ML102020020
| ML102020020 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/20/2010 |
| From: | Bartley J NRC/RGN-II/DRP/RPB1 |
| To: | Baxter D Duke Energy Carolinas |
| References | |
| Download: ML102020020 (66) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257 July 20, 2010 Mr. David A. Baxter Site Vice President Duke Energy Carolinas, LLC Oconee Nuclear Station 7800 Rochester Highway Seneca, SC 29672
SUBJECT:
PUBLIC MEETING
SUMMARY
- OCONEE NUCLEAR STATION - DOCKET NOS. 50-269, 50-270, AND 50-287
Dear Mr. Baxter:
This refers to the Category 1 public meeting which was held on July 13, 2010, in Atlanta, GA.
The purpose of this meeting was to discuss the safety significance of two preliminary greater than Green findings with two associated Apparent Violations (AV) and the severity level of one AV considered for potential Escalated Enforcement that were documented in NRC Inspection Report 05000269,05000270,05000287/2010007. A listing of meeting attendees and information presented during the meeting are enclosed.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter will be available electronically for public inspection in the NRC Public Document Room (PDR) or from the Publicly Available Records (PARS) component of NRCs 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).
Should you have any questions concerning this meeting, please contact me at (404) 997-4607.
Sincerely,
/RA/
Jonathan H. Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-269, 50-270, 50-287 License Nos.: DPR-38, DPR-47, DPR-55
Enclosures:
- 1. List of Attendees
- 2. Summary of Violations
- 3. Duke Energy Carolinas Presentation cc w/encls: (See page 2)
G SUNSI REVIEW COMPLETE OFFICE RII:DRP RII:DRP SIGNATURE JHB /RA for/
JHB /RA/
NAME EStamm JBartley DATE 7/ /2010 7/ /2010 7/ /2010 7/ /2010 7/ /2010 7/ /2010 7/ /2010 E-MAIL COPY?
YES NO YES NO YES NO YES NO YES NO YES NO YES NO
DEC 2
cc w/encl:
David A. Baxter Site Vice President Oconee Nuclear Station Duke Energy Carolinas, LLC Electronic Mail Distribution Kent Alter Regulatory Compliance Manager Oconee Nuclear Station Duke Energy Carolinas, LLC Electronic Mail Distribution J. W. (Bill) Pitesa Senior Vice President Nuclear Operations Duke Energy Carolinas, LLC Electronic Mail Distribution Scott L. Batson Engineering Manager Oconee Nuclear Station Duke Energy Carolinas, LLC Electronic Mail Distribution Philip J. Culbertson Oconee Nuclear Station Duke Energy Carolinas, LLC Electronic Mail Distribution Preston Gillespie Station Manager Oconee Nuclear Station Duke Energy Carolinas, LLC Electronic Mail Distribution R. L. Gill, Jr.
Manager Nuclear Regulatory Issues & Industry Affairs Duke Energy Carolinas, LLC Electronic Mail Distribution Dhiaa M. Jamil Group Executive and Chief Nuclear Officer Duke Energy Carolinas, LLC Electronic Mail Distribution David A. Repka Winston Strawn LLP Electronic Mail Distribution Kathryn B. Nolan Senior Counsel Duke Energy Corporation 526 South Church Street-EC07H Charlotte, NC 28202 Charles Brinkman Director Washington Operations Westinghouse Electric Company, LLC Electronic Mail Distribution County Supervisor of Oconee County 415 S. Pine Street Walhalla, SC 29691-2145 Mark Yeager Division of Radioactive Waste Mgmt.
S.C. Department of Health and Environmental Control Electronic Mail Distribution Lara Nichols Associate General Counsel Duke Energy Corporation Electronic Mail Distribution Susan E. Jenkins Director, Division of Waste Management Bureau of Land and Waste Management S.C. Department of Health and Environmental Control Electronic Mail Distribution W. Lee Cox, III Section Chief Radiation Protection Section N.C. Department of Environmental Commerce & Natural Resources Electronic Mail Distribution Jim Kammer RES Manager Duke Energy Carolinas, LLC Electronic Mail Distribution Paul Fisk MCE Manager Duke Energy Carolinas, LLC Electronic Mail Distribution
TVA 3
Letter to David A. Baxter from Jonathan H. Bartley dated July 20, 2010
SUBJECT:
OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000269/2010, 05000270/2010 AND 05000287/2010 Distribution w/encl:
C. Evans, RII EICS (Part 72 Only)
L. Slack, RII EICS (Linda Slack)
OE Mail (email address if applicable)
RIDSNRRDIRS PUBLIC RidsNrrPMOconee Resource
2
OCONEE REGULATORY AND PREDECISIONAL ENFORCEMENT CONFERENCE July 13, 2010
[SSF Letdown Filter]
2 Apparent Violation #1 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, deficiencies, and defective material are promptly identified and corrected.
