IR 05000280/2007003: Difference between revisions

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=Text=
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{{#Wiki_filter:July 30, 2007Virginia Electric and Power CompanyATTN:Mr. David Sr. Vice President and Chief Nuclear Officer Innsbrook Technical Center - 2SW 5000 Dominion Boulevard Glen Allen, VA 23060-6711SUBJECT:SURRY POWER STATION - INTEGRATED INSPECTION REPORT05000280/2007003 AND 05000281/2007003
{{#Wiki_filter:uly 30, 2007
 
==SUBJECT:==
SURRY POWER STATION - INTEGRATED INSPECTION REPORT 05000280/2007003 AND 05000281/2007003


==Dear Mr. Christian:==
==Dear Mr. Christian:==
On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atyour Surry Power Station. The enclosed report documents the inspection results which were discussed on July 17, 2007, with Mr. Sloane and members of your staff.The inspection examined activities conducted under your licenses as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, the NRC has identified two findings of very low safetysignificance (Green), which were determined to be violations of NRC requirements. However, because of the very low safety significance and because the issue was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV)
On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station. The enclosed report documents the inspection results which were discussed on July 17, 2007, with Mr. Sloane and members of your staff.
 
The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
 
Based on the results of this inspection, the NRC has identified two findings of very low safety significance (Green), which were determined to be violations of NRC requirements. However, because of the very low safety significance and because the issue was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV)
consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN:
consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Surry Power Station.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and any response will be available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's VEPCO2document system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Surry Power Station.
 
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and any response will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's
 
VEPCO  2 document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).


Sincerely,
Sincerely,
/RA/Eugene F. Guthrie, ChiefReactor Projects Branch 5 Division of Reactor ProjectsDocket Nos.:50-280, 50-281License Nos.:DPR-32, DPR-37
/RA/
Eugene F. Guthrie, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37


===Enclosure:===
===Enclosure:===
NRC Integrated Inspection Report 05000280/2007003 and 05000281/2007003 w/Attachment: Supplemental Information
NRC Integrated Inspection Report 05000280/2007003 and 05000281/2007003 w/Attachment: Supplemental Information


REGION IIDocket Nos.:50-280, 50-281License Nos.:DPR-32, DPR-37 Report No.:05000280/2007003, 05000281/2007003, Licensee:Virginia Electric and Power Company (VEPCO)
REGION II==
Facility:Surry Power Station, Units 1 & 2 Location:5850 Hog Island RoadSurry, VA 23883Dates:April 1, 2007 - June 30, 2007 Inspectors:G. McCoy, Senior Resident InspectorJ. Reece, Senior Resident Inspector E. Riggs, Acting Senior Resident Inspector D. Arnett, Resident Inspector R. Chou, Senior Reactor Inspector (Sections 1R02, 1R17)
Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37 Report No.: 05000280/2007003, 05000281/2007003, Licensee: Virginia Electric and Power Company (VEPCO)
Facility: Surry Power Station, Units 1 & 2 Location: 5850 Hog Island Road Surry, VA 23883 Dates: April 1, 2007 - June 30, 2007 Inspectors: G. McCoy, Senior Resident Inspector J. Reece, Senior Resident Inspector E. Riggs, Acting Senior Resident Inspector D. Arnett, Resident Inspector R. Chou, Senior Reactor Inspector (Sections 1R02, 1R17)
G. Gardner, Reactor Inspector (Sections 1R02, 1R17)
G. Gardner, Reactor Inspector (Sections 1R02, 1R17)
A. Issa, Reactor Inspector (Sections 1R02, 1R17)
A. Issa, Reactor Inspector (Sections 1R02, 1R17)
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D. Mas-Penaranda, Reactor Inspector (Sections 1R02, 1R17)
D. Mas-Penaranda, Reactor Inspector (Sections 1R02, 1R17)
L. Miller, Senior Emergency Preparedness Inspector (Section 4OA2.3)
L. Miller, Senior Emergency Preparedness Inspector (Section 4OA2.3)
J. Kreh, Emergency Preparedness Inspector (Section 4OA2.3)Approved by: E. Guthrie, Chief,Reactor Projects Branch 5 Division of Reactor Projects  
J. Kreh, Emergency Preparedness Inspector (Section 4OA2.3)
Approved by: E. Guthrie, Chief, Reactor Projects Branch 5 Division of Reactor Projects Enclosure


=SUMMARY OF FINDINGS=
=SUMMARY OF FINDINGS=
IR 05000280/2007003, 05000281/2007003; 04/01/07 - 06/30/07; Surry Power Station Units 1and 2; Other Activities and Permanent Plant Modifications.The report covered a three-month period of inspection by resident inspectors and announcedregional-based inspections conducted by five reactor inspectors and two emergency preparedness inspectors. Two Green findings, all of which were non-cited violations (NCVs),
IR 05000280/2007003, 05000281/2007003; 04/01/07 - 06/30/07; Surry Power Station Units 1 and 2; Other Activities and Permanent Plant Modifications.
 
The report covered a three-month period of inspection by resident inspectors and announced regional-based inspections conducted by five reactor inspectors and two emergency preparedness inspectors. Two Green findings, all of which were non-cited violations (NCVs),
were identified. The significance of the finding is indicated by the color (Green, White, Yellow,
were identified. The significance of the finding is indicated by the color (Green, White, Yellow,
Red) using IMC 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.
Red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.


The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.
The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.


===NRC-Identified and Self-Revealing Findings===
===NRC-Identified and Self-Revealing Findings===
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===Cornerstone: Initiating Events===
===Cornerstone: Initiating Events===
: '''Green.'''
: '''Green.'''
The inspectors identified a non-cited violation of 10 CFR 50.65 (a)(4), whichrequires that the licensee assess and manage the increase in risk that may result from the proposed maintenance activities. Specifically, in assessing the increase in risk of planned maintenance activities, the licensee failed to adequately assess planned risk.
The inspectors identified a non-cited violation of 10 CFR 50.65 (a)(4), which requires that the licensee assess and manage the increase in risk that may result from the proposed maintenance activities. Specifically, in assessing the increase in risk of planned maintenance activities, the licensee failed to adequately assess planned risk.
 
The licensee entered this issue in their corrective action program as CR-003611 for resolution.


