is stabilized on natural circulation using emergency, abnormal and normaloperating procedures. Primary system parameters are being controlled through

the use of auxiliary feedwater and steam generator PORV's.20:27Offsite power is restored to the 6.9kV non-vital busses. Work is in-progress tore-energize the 4.16kV vital busses from offsite power and secure the diesel

generators.23:314.16kV vital bus 2ETA is aligned to offsite power.

23:362A diesel generator output breaker is opened. Actions initiated to secure the 2Adiesel generator and place it in stand-by.23:534.16kV vital bus

2ETB is aligned to offsite power. Due to the 2B Zone lockout,power is being supplied from the Unit 1 B

SAT using procedural May 21, 200623:572B diesel generator output breaker is opened. Actions initiated to secure the 2Bdiesel generator and place it in stand-by.01:40Notice of Unusual Event terminated following restoration of offsite power to allunit busses.11:06The 2B reactor coolant pump was placed in service restoring forced circulation inthe primary system and providing normal pressurizer sprays for pressure control

if required. Exited Natural Circulation

EP and transitioned to

OP/2/A/6100/002;

Controlling Procedure for Unit Shutdown12:00The unit was stabilized at 460 F and 1900 psig in Mode 3. Recovery actions areinitiated.May 22, 200611:00Vacuum is reestablished in the main condenser allowing secondary pressurecontrol to be transferred from the steam generator PORV's to the steam dumps

and conserve inventory required to feed the steam generators.

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