Contrary to the above, from October 19, 2009, to February 20, 2010, (Unit 2) and February 23, 2010, (Unit 3) the licensee failed to promptly identify and correct a condition adverse to quality involving foreign material on the Unit 2 and 3 SSF letdown line filters. In this case, after identification of a condition adverse to quality on Unit 1, the licensee failed to identify and correct a similar condition adverse to quality on Unit 2 and Unit 3. The condition would have adversely affected the operators ability to control reactor coolant system inventory during a postulated event involving the use of the Standby Shutdown Facility.
3 Apparent Violation #2 Technical Specification 3.10.1 required the SSF to be operable in Modes 1, 2 and 3 and Condition C allowed the RCM subsystem to be inoperable for up to seven days without additional actions being taken.
Contrary to the above, the SSF RCM system was inoperable whenever the unit was in Modes 1, 2, or 3 from May 30, 2008, until October 9, 2009, for Unit 1; from December 10, 2008, until February 20, 2010, for Unit 2; and from May 19, 2009, until February 23, 2010, for Unit 3 because the letdown line could not pass the required flow.
4 Apparent Violation #3 10 CFR 50.9(a) requires, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects.
Contrary to the above, on December 18, 2009, the licensee provided information to the NRC that was not complete and accurate in all material respects. The information provided described compensatory actions for controlling pressurizer level during an SSF event which was not available due to a closed manual valve inside containment. This information, combined with an evaluation that showed flow rates on Unit 2 and Unit 3 were greater than the required value for level control in the last as-tested condition, was material to the NRC because it was used, in part, as the basis for determining whether the licensees response to the degraded condition was adequate and whether additional compensatory actions or NRC review would be necessary.
OCONEE REGULATORY AND PREDECISIONAL ENFORCEMENT CONFERENCE July 13, 2010
[SSF Letdown Filter]
2 1
Foreign Material Found in the Standby Shutdown Facility (SSF)
Letdown Line Strainer for Units 1, 2, and 3 NRC Region II Office Atlanta, Georgia July 13, 2010 Oconee Nuclear Station Regulatory Conference
3 2
Duke Participants
Bill Pitesa, Senior Vice President, Nuclear Operations
Dave Baxter, Oconee Site Vice President
Preston Gillespie, Oconee Station Manager
Scott Batson, Oconee Engineering Manager
Jim Kammer, Oconee RES Engineering Manager
Paul Fisk, Oconee MCE Engineering Manager
Steve Nader, NGO PRA Engineering Supervisor
Chris Nolan, NGO Licensing Manager
4 3
Agenda
Opening Remarks D. Baxter
SSF Letdown Line Overview S. Batson
Timeline J. Kammer
Testing Overview P. Fisk
SDP Highlights and Results S. Nader
Regulatory Perspectives C. Nolan
Cause Analysis and Corrective Actions P. Fisk / Jim Kammer
Closing Remarks D. Baxter / B. Pitesa
5 4
Opening Remarks The SSF performs an important safety function with a high risk worth NRC staff played a key role in recognizing the common mode vulnerability of this issue Oconee will present its cause analysis and corrective actions Oconee will present insights from its fire PRA which was submitted to NRC for Oconees NFPA 805 amendment request Oconee agrees with NRCs characterization:
3/4 Apparent violation of 10 CFR 50.9 3/4 Apparent violation of Appendix B, Criteria XVI 3/4 Apparent violation of Technical Specifications
6 5
Opening Remarks - cont.