The licensee entered this issue in their corrective action program as CR-003611 for resolution.The finding was considered to be more than minor because the licensee's riskassessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. The inspectors determined that the finding is of very low safety significance (Green) since the incremental core damage probability deficit was less than 1E-6. The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.
The finding was considered to be more than minor because the licensees risk assessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. The inspectors determined that the finding is of very low safety significance (Green) since the incremental core damage probability deficit was less than 1E-6. The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.


(Section 4OA5)
      (Section 4OA5)


===Cornerstone: Mitigating Systems===
===Cornerstone: Mitigating Systems===
: '''Green.'''
: '''Green.'''
The NRC identified a non-cited violation (NCV) for the failure to ensure thesuitability of application of equipment essential to the safety-related functions of structures, systems, and components (SSCs) through their commercial dedication process as required by 10 CFR Part 50, Appendix B, Criterion III, Design Control. The licensee entered each of the two examples identified by the team into their corrective actions program as CR-013984, including an action to review their overall commercial dedication program.The examples involve Agastat 7000 relays used in supporting the emergency dieselgenerator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensee's commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics. Both examples of the finding are more than minor because they are associated with theDesign Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The examples to the finding were evaluated using the SDP for Reactor Inspection Findings for At-Power Situations. The SDP Phase 1 analysis demonstrates the finding to be of very low safety significance (Green) as the licensee confirmed operability in accordance with plant procedures for both examples. The cause of the first example is related to the cross cutting aspect of human performance. (Section 1R17.2)
The NRC identified a non-cited violation (NCV) for the failure to ensure the suitability of application of equipment essential to the safety-related functions of structures, systems, and components (SSCs) through their commercial dedication process as required by 10 CFR Part 50, Appendix B, Criterion III, Design Control. The licensee entered each of the two examples identified by the team into their corrective actions program as CR-013984, including an action to review their overall commercial dedication program.
 
The examples involve Agastat 7000 relays used in supporting the emergency diesel generator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensees commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics. Both examples of the finding are more than minor because they are associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The examples to the finding were evaluated using the SDP for Reactor Inspection Findings for At-Power Situations. The SDP Phase 1 analysis demonstrates the finding to be of very low safety significance (Green) as the licensee confirmed operability in accordance with plant procedures for both examples. The cause of the first example is related to the cross cutting aspect of human performance. (Section 1R17.2)


===B.Licensee-Identified Violations===
===Licensee-Identified Violations===


None
None


=REPORT DETAILS=
=REPORT DETAILS=
Summary of Plant StatusUnit 1 began the report period operating at 100 percent rated thermal power (RTP). On May 30, the unit was down-powered to 88.6 percent until June 1, due to a malfunctioning Turbine Stop Valve. The unit operated at or near full RTP for the remainder of the report period.Unit 2 operated at or near full RTP for the entire reporting period.
 
===Summary of Plant Status===
 
Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On May 30, the unit was down-powered to 88.6 percent until June 1, due to a malfunctioning Turbine Stop Valve. The unit operated at or near full RTP for the remainder of the report period.
 
Unit 2 operated at or near full RTP for the entire reporting period.


==REACTOR SAFETY==
==REACTOR SAFETY==
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{{a|1R01}}
{{a|1R01}}
==1R01 Adverse Weather ProtectionHurricane Preparations==
==1R01 Adverse Weather Protection==
 
Hurricane Preparations


====a. Inspection Scope====
====a. Inspection Scope====
On June 11 and 27, 2007, inspectors conducted a tour of the owner-controlled area toevaluate the licensee's preparedness for high winds and hurricane conditions well in advance of the approach of any hurricanes. Specifically, the inspectors toured the following areas: Service and Auxiliary Building rooftop, the low level intake, the construction buildings, the sewage treatment plant, the area outside the warehouse, and the area surrounding the Gravel Neck gas turbines. The tour emphasized the identification of loose material, which could become airborne and potentially damage structures, systems, components (SSCs) or the switchyard. The inspectors also reviewed Operations Checklist OC-21 "Severe Weather Checklist", Abnormal Procedure (AP) 37.01 "Abnormal Environmental Conditions", and the Dominion Hurricane Response Plan (Nuclear).
On June 11 and 27, 2007, inspectors conducted a tour of the owner-controlled area to evaluate the licensees preparedness for high winds and hurricane conditions well in advance of the approach of any hurricanes. Specifically, the inspectors toured the following areas: Service and Auxiliary Building rooftop, the low level intake, the construction buildings, the sewage treatment plant, the area outside the warehouse, and the area surrounding the Gravel Neck gas turbines. The tour emphasized the identification of loose material, which could become airborne and potentially damage structures, systems, components (SSCs) or the switchyard. The inspectors also reviewed Operations Checklist OC-21 Severe Weather Checklist, Abnormal Procedure (AP) 37.01 Abnormal Environmental Conditions, and the Dominion Hurricane Response Plan (Nuclear).


====b. Findings====
====b. Findings====
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The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility, Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for six changes and additional information, such as calculations, supporting analyses, the UFSAR, and drawings to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed in the Attachment to this report.
The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility, Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for six changes and additional information, such as calculations, supporting analyses, the UFSAR, and drawings to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed in the Attachment to this report.


5The inspectors also reviewed samples of changes for which the licensee haddetermined that evaluations were not required, to confirm that the licensee's conclusions to screen out these changes were correct and consistent with 10CFR50.59. The 13 screen out changes reviewed are listed in the Attachment to this report.The inspectors also reviewed one Condition Report (CR) to confirm that the problemwas identified at an appropriate threshold, was entered into the corrective action program, and appropriate corrective actions had been initiated.
The inspectors also reviewed samples of changes for which the licensee had determined that evaluations were not required, to confirm that the licensees conclusions to screen out these changes were correct and consistent with 10CFR50.59. The 13 screen out changes reviewed are listed in the Attachment to this report.
 