NRC proposed two findings to address letdown line degradation:
A current performance issue that is forward looking from discovery A legacy issue with the original design that is a look back Oconee proposes a combined performance deficiency to address both perspectives reflective of this single event 3/4 Failure to promptly identify and correct a degraded condition in the SSF RCM letdown line for Units 1, 2, & 3 Aligns regulatory focus, significance, and inspection The maximum exposure time would be applied to each unit (1 year)
Avoids the appearance of double counting
7 SSF Letdown Line Overview 6
Scott Batson, Engineer Manager, Oconee Nuclear Station
8 SSF Letdown Line Overview:
System Flow Diagram 7
9 8
SSF Letdown Line Overview:
Timeline
SSF RC Letdown Line Orifice Strainer history 3/4 ~ 1982:
Original installation of letdown line orifice / strainer 3/4 ~ 1994/95: Orifice determined to be under-sized; new orifice installed 3/4 ~ 1996/97: Flow test performed on all units, passed
Recent testing of SSF RC Letdown Line 3/4 02/2007:
Unit 3 RBES legacy foreign material finding 3/4 10/2008:
Unit 2 SSF RC letdown line flow test passed 3/4 04/2009:
Unit 3 SSF RC letdown line flow test passed 3/4 10/2009:
Unit 1 SSF RC letdown line flow test failed, root cause evaluation conducted, strainer removed correcting condition
10 SSF Letdown Line Overview:
Cause Analysis
Oconee approach to cause analysis
Fleet approach 3/4 Each site reviews other site root causes and corrective actions to prevent recurrence; expectation is fleet consistency for these actions 3/4 Nuclear System & other lower tier directives apply fleet wide 9
Issue Cause Analysis Inaccurate material information provided to NRC PIP 10-0561 Apparent Cause Analysis completed 3/24/10 SSF RC Letdown Line inoperable due to foreign material 09-7536 Root Cause Analysis Rev. 0 completed 12/03/09 Rev. 1 completed 04/8/10 Inadequate corrective actions from October 2009 to 23 February 2010 10-1213 Root Cause Analysis Includes additional organizational &
programmatic issues related to inaccurate material information provided to NRC
11 Timeline 10 Jim Kammer, Reactor & Electrical Systems Engineer Manager
12 Timeline
02/13/07:
RBES White Finding
06/27/08:
Decision to use SSF letdown line flow path verification test method to address RBES White Finding
10/11/09:
Unit 1 flow test was performed and failed
10/19/09:
Debris found in orifice strainer
10/23/09 1HP-426 disassembled, backseat gasket missing
10/27/09:
Archived data used to generate flow information from prior tests and compared to expected results
10/27/09:
Flowserve indicated no previous reports of problems with backseat gasket or material 11
13 Timeline
11/10/09:
Three spare valves examined and backseat gaskets found in place
11/20/09:
ONS concluded that the performance issue was isolated to Unit 1
11/23/09:
Strainer proof of concept/methodology performed using a positive displacement pump - strainer deformation observed
12/03/09:
Site CARB approves Root Cause Rev 0 (09-7536)
12/18/09:
Additional analyses re-affirmed adequate flow for Units 2 and 3 and recognized Unit 2 had less margin than originally estimated 12
14 Timeline
~ 01/18/10:
Regulatory Impact Team reviewed flow analysis and questioned the reduced margin for Unit 2 and the lack of a PIP
01/25/10:
PIP 10-0494 written documenting less margin than expected on Unit 2
01/25/10:
Operations concurred with Immediate Determination of Operability (Re-affirmed 2/8/10)
02/17/10:
Operations concurred with Prompt Determination of Operability
02/18/10:
NRC asks Operations questions related to operability including: Could strainer deform under expected dP, and what would be the impact on flow?
13
15 Timeline
02/18/10:
Operations requests Engineering assistance to address NRC questions
02/18/10:
Unit 2 SSF Letdown Line declared Inoperable
02/20/10:
Unit 2 power reduced to 20% to remove the SSF LD line orifice strainer
02/21/10:
PIP 10-1203 written to assess impact on Unit 3 of new data from Unit 2
02/23/10:
Unit 3 power reduced to 20% to remove the SSF LD line orifice strainer
03/10 -05/10: Offsite testing conducted at Alden Research Laboratory, Inc.
14
16 Testing Overview 15 Paul Fisk, Mechanical & Civil Systems Engineer Manager
17 Testing Overview:
Problem Identification Unit 1 blockage detected while performing flow test to address Unit 3 RBES Foreign Material corrective actions (October 2009) 3/4 RCS conditions held stable in Mode 5 3/4 Flow established from HPI Letdown, through 1HP-426 and pressure reduction orifice, to Spent Fuel Pool 3/4 Acceptance criteria: 3 inch decrease in Pressurizer level in 15 minutes Unit 2 and Unit 3 tested (Fall 2008 / Spring 2009)
Unit 1 result was no appreciable Pressurizer level change 16
18 Testing Overview:
Problem Identification
Subsequent inspection found debris in pipe and orifice strainer screen downstream of valve, 1HP-426
Debris identified by Met Lab as mixture of legacy and graphite materials 17 Top View Unit 1 orifice strainer Side View Unit 1 orifice strainer
19 Testing Overview:
Problem Identification
Graphite material found to be from upstream valve, 1HP-426
Valve backseat insert gasket (Grafoil) had become dislodged and flowed to strainer 18 1HP-426 valve internals Backseat Gasket Cross-section Sketch
20 Testing Overview:
Problem Identification Similar failure mode subsequently identified in Unit 2 and Unit 3 systems 19 Unit 1 Material Unit 2 Material Unit 3 Material Larger Grafoil Strips & Shreds
~20 mils thick by 1/8-inch wide and up to 1/2-inch in length Grafoil Material Most of the Grafoil particles consisted of very fine flakes Grafoil Material Five pieces up to 0.3-inch Discrete, irregular chunks of plastic material (epoxy)
Alumina Abrasive Paint Chips Finer mixed particulate consisting of above materials and fine metal shavings Stainless Steel Shavings Rust Flakes Fine Fibers Mixture of Very Fine Particulate
21 Testing Overview:
Offsite Testing
Used to determine flow rates at full system pressure for as-found conditions
Resulted in the following significant observations:
3/4 Grafoil material in the amount of one gasket is sufficient to deform the strainer and reduce flow less than acceptance criteria 3/4 Strainer deformation does not result in complete flow blockage 3/4 Legacy material only slightly reduces flow (meets acceptance criteria) 3/4 Strainer deformation does not occur under legacy material loading
With entire Grafoil backseat gasket captured by orifice strainer.
3/4 Strainer deformation expected with flow reduction, not complete blockage 3/4 Flow reduction not adequate to perform design function.
Design function would be satisfied with legacy material alone (i.e. - no Grafoil) 20
22 SDP Highlights and Results 21 Steve Nader, NGO PRA Engineering Supervisor
23 SDP Highlights:
NRC Risk Significance NRCs June 9, 2010, letter provided lower bound for risk 3/4 Risk analyses associated with fire are not finalized Oconee aligns with NRCs assessment in the following areas:
Overall approach Internal Events risk HELB risk Internal Flood risk Seismic risk Tornado risk Operator Action 22
24 23 SDP Highlights:
Fire Modeling and NFPA 805 Fire Risk - still under development 3/4 On-going discussions between Oconee and NRC PRA experts 3/4 Fire risk will likely drive final significance determination 3/4 Objective of SDP is to achieve a best estimate assessment of risk 3/4 Therefore, fire risk should be a best estimate value Oconee is a pilot for NFPA 805 (LAR submitted 4/14/10) 3/4 We have a detailed Fire PRA model 3/4 Good tool to evaluate this kind of scenario 3/4 However, pilot experience has shown that NUREG 6850 does not provide best estimate results
25 24 SDP Highlights:
Fire Model Background
NUREG 6850 provides fire frequencies Pilots (Oconee, Harris) saw the need to develop refinements 3/4 Deviations were peer reviewed Other industry efforts also underway to refine NUREG 6850 3/4 EPRI published TR-1016735 (NRC approved limited use per FAQ 08-048) 3/4 PWROG working on improving details of past fire events to allow more accurate estimation of fire frequencies 3/4 NEI has presented information showing NUREG 6850 results in over estimation of fires in low voltage electrical cabinets by 10x compared to actual operating experience 3/4 ACRS has recommended refinement of NUREG 6850
26 25 SDP Highlights:
Key Fire Model Inputs Low Voltage Electrical Cabinets 3/4 Cabinets could have a fire that propagates to adjacent cables resulting in loss of redundant functions - SBO 3/4 NUREG 6850 methodology Does not differentiate between high and low voltage cabinets Assumes most multi-cable bundle cabinet fires propagate to low (3 to 4) overhead cables; not conducive to scenario refinement Per NEI, this methodology predicts the industry should have had ~ 130 severe fires in these types of cabinets Only 13 in the industry data base 3/4 Oconee approach Different treatment for low and high voltage cabinets Different treatment for sealed vs. ventilated cabinets
27 SDP Highlights:
Key Fire Model Inputs Electrical Cabinet Fires (Oconee approach - cont) 3/4 Sealed Cabinets Well sealed cabinets do not propagate Poorly ventilated (leaky) cabinets exhibit similar fire behavior Internal cabinet failures include concurrent spurious 3/4 Ventilated Cabinets Severity Factor applied NUREG 6850 heat release rate (HRR) distribution profiles used for a broad range of applications (load centers, switchgear, etc.)