The inspectors also reviewed one Condition Report (CR) to confirm that the problem was identified at an appropriate threshold, was entered into the corrective action program, and appropriate corrective actions had been initiated.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.
{{a|1R04}}
{{a|1R04}}
==1R04 Equipment Alignment.1Partial System Walkdown==
==1R04 Equipment Alignment==
 
===.1 Partial System Walkdown===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors conducted partial equipment alignment walkdowns to evaluate theoperability of selected redundant trains or backup systems while the other train or system was inoperable or out of service (OOS). The walkdowns included, as appropriate, reviews of plant procedures and other documents to determine correct system lineups, and verification of critical components to identify discrepancies which could affect operability of the redundant train or backup system. Additionally, the inspectors reviewed the corrective action system to verify that equipment alignment problems were being identified and properly resolved. Specific documents utilized for this inspection sample are listed in the Attachment to this report. The following three systems were included in this review:*Unit 2 Auxiliary Feedwater system while the number 2, Emergency DieselGenerator (EDG) was OOS for maintenance*Number 1 and 3 EDGs while number 2 EDG was OOS for maintenance and testing*Unit 1, A and B Emergency Service Water Pumps, 1-SW-P-1A/B, while 1-SW-P-1C was OOS for maintenance
The inspectors conducted partial equipment alignment walkdowns to evaluate the operability of selected redundant trains or backup systems while the other train or system was inoperable or out of service (OOS). The walkdowns included, as appropriate, reviews of plant procedures and other documents to determine correct system lineups, and verification of critical components to identify discrepancies which could affect operability of the redundant train or backup system. Additionally, the inspectors reviewed the corrective action system to verify that equipment alignment problems were being identified and properly resolved. Specific documents utilized for this inspection sample are listed in the Attachment to this report. The following three systems were included in this review:
* Unit 2 Auxiliary Feedwater system while the number 2, Emergency Diesel Generator (EDG) was OOS for maintenance
* Number 1 and 3 EDGs while number 2 EDG was OOS for maintenance and testing
* Unit 1, A and B Emergency Service Water Pumps, 1-SW-P-1A/B, while 1-SW-P-1C was OOS for maintenance


====b. Findings====
====b. Findings====
No findings of significance were identified..2Complete System Walkdown
No findings of significance were identified.
 
===.2 Complete System Walkdown===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a detailed walkdown on the accessible portions of the Unit 2containment spray system. The walkdown emphasized piping routing, pump and piping overall conditions, proper bolting, plant issues associated with system deficiencies, valve 6and breaker position verifications, and component labeling. The inspectors reviewed thefollowing operating procedures (OPs) and drawings: 0-OP-CS-001/2/3/4/5, FM-84A, DCP 94-059, RC and CS MOV Modification and UFSAR Section 6.3.
The inspectors performed a detailed walkdown on the accessible portions of the Unit 2 containment spray system. The walkdown emphasized piping routing, pump and piping overall conditions, proper bolting, plant issues associated with system deficiencies, valve and breaker position verifications, and component labeling. The inspectors reviewed the following operating procedures (OPs) and drawings: 0-OP-CS-001/2/3/4/5, FM-84A, DCP 94-059, RC and CS MOV Modification and UFSAR Section 6.3.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.
{{a|1R05}}
{{a|1R05}}
==1R05 Fire ProtectionFire Area Walkdowns==
==1R05 Fire Protection==
 
Fire Area Walkdowns


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors conducted inspections in twelve areas of the plant to verify thatcombustibles and ignition sources were properly controlled, and that fire detection and suppression capabilities were intact. The inspectors selected the areas based on a review of the licensee's safe shutdown analysis and probabilistic risk assessment based sensitivity studies for fire-related core damage sequences. Specific documents utilized for this inspection sample are listed in the Attachment to this report. Inspections of the following areas were conducted during this inspection period:*EDG room #2 (1)*Battery room 1A (1)
The inspectors conducted inspections in twelve areas of the plant to verify that combustibles and ignition sources were properly controlled, and that fire detection and suppression capabilities were intact. The inspectors selected the areas based on a review of the licensees safe shutdown analysis and probabilistic risk assessment based sensitivity studies for fire-related core damage sequences. Specific documents utilized for this inspection sample are listed in the Attachment to this report. Inspections of the following areas were conducted during this inspection period:
*Battery room 1B (1)
* EDG room #2 (1)
*Battery room 2A (1)
* Battery room 1A (1)
*Battery room 2B (1)
* Battery room 1B (1)
*Unit 1 and 2 Control Room (1)
* Battery room 2A (1)
*Unit 1 Emergency Switchgear room (1)
* Battery room 2B (1)
*Unit 2 Emergency Switchgear room (1)
* Unit 1 and 2 Control Room (1)
*Auxiliary Building - 2 foot level (1)
* Unit 1 Emergency Switchgear room (1)
*Auxiliary Building - 13 foot level (1)
* Unit 2 Emergency Switchgear room (1)
*Auxiliary Building - 27 foot level (1)
* Auxiliary Building - 2 foot level (1)
*Auxiliary Building - 45 foot level (1)
* Auxiliary Building - 13 foot level (1)
* Auxiliary Building - 27 foot level (1)
* Auxiliary Building - 45 foot level (1)


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed licensed operator simulator training on June 27, 2007, to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The scenario involved manually tripping the reactor and initiating safety injection following the development of excessive reactor coolant system leakage 7with a loss of all makeup capability and a faulted steam generator (SG). As the scenarioprogressed, multiple tubes in the faulted SG ruptured, resulting in a radiological release.
The inspectors observed licensed operator simulator training on June 27, 2007, to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The scenario involved manually tripping the reactor and initiating safety injection following the development of excessive reactor coolant system leakage with a loss of all makeup capability and a faulted steam generator (SG). As the scenario progressed, multiple tubes in the faulted SG ruptured, resulting in a radiological release.


The inspectors observed crew performance in terms of: communications; ability to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including alarm response procedures; and timely control board operation and manipulation, including high-risk operator actions. Additionally, theinspectors observed the oversight and direction, provided by the shift supervisor, including the ability to identify and implement appropriate technical specification (TS)actions.
The inspectors observed crew performance in terms of: communications; ability to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including alarm response procedures; and timely control board operation and manipulation, including high-risk operator actions. Additionally, the inspectors observed the oversight and direction, provided by the shift supervisor, including the ability to identify and implement appropriate technical specification (TS)actions.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
For the two equipment issues described in the plant issues listed below, the inspectorsevaluated the licensee's effectiveness of the corresponding preventive and corrective maintenance. For each selected item below, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. Inspectors performed walkdowns of the accessible portions of the system, performed in-office reviews of procedures and evaluations, and held discussions with system engineers. Inspectors compared the licensee's actions with the requirements of the Maintenance Rule (10 CFR 50.65), VPAP 0815 "Maintenance Rule Program," and the Surry Maintenance Rule Scoping and Performance Criteria Matrix. *Condition Report (CR) 007238, Multiple indications of valve plug to valve stemseparation in steam dump valve 1-MS-TCV-105B*CR 012712, Unit 1 and 2 turbine stop valves and associated limit switches
For the two equipment issues described in the plant issues listed below, the inspectors evaluated the licensees effectiveness of the corresponding preventive and corrective maintenance. For each selected item below, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. Inspectors performed walkdowns of the accessible portions of the system, performed in-office reviews of procedures and evaluations, and held discussions with system engineers. Inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65), VPAP 0815 Maintenance Rule Program, and the Surry Maintenance Rule Scoping and Performance Criteria Matrix.
* Condition Report (CR) 007238, Multiple indications of valve plug to valve stem separation in steam dump valve 1-MS-TCV-105B
* CR 012712, Unit 1 and 2 turbine stop valves and associated limit switches