Oconee applied an empirically based factor for low voltage cabinets 26
28 27 SDP Highlights:
Key Fire Model Inputs
Cabinets with wireways 3/4 Adjacent cabinets with wireways in the walls to allow cables to pass between cabinets 3/4 Oconees best estimate approach assumes fires do not propagate between cabinets nor to adjacent equipment Based on limited openings, and therefore limited oxygen source No PVC material inside cabinet to challenge penetrations 3/4 If propagation is assumed (severe fires)
FAQ on super cabinets provides an alternate way to count the cabinets and apply the proper fire frequency Timing should be considered, credit for fire brigade
29 28 SDP Highlights:
Key Fire Model Inputs Bus Ducts:
3/4 NUREG 6850 methodology has been a topic of industry discussion 3/4 EPRI has calculated new frequencies (older data receives less weight) 3/4 One plant experienced 3 of the 7 events 3/4 Should be plant specific (Bayesian update)
Dukes opinion is that:
3/4 Oconee bus ducts are robust 3/4 Thickness of enclosure offers better containment relative to sheet metal 3/4 Circular construction provides better protection 3/4 Armored cables are less vulnerable targets (galvanized steel)
30 29 SDP Highlights:
Key Fire Model Inputs Loss of Normal Letdown Scenarios 3/4 Fire could cause a loss of normal letdown and the auto-alignment to BWST Could result in the loss of key safety pumps (no suction path) 3/4 Oconee emergency procedures provide multiple options Refill Letdown Storage Tank, or Align Low Pressure pumps to BWST and use piggy back mode Both of these strategies ensure a continuous suction path
31 SDP Results:
Treatment of Event Exposure Time Risk results are calculated on a per year basis 3/4 Adjusted to match actual event duration Current risk analysis 3/4 Unit 1:
12 months 3/4 Units 2/3: 12 months
+ ~4 months Proposed 3/4 Units 1/2/3: 12 months 30
32 SDP Results:
Conclusions SDP Risk Significance 3/4 Total delta CDF ~ 8.0E-06/yr [Draft] (based on one year duration)
NUREG/CR-6850 does not provide best estimate results for this application Observations regarding NRCs proposed action 3/4 Units 2 & 3 assessed 16 months of cumulative exposure time 31
33 Regulatory Perspectives 32 Chris Nolan, NGO Licensing Manager
34 Regulatory Perspectives:
Apparent Violation of 10 CFR 50.9 Oconees action plan for the SSF letdown line issue was provided to NRC on 12/18/2009 3/4 Identified Oconees intention to remove the Unit 2 and Unit 3 orifice strainers in the event of a forced outage to Mode 3 3/4 Identified three alternate methods to provide pressurizer level control including:
TSC directed action to utilize reactor coolant makeup pump (RCMUP) bypass line Flow path could be initiated within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> A closed manual valve inside containment precluded the use of this flow path 33
35 Regulatory Perspectives:
Apparent Violation of 10 CFR 50.9
12/18/09:
Action Plan White Paper provided to NRC
01/27/10:
Manual valve (2,3 HP-427) discovered closed 9 Discovered during engineering change process updating design basis documents for this event
01/27/10:
Immediately entered into corrective action program
01/27/10:
The NRC SRI was informed
01/28/10:
Containment entry made to open 2 HP-427
01/29/10:
Containment entry made to open 3 HP-427
01/29/10:
Compliance was restored
02/09/10:
Prompt corrective actions completed 34
36 Regulatory Perspectives:
Apparent Violation of 10 CFR 50.9 NSD-227, Communicating with the NRC was not followed NSD-227 is robust and the validation process required in NSD-227, if followed correctly, would have identified the inconsistency Corrective Actions Accountability for administrative procedure compliance reinforced Reinforcement of expectations regarding communications with NRC Compliance Manager written expectations to Regulatory Compliance Group on NSD 227 SA Manager conducted table top session with Regulatory Compliance Group Engineering continuing training lessons learned Catawba/McGuire Regulatory Compliance Group lessons learned Fleet wide communication by Senior VP 35
37 Regulatory Perspectives:
Apparent Violation of 10 CFR 50.9 Oconee agrees with the apparent violation (AV)
No aspects of willfulness were identified with the AV No traditional escalated enforcement activity within two years Oconee identified the violation and promptly informed the NRC Prompt & comprehensive corrective actions have been taken Oconee acknowledges that this violation could be assessed as a Severity Level III Based on our review of the Enforcement Policy, Oconee does not believe that a civil penalty is warranted 36
38 Regulatory Perspectives:
Current Performance Issue Expectations were not met regarding Oconees response to SSF letdown line degradation Apparent Violation of Appendix B, Criterion XVI 3/4 Oconee agrees with the performance deficiency for Units 2 & 3 3/4 This issue was reflective of current performance and foreseeable 3/4 This issue has a low to moderate risk significance 3/4 Oconee agrees with the cross-cutting aspect of H.1(b) 3/4 Oconee agrees with the apparent violation 3/4 Corrective actions taken to restore compliance 3/4 Comprehensive actions taken or planned to address extent of condition 37
39 Regulatory Perspectives:
Legacy Issue Apparent Violation of TS 3.10.1 3/4 Oconee agrees with the violation 3/4 Corrective actions taken to restore compliance 3/4 Comprehensive actions taken or planned for extent-of-condition Significance 3/4 This issue has a low to moderate risk significance 3/4 Oconee has offered its risk insights regarding the PRA analysis:
Treatment of low voltage cabinet fires Treatment of bus ducts Event exposure time This issue is not reflective of current performance 38
40 Regulatory Perspectives:
Legacy Issue Single performance deficiency to address the event:
3/4 Failure to promptly identify and correct a degraded condition for the Unit 1, 2, & 3 SSF RCMU letdown line 3/4 Valid performance deficiency that was reasonably foreseeable Untimely recognition of a new degradation mechanism as a common mode failure Missed opportunities to identify in 2008 & 2009 Addresses testing weaknesses in context of current performance 3/4 Characterizes the significance of the event and applies that significance to all three units (1 year of exposure time) 3/4 Apparent violations of Criterion XVI and TS 3.10.1 would apply 39
41 Regulatory Perspectives:
Legacy Issues Challenges with the Legacy Performance Deficiency 3/4 No regulatory requirement or licensee standard to test the line 3/4 This issue is not reflective of current performance Testing was a corrective action related to RBES FM 3/4 The letdown line failure was not reasonably foreseeable A new degradation mechanism impacted performance
- Vendor was not aware of mechanism (10 CFR 21 notification)
- Oconee shared operating experience with other utilities Non-Grafoil material insufficient to reduce flow below acceptable levels 3/4 Legacy issue should not be considered a valid performance deficiency 40
42 Regulatory Perspectives:
Summary Oconee propose a single performance deficiency to address RCMU letdown line flow degradation:
3/4 The finding would apply to all three units 3/4 Issue characterized with a low to moderate risk significance The maximum exposure time of 1 year would apply 3/4 Apparent violations of Criterion XVI and TS 3.10.1 would apply 3/4 Aligns the regulatory focus, significance, corrective actions, and inspection outcomes 3/4 Avoids the appearance of double counting Oconee plans to test the SSF letdown line on a refueling outage basis going forward 41
43 Cause Analysis & Corrective Actions Legacy Issue 42 Paul Fisk, Mechanical & Civil Systems Engineer Manager
44 Legacy Issue:
Cause Determination Initial root cause completed on 12/03/09 3/4 Root cause identified as valve vendor assembly error 3/4 Immediate corrective actions removed 1HP-426 backseat gasket and Unit 1 orifice strainer 3/4 Strainer removal and flow testing work orders written for Unit 2 and Unit 3 and added to forced outage lists Root cause reopened based on new information from Unit 2 & 3 strainer removal / inspections 3/4 Problem statement redefined as flow blockage on U1 and flow reduction on U2 3/4 Scope expanded to include deeper look at O&P factors 3/4 Extent of condition expanded beyond SSF subsystems 3/4 Extent of cause examined for all causes (root and contributing) 43
45 Legacy Issue:
Cause Determination Root Cause (from Revision 1, completed 4/8/10) 3/4 Improper strainer selection Contributing Causes 3/4 Inadequate testing 3/4 Untimely and ineffective Unit 3 Emergency Sump foreign material corrective actions 3/4 Inadequate design documentation 3/4 Valve manufacturing deficiency 3/4 Legacy foreign material 44