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated the adequacy, accuracy, and completeness of plant riskassessments performed prior to changes in plant configuration for maintenance activities or in response to emergent conditions. When applicable, inspectors assessed if the licensee entered the appropriate risk category in accordance with plant procedures. Specifically, the inspectors reviewed:
The inspectors evaluated the adequacy, accuracy, and completeness of plant risk assessments performed prior to changes in plant configuration for maintenance activities or in response to emergent conditions. When applicable, inspectors assessed if the licensee entered the appropriate risk category in accordance with plant procedures. Specifically, the inspectors reviewed:
8*Plan of the Day (POD) for the week of 4/2 - 6, including the removal of smokedetectors, emergent work on "D" control room chiller breaker 1-VS-E-4D, and a RECO involving "B" Residual Heat Removal pump,1-RH-P-1B*POD for the week of 4/9 - 13, including the addition of OC-21 "Severe WeatherChecklist", due to a tornado warning, verified that the proper IPT term was being used for the rods being placed in manual, and shifting of safety related maintenance*POD for the week of 4/30 - 5/4, including shifting 2-OPT-CS-002, adding 2-OPT-CH-001, and the possible inclusion of any system affected by the bolting
* Plan of the Day (POD) for the week of 4/2 - 6, including the removal of smoke detectors, emergent work on D control room chiller breaker 1-VS-E-4D, and a RECO involving B Residual Heat Removal pump,1-RH-P-1B
 
* POD for the week of 4/9 - 13, including the addition of OC-21 Severe Weather Checklist, due to a tornado warning, verified that the proper IPT term was being used for the rods being placed in manual, and shifting of safety related maintenance
hardness issue*POD for the week of 5/21 - 25, including emergent work for the failure of Unit 1main steam flow channel, 1-MS-FI-1495 and the shifting of safety related surveillances*POD for the week of 5/28 - 6/1, including the decrease in RTP of Unit 1 forTurbine Valve Freedom testing, maintenance on 1-MS-TV-3 and increase in RTP of Unit 1*POD for the week of 6/17 -23, including emergent repair of 2-BC-E-1C endbellleak, as well as disassembly and drying of A and B main feedwater pump recirculation valve limit switches and clearing the resulting grounds on DC
* POD for the week of 4/30 - 5/4, including shifting 2-OPT-CS-002, adding 2-OPT-CH-001, and the possible inclusion of any system affected by the bolting hardness issue
 
* POD for the week of 5/21 - 25, including emergent work for the failure of Unit 1 main steam flow channel, 1-MS-FI-1495 and the shifting of safety related surveillances
busses
* POD for the week of 5/28 - 6/1, including the decrease in RTP of Unit 1 for Turbine Valve Freedom testing, maintenance on 1-MS-TV-3 and increase in RTP of Unit 1
* POD for the week of 6/17 -23, including emergent repair of 2-BC-E-1C endbell leak, as well as disassembly and drying of A and B main feedwater pump recirculation valve limit switches and clearing the resulting grounds on DC busses


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated the technical adequacy of the four operability evaluations toensure that operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The operability evaluations were described in the engineering transmittals and plant issues listed below:*CR009891, Unit 1 Residual Heat Removal Pumps*CR011234, Unit 2 Containment Spray Piping  
The inspectors evaluated the technical adequacy of the four operability evaluations to ensure that operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The operability evaluations were described in the engineering transmittals and plant issues listed below:
*CR012712, Unit 1, Number 3 Turbine Stop Valve
* CR009891, Unit 1 Residual Heat Removal Pumps
*CR014703, Number 2 EDG high silver content
* CR011234, Unit 2 Containment Spray Piping
* CR012712, Unit 1, Number 3 Turbine Stop Valve
* CR014703, Number 2 EDG high silver content


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.
{{a|1R17}}
==1R17 Permanent Plant Modifications==


91R17Permanent Plant Modifications.1Annual Review
===.1 Annual Review===


a.Inspections ScopeThe inspectors reviewed one Design Change Package (DCP) related to a safety significant system to verify that the associated systems' design bases, licensing bases, and performance capability would be maintained following the modifications; and that the modifications would not render or place the plant in an unsafe condition. The associated 10 CFR 50.59 screenings/evaluations were also reviewed for technical accuracy and to verify license amendments were not required. The DCP contained the technical basis for the modification, the post maintenance test (PMT) requirements to return the pump to service, revised drawings, and other engineering documents. The inspectors reviewed:DCP 04-036, Change Nuttall Gear to IMO Pump Coupling on 2B Charging Pump.
a. Inspections Scope The inspectors reviewed one Design Change Package (DCP) related to a safety significant system to verify that the associated systems design bases, licensing bases, and performance capability would be maintained following the modifications; and that the modifications would not render or place the plant in an unsafe condition. The associated 10 CFR 50.59 screenings/evaluations were also reviewed for technical accuracy and to verify license amendments were not required. The DCP contained the technical basis for the modification, the post maintenance test (PMT) requirements to return the pump to service, revised drawings, and other engineering documents. The inspectors reviewed:
DCP 04-036, Change Nuttall Gear to IMO Pump Coupling on 2B Charging Pump.


====b. Findings====
====b. Findings====
No findings of significance were identified..2Biennial Review
No findings of significance were identified.
 
===.2 Biennial Review===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated nine engineering Design Change Packages (DCPs), foradverse effects on system availability, reliability, and functional capability. The nine modifications and the associated attributes reviewed are as follows: DCP-06-031, 1-CH-MOV-1381 Defeat Torque Closure, Rev. 0 (Barrier Integrity)- Control Signals
The inspectors evaluated nine engineering Design Change Packages (DCPs), for adverse effects on system availability, reliability, and functional capability. The nine modifications and the associated attributes reviewed are as follows:
- Failure ModesDCP-06-047, Defeat Auto-Open Function for Auxiliary Feedwater Flow Isolation MotorOperated Valves, Rev. 0 (Mitigating Systems)
DCP-06-031, 1-CH-MOV-1381 Defeat Torque Closure, Rev. 0 (Barrier Integrity)
- Equipment Protection
    - Control Signals
- Operations
    - Failure Modes DCP-06-047, Defeat Auto-Open Function for Auxiliary Feedwater Flow Isolation Motor Operated Valves, Rev. 0 (Mitigating Systems)
- Flowpaths
    - Equipment Protection
- Control SignalsPTE 9002974, Circle Seal Controls PCV Commercial Dedication Inspection Plan, Ver. 0(Mitigating Systems)
    - Operations
- Materials/Replacement Components
    - Flowpaths
- Pressure Boundary
    - Control Signals PTE 9002974, Circle Seal Controls PCV Commercial Dedication Inspection Plan, Ver. 0 (Mitigating Systems)
- Failure Modes 10DCP-06-046, Emergency Diesel Generator Timing Relay Replacement, Surry Units 1 &2, Rev. 0 (Mitigating Systems)
    - Materials/Replacement Components
    - Pressure Boundary
    - Failure Modes DCP-06-046, Emergency Diesel Generator Timing Relay Replacement, Surry Units 1 &
2, Rev. 0 (Mitigating Systems)
- Materials/Replacement Components
- Materials/Replacement Components
- Timing
- Timing
- Licensing BasisDCP-5-020, Alternate Power Supply for Appendix R Remote Monitoring Panels, SurryUnits 1 & 2, 2/23/06 (Mitigating Systems)
- Licensing Basis DCP-5-020, Alternate Power Supply for Appendix R Remote Monitoring Panels, Surry Units 1 & 2, 2/23/06 (Mitigating Systems)
- Energy Needs
- Energy Needs
- Materials/Replacement Components
- Materials/Replacement Components
- Control Signals
- Control Signals
- OperationsDCP-05-052, Installation of Replacement Annubars for 38-01-SW-FE-121A, B, & C(Mitigating Systems)
- Operations DCP-05-052, Installation of Replacement Annubars for 38-01-SW-FE-121A, B, & C (Mitigating Systems)
- Control Signals
- Control Signals
- Licensing Basis
- Licensing Basis
- Flowpaths
- Flowpaths
- Structural
- Structural
- Material/Replacement ComponentsDCP-06-019, Pressurizer Pressure Controller Modification (Mitigating Systems)- Control Signals
- Material/Replacement Components DCP-06-019, Pressurizer Pressure Controller Modification (Mitigating Systems)
- Control Signals
- Licensing Basis
- Licensing Basis
- Operations
- Operations
- Energy NeedsDCP-06-052, Modify Circuit Breaker Logic for Loading AAC Diesel onto the EmergencyBuses (Mitigating Systems)- Control Signals
- Energy Needs DCP-06-052, Modify Circuit Breaker Logic for Loading AAC Diesel onto the Emergency Buses (Mitigating Systems)
- Control Signals
- Licensing Basis
- Licensing Basis
- Operations
- Operations
- Energy NeedsDCP-05-060, Replace Stainless Steel Service Water Piping, Rev. 0 (Mitigating Systems)- Materials/Replacement Components
- Energy Needs DCP-05-060, Replace Stainless Steel Service Water Piping, Rev. 0 (Mitigating Systems)
- Pressure BoundaryDocuments reviewed included procedures, engineering calculations, modification designand implementation packages, work orders, drawings, corrective action documents, applicable sections of the current UFSAR, supporting analyses, Technical Specification (TS), and design basis information. The inspectors additionally reviewed test documentation to ensure adequacy in scope and conclusion. The inspectors verified that as-built notice details were incorporated in licensing and design basis documentsand associated plant procedures.The inspectors also reviewed selected CRs, Deviation Reports (DRs), and one AuditReport associated with modifications to confirm that problems were identified at an 11appropriate threshold, were entered into the corrective action process, and appropriatecorrective actions had been initiated and tracked to completion.
- Materials/Replacement Components
- Pressure Boundary Documents reviewed included procedures, engineering calculations, modification design and implementation packages, work orders, drawings, corrective action documents, applicable sections of the current UFSAR, supporting analyses, Technical Specification (TS), and design basis information. The inspectors additionally reviewed test documentation to ensure adequacy in scope and conclusion. The inspectors verified that as-built notice details were incorporated in licensing and design basis documents and associated plant procedures.
 
The inspectors also reviewed selected CRs, Deviation Reports (DRs), and one Audit Report associated with modifications to confirm that problems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated and tracked to completion.


====b. Findings====
====b. Findings====


=====Introduction:=====
=====Introduction:=====
The NRC identified a non-cited violation (NCV) of very low safetysignificance (Green) involving commercial grade dedication with two examples. The examples involved Agastat 7000 relays used in supporting the emergency diesel generator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensee's commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics.Description: Regarding the Agastat 7000 relay example, the licensee issued commercialgrade dedication PTE 9002287 pending Design Change Package (DCP) and seismic qualification approval. The approved seismic qualification justification in DCP-06-046 did not qualify the dedicated commercial grade Agastat 7000 relays, but used the justification for the Safety Related (SR) E7000 series relays. This oversight was not dispositioned through DCP closeout and review. The affected relays had not been installed in the plant, but were available for use.Regarding the PCV example, the licensee routinely performs commercial gradededication of new or rebuilt PCVs for use in regulating the 2200 psi safety-related air supply (from storage flasks) to the nominal 85 psi application pressure for the PORVs in the absence of the normal non-safety instrument air supply as described in TS 3.1.A.6.C. Commercial grade dedication plan PTE 9002974 specifies a test pressure of only 1500 pounds per square inch (PSI) minimum for satisfying pressure boundary, pressure regulation and air-flow-shutoff requirements necessary in support of the design basis. The licensee used an existing maintenance procedure as the basis for the pressure selection, vice the original equipment manufacturer (OEM) testing or system operating requirements. The licensee performed an operability determination for valves currently installed in the system with the reactor coolant system operating at temperatures above 350 F and pressures above 2000 psi, and determined that thevalves were operable based upon OEM-performed commercial-grade testing.Analysis: In the first example, the inspectors found that the licensee's failure toadequately perform the commercial grade dedication of the Agastat 7000 series relays for applications that provide safety-related timing control during EDG start was more than minor in that it was associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety significance (Green) because the dedicated relays were available for use but were not placed into service. In the second example, the licensee's failure to adequately perform the commercial grade dedication of the PCVs for applications that provide the safety-related air supply to the PORVs was more than minor in that it is associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety 12significance (Green) based upon confirmation of operability by the licensee as describedabove.In addition, the inspectors identified a cross-cutting aspect of this finding, associatedwith the first example, in the area of human performance - decision making - as illustrated in NRC Inspection Manual Chapter 0305, Section 06.07.c, Substantive Cross-Cutting Issues, Components Within the Cross-Cutting Areas H.1(a). The licensee did not make safety significant or risk significant decisions using a systematic process causing the seismic qualification justification to be missed.
The NRC identified a non-cited violation (NCV) of very low safety significance (Green) involving commercial grade dedication with two examples. The examples involved Agastat 7000 relays used in supporting the emergency diesel generator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensees commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics.
 
=====Description:=====
Regarding the Agastat 7000 relay example, the licensee issued commercial grade dedication PTE 9002287 pending Design Change Package (DCP) and seismic qualification approval. The approved seismic qualification justification in DCP-06-046 did not qualify the dedicated commercial grade Agastat 7000 relays, but used the justification for the Safety Related (SR) E7000 series relays. This oversight was not dispositioned through DCP closeout and review. The affected relays had not been installed in the plant, but were available for use.
 
Regarding the PCV example, the licensee routinely performs commercial grade dedication of new or rebuilt PCVs for use in regulating the 2200 psi safety-related air supply (from storage flasks) to the nominal 85 psi application pressure for the PORVs in the absence of the normal non-safety instrument air supply as described in TS 3.1.A.6.C. Commercial grade dedication plan PTE 9002974 specifies a test pressure of only 1500 pounds per square inch (PSI) minimum for satisfying pressure boundary, pressure regulation and air-flow-shutoff requirements necessary in support of the design basis. The licensee used an existing maintenance procedure as the basis for the pressure selection, vice the original equipment manufacturer (OEM) testing or system operating requirements. The licensee performed an operability determination for valves currently installed in the system with the reactor coolant system operating at temperatures above 350E F and pressures above 2000 psi, and determined that the valves were operable based upon OEM-performed commercial-grade testing.
 
=====Analysis:=====
In the first example, the inspectors found that the licensees failure to adequately perform the commercial grade dedication of the Agastat 7000 series relays for applications that provide safety-related timing control during EDG start was more than minor in that it was associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety significance (Green) because the dedicated relays were available for use but were not placed into service. In the second example, the licensees failure to adequately perform the commercial grade dedication of the PCVs for applications that provide the safety-related air supply to the PORVs was more than minor in that it is associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety significance (Green) based upon confirmation of operability by the licensee as described above.
 
In addition, the inspectors identified a cross-cutting aspect of this finding, associated with the first example, in the area of human performance - decision making - as illustrated in NRC Inspection Manual Chapter 0305, Section 06.07.c, Substantive Cross-Cutting Issues, Components Within the Cross-Cutting Areas H.1(a). The licensee did not make safety significant or risk significant decisions using a systematic process causing the seismic qualification justification to be missed.


=====Enforcement:=====
=====Enforcement:=====
10 CFR 50 Appendix B Criterion III, Design Control, requires in part thatmeasures shall be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components (SSCs). Contrary to this requirement, in the first example, the licensee failed to establish that the dedicated relays are suitable for the application by not performing an adequate seismic qualification; and in the second example, the licensee failed to establish test criteria which demonstrated that the dedicated PCVs were appropriate for system pressure requirements. Because this finding is of very low safety significance and was entered into the licensee's corrective action program (CRs 013815, 013846, and 013984), it is considered an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000280, 281/2007003-01, Failure to Ensure the Suitability of Application of Equipment Essential to Safety-Related Functions.
10 CFR 50 Appendix B Criterion III, Design Control, requires in part that measures shall be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components (SSCs). Contrary to this requirement, in the first example, the licensee failed to establish that the dedicated relays are suitable for the application by not performing an adequate seismic qualification; and in the second example, the licensee failed to establish test criteria which demonstrated that the dedicated PCVs were appropriate for system pressure requirements. Because this finding is of very low safety significance and was entered into the licensee's corrective action program (CRs 013815, 013846, and 013984), it is considered an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000280, 281/2007003-01, Failure to Ensure the Suitability of Application of Equipment Essential to Safety-Related Functions.
{{a|1R19}}
{{a|1R19}}
==1R19 Post Maintenance Testing==
==1R19 Post Maintenance Testing==


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed PMT procedures and/or test activities, as appropriate, forselected risk significant systems to assess whether:
The inspectors reviewed PMT procedures and/or test activities, as appropriate, for selected risk significant systems to assess whether:
: (1) plant testing had been adequately addressed by control room and/or engineering personnel;
: (1) plant testing had been adequately addressed by control room and/or engineering personnel;
: (2) testing was adequate for the maintenance performed;
: (2) testing was adequate for the maintenance performed;
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: (5) tests were performed as written with applicable prerequisites satisfied;
: (5) tests were performed as written with applicable prerequisites satisfied;
: (6) jumpers installed or leads lifted were properly controlled; (7)test equipment was removed following testing; and
: (6) jumpers installed or leads lifted were properly controlled; (7)test equipment was removed following testing; and
: (8) equipment was returned to the status required to perform its safety function. The inspectors observed testing and/or reviewed the results of the following six tests listed below:*0-OPT-SW-003, Emergency Service Water Pump (ESW), 1-SW-P-1C*2-OPT-CH-001, Charging Pump Operability and Performance Test for 2-CH-P-1A*0-OPT-SW-001, ESW Pump, 1-SW-P-1A
: (8) equipment was returned to the status required to perform its safety function. The inspectors observed testing and/or reviewed the results of the following six tests listed below:
*2-OPT-CH-002, Charging Pump Operability and Performance Test for 2-CH-P-1B*0-OPT-EG-001, Number 3 EDG Monthly Start Exercise Test
* 0-OPT-SW-003, Emergency Service Water Pump (ESW), 1-SW-P-1C
*1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test
* 2-OPT-CH-001, Charging Pump Operability and Performance Test for 2-CH-P-1A
* 0-OPT-SW-001, ESW Pump, 1-SW-P-1A
* 2-OPT-CH-002, Charging Pump Operability and Performance Test for 2-CH-P-1B
* 0-OPT-EG-001, Number 3 EDG Monthly Start Exercise Test
* 1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test


====b. Findings====
====b. Findings====
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The inspectors witnessed surveillance tests and/or reviewed test data of the seven risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, the Updated Final Safety Analysis Report (UFSAR), and licensee procedural requirements.
The inspectors witnessed surveillance tests and/or reviewed test data of the seven risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, the Updated Final Safety Analysis Report (UFSAR), and licensee procedural requirements.


The inspectors also determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions. Surveillance Tests*1-OPT-EG-001, Number 1 EDG Monthly Start Exercise*1-IPT-FT-RP-SI-001A (B), Train A (B) Safeguards Actuation Logic FunctionalTest*2-IPT-FT-RC-444/445, Pressurizer Pressure Control Loop Test
The inspectors also determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions.
*1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test
 
*2-OSP-TM-001, Unit 2 Turbine Inlet Valve Freedom TestInservice Tests*1-OPT-CH-002, Charging Pump Operability and Performance Test for 1-CH-P-1BReactor Coolant System (RCS) leakage detection surveillances*2-OPT-RC-10.0, Reactor Coolant Leakage, Computer Calculated
Surveillance Tests
* 1-OPT-EG-001, Number 1 EDG Monthly Start Exercise
* 1-IPT-FT-RP-SI-001A (B), Train A (B) Safeguards Actuation Logic Functional Test
* 2-IPT-FT-RC-444/445, Pressurizer Pressure Control Loop Test
* 1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test
* 2-OSP-TM-001, Unit 2 Turbine Inlet Valve Freedom Test Inservice Tests
* 1-OPT-CH-002, Charging Pump Operability and Performance Test for 1-CH-P-1B Reactor Coolant System (RCS) leakage detection surveillances
* 2-OPT-RC-10.0, Reactor Coolant Leakage, Computer Calculated


====b. Findings====
====b. Findings====
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====b. Findings====
====b. Findings====
No findings of significance were identified.Cornerstone: Emergency Preparedness1EP6Drill Evaluation
No findings of significance were identified.
 
===Cornerstone: Emergency Preparedness===
 
1EP6 Drill Evaluation


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed the announced emergency response training drill conducted onMay 23, 2007, to assess the licensee's performance in emergency classification, off-site notification and protective action recommendations. The drill included emergency response actions taken by the management team in the Technical Support Center. This drill evaluation is included in the Emergency Response Performance Indicator statistics.
The inspectors observed the announced emergency response training drill conducted on May 23, 2007, to assess the licensees performance in emergency classification, off-site notification and protective action recommendations. The drill included emergency response actions taken by the management team in the Technical Support Center. This drill evaluation is included in the Emergency Response Performance Indicator statistics.


====a. Findings====
====a. Findings====
No findings of significance were identified.4OTHER ACTIVITIES4OA1Performance Indicator VerificationInitiating Events Cornerstone.1Unplanned Scrams per 7000 Critical Hours Performance Indicator
No findings of significance were identified.
 
==OTHER ACTIVITIES==
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
 
Initiating Events Cornerstone
 
===.1 Unplanned Scrams per 7000 Critical Hours Performance Indicator===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a periodic review of the "Unplanned Scrams per 7000 CriticalHours" performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline."  Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.
The inspectors performed a periodic review of the Unplanned Scrams per 7000 Critical Hours performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.


====b. Findings====
====b. Findings====
No findings of significance were identified..2Scrams with Loss of Normal Heat Removal Performance Indicator
No findings of significance were identified.
 
===.2 Scrams with Loss of Normal Heat Removal Performance Indicator===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a periodic review of the "Scrams with Loss of Normal HeatRemoval" performance indicator for Units 1 and 2. Specifically, the inspectors reviewed 15this performance indicator from the third quarter of 2006 through the first quarter of2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline."  Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.
The inspectors performed a periodic review of the Scrams with Loss of Normal Heat Removal performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.


====b. Findings====
====b. Findings====
Inspectors found that the licensee had not counted the Unit 2 reactor trip on October 7,2006, as a Scram with Loss of Normal Heat Sink. The licensee submitted the corrected PI and documented the revision in CR 16147..3Unplanned Power Changes per 7000 Critical Hours Performance Indicator
Inspectors found that the licensee had not counted the Unit 2 reactor trip on October 7, 2006, as a Scram with Loss of Normal Heat Sink. The licensee submitted the corrected PI and documented the revision in CR 16147.
 
===.3 Unplanned Power Changes per 7000 Critical Hours Performance Indicator===


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a periodic review of the "Unplanned Power Changes per 7000Critical Hours" performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the second quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline."  Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.
The inspectors performed a periodic review of the Unplanned Power Changes per 7000 Critical Hours performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the second quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.


====b. Findings====
====b. Findings====
No findings of significance were identified.4OA2Identification and Resolution of Problems.1Daily Review of Plant Issues
No findings of significance were identified.
 
{{a|4OA2}}
==4OA2 Identification and Resolution of Problems==
 
===.1 Daily Review of Plant Issues===


====a. Inspection Scope====
====a. Inspection Scope====
As required by Inspection Procedure (IP) 71152 "Identification and Resolution ofProblems,' and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed daily screening of items entered into the licensee's corrective action program (CAP). This review was accomplished by reviewing copies of CRs, attending daily screening meetings, and accessing the licensee's computerized database.
As required by Inspection Procedure (IP) 71152 Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed daily screening of items entered into the licensees corrective action program (CAP). This review was accomplished by reviewing copies of CRs, attending daily screening meetings, and accessing the licensees computerized database.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


16.2Semi-Annual Review of Plant Issues
===.2 Semi-Annual Review of Plant Issues===


====a. Inspection Scope====
====a. Inspection Scope====
As required by Inspection Procedure 71152, the inspectors performed a review of thelicensee's corrective action program (CAP) and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspector's review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1, above, licensee trending efforts, and licensee human performance results. The inspector's review nominally considered the six month period of January 2007, through June 2007, although some examples expanded beyond those dates when the scope of the trend warranted. The review included the following areas/documents:*2007 first quarter trend report and graphs*NRC performance indicators
As required by Inspection Procedure 71152, the inspectors performed a review of the licensees corrective action program (CAP) and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1, above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of January 2007, through June 2007, although some examples expanded beyond those dates when the scope of the trend warranted. The review included the following areas/documents:
*Station indicators
* 2007 first quarter trend report and graphs
*2007 first quarter system heath reports
* NRC performance indicators
*Station reliability issues list
* Station indicators
*Corrective action program status reports
* 2007 first quarter system heath reports
*Work management/normal process list
* Station reliability issues list
*Maintenance rule program reports
* Corrective action program status reports
* Work management/normal process list
* Maintenance rule program reports


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed an in-depth review of Emergency Preparedness (EP) relatedCRs for the October 7, 2006, loss of offsite power event. The inspectors reviewed the actions taken to determine if the licensee had adequately addressed the following attributes:*Complete, accurate and timely identification of the problem*Evaluation and disposition of operability and reportability issues
The inspectors performed an in-depth review of Emergency Preparedness (EP) related CRs for the October 7, 2006, loss of offsite power event. The inspectors reviewed the actions taken to determine if the licensee had adequately addressed the following attributes:
*Consideration of previous failures, extent of condition, generic or common causeimplications*Prioritization and resolution of the issue commensurate with safety significance
* Complete, accurate and timely identification of the problem
*Identification of the root cause and contributing causes of the problem
* Evaluation and disposition of operability and reportability issues
*Identification and implementation of corrective actions commensurate with thesafety significance of the issue.The following EP related CRs and corrective actions for the October 7, 2006, loss ofoffsite power event were reviewed:
* Consideration of previous failures, extent of condition, generic or common cause implications
17*CR 002191, Emergency Classification Opportunity*CR 002562, Performance Indicator Evaluation
* Prioritization and resolution of the issue commensurate with safety significance
*CR 003087, Final Evaluation of Performance Indicator Opportunity on missedNOUE 10/07/2006*CR 002193, TSC response adversely affected by loss of power  
* Identification of the root cause and contributing causes of the problem
*CR 002300, VPAP2802 reportability review for CR002193 (loss of power to theTSC) relate to equipment problems associated with the loss of offsite power event of October 7, 2006.
* Identification and implementation of corrective actions commensurate with the safety significance of the issue.
 
The following EP related CRs and corrective actions for the October 7, 2006, loss of offsite power event were reviewed:
* CR 002191, Emergency Classification Opportunity
* CR 002562, Performance Indicator Evaluation
* CR 003087, Final Evaluation of Performance Indicator Opportunity on missed NOUE 10/07/2006
* CR 002193, TSC response adversely affected by loss of power
* CR 002300, VPAP2802 reportability review for CR002193 (loss of power to the TSC) relate to equipment problems associated with the loss of offsite power event of October 7, 2006.


====b. Findings and Observations====
====b. Findings and Observations====
No findings of significance were identified. 4OA5Other Activities(Closed) Unresolved Item (URI) 5000280,281/2006011-01, Evaluation of Risk Analysisfor Unit 1 For Cross-under Relief Valve Events
No findings of significance were identified.
 
{{a|4OA5}}
==4OA5 Other Activities==
 
    (Closed) Unresolved Item (URI) 5000280,281/2006011-01, Evaluation of Risk Analysis for Unit 1 For Cross-under Relief Valve Events


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors completed the review and risk determination of URI 05000280,281/2006011-01. The inspectors reviewed the licensee's risk procedures and program requirements, correspondence between licensee site personnel and Dominion corporate personnel, and interviewed licensing personnel to evaluate the adequacy of the risk assessments relative to the requirements of 10 CFR 50.65 (a)(4), "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
The inspectors completed the review and risk determination of URI 05000280, 281/2006011-01. The inspectors reviewed the licensees risk procedures and program requirements, correspondence between licensee site personnel and Dominion corporate personnel, and interviewed licensing personnel to evaluate the adequacy of the risk assessments relative to the requirements of 10 CFR 50.65 (a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.


====b. Findings====
====b. Findings====


=====Introduction:=====
=====Introduction:=====
A Green, non-cited violation (NCV) was identified by the NRC regarding afailure to adequately assess the increase in risk due to an emergent condition consisting of the cross-under relief valve (CURV) configuration which resulted in a partial loss of offsite power on Units 1 and 2.Description: On October 7, 2006, Unit 2 was manually tripped during a transient basedon indications associated with main steam flow, main steam pressure, and steam generator feedwater flow and level perturbations. During the transient, exhaust steam discharging from the Unit 2 CURVs impacted the adjacent turbine building siding and created flying debris. The flying debris impacted the 'A' and 'C' Reserve Service Station Transformers' electrical conductors resulting in a loss of normal offsite power to both Unit 1 and one of the Unit 2 emergency buses. Additional details associated with this event are contained in Inspection Report 05000280/2006011 and 05000281/2006011. Upon arrival at the site on October 23, 2006, approximately two weeks after the event,the inspectors requested a risk assessment of this event and the existing configuration of the Unit 1 cross-under relief valves on the south side of the turbine building. The current plant configuration could result in removal and ejection of turbine building siding 18on discharge of the relief valves similar to that which occurred on Unit 2 on October 7,2006. The licensee informed the inspectors that they did not have the risk calculations available, initiated action to perform the risk evaluation, and subsequently incorporated the results into the risk matrix for Unit 1 maintenance rule evaluations.The inspectors obtained additional correspondence information from the licensee whichdemonstrated that the licensee had indeed received a risk evaluation with recommended compensatory actions completed by a Dominion corporate risk analyst on October 11, 2006. However, the licensee failed to integrate this risk assessment, which included a new baseline core damage frequency and compensatory actions, into the site risk program. Following the inspector's request to review a risk assessment on October 23, 2006, the licensee obtained a second risk assessment from another corporate risk analyst on October 25, 2006, and appropriately it was included within the site's overall risk program.Analysis: The inspectors