46 Legacy Issue:
Corrective Actions - Completed
Strainers removed from all units as of 2/24/10, resulting in full compliance with Tech Spec 3.10.1
Rigorous testing established
Extent of condition evaluated for all plant valves with similar backseat gasket design
SSF test matrices evaluated for weaknesses in light of lessons learned 45
47 Legacy Issue:
Corrective Actions - Completed
Solicited independent industry expert to evaluate effectiveness of root cause analysis and corrective actions 3/4 Overall conclusion was a rigorous, detailed and thorough cause analysis 3/4 Improvement recommendations captured in corrective action program
Reviewed outstanding U3 RBES event corrective actions for risk
Provided lessons-learned training to Engineering organization
Communicated to all site personnel involved in design changes and establishing test acceptance criteria 46
48 Legacy Issue:
Corrective Actions - Planned
Independent, non-ONS team to review adequacy of current SSF testing
Review and validate the adequacy of test matrix and test acceptance criteria for all MR high safety significant functions
Revise directives related to testing 47
49 Cause Analysis & Corrective Actions Current Performance Issue 48 Jim Kammer, Reactor & Electrical Systems Engineer Manager
50 Current Performance Issue:
Cause Analysis Oconee Root Cause Methodology Independent Contractor brought in to apply MORT methodology Status: Comment resolution in progress 49
51 Current Performance Issue:
Key Insights
Decision Making
Failed to ensure selected test method was adequate to provide the desired information.
Failed to validate quality (precision) of information
Corrective Action Program
Failed to initiate new PIPs when significant new information was received
Failed to adequately assess potential failure modes of equipment during Operability Determination Process.
Identified weaknesses in issue management
Inadequate oversight
Inadequate communications
Inadequate transition from outage emergent issue to other process 50
52 Current Performance Issue:
Corrective Actions Decision Making Accountability reinforcement Engineering Continuing Training Fleet communication on issue from Senior VP Now require Management Review Team process for each Prompt Determination of Operability Evaluate process changes to require Management Review Team for Prompt Determinations of Operability (Fleet)
Leadership Academy training on decision-making 51
53 Current Performance Issue:
Corrective Actions Corrective Action Program Accountability reinforcement Enhance guidance for new PIP threshold when already working within PIP Enhance Cause Analysis Process to identify situations that will require a formal FMEA Corrective Action Review Board Training Lessons Learned Root Cause Operability Extent of Condition/Extent of Cause 52
54 Current Performance Issue:
Corrective Actions Issue Management Accountability reinforcement Process enhancements Enhance issue management roles and responsibilities for the management lead in the areas of providing oversight, clear communications, coordination of hand-offs between processes.
Establish clear expectations for communications frequency and content with a focus on new information and its potential relationships to the issue under investigation.
Establish clear hand-off from outage emergent issue to other oversight process.
Fleet communication on issue from Senior VP 53
55 Closing Remarks 54 Dave Baxter, Site Vice President Bill Pitesa, Senior Vice President, Nuclear Operations
56 55 Closing Remarks
Oconees performance did not meet expectations
Oconee has described its cause analysis and corrective actions
Oconee agrees with the apparent violations of 10 CFR 50.9, Appendix B Criterion XVI, and TS 3.10.1 proposed by NRC
Oconee has offered its perspectives regarding risk
Proposal to combine performance deficiencies to reflect the legacy and current performance perspectives of a single event 3/4 Focuses on current performance issues that were foreseeable 3/4 Aligns regulatory focus, significance, corrective actions, and inspection outcomes 3/4 Equal treatment of units impacted by a common mode failure 3/4 Avoids the appearance of double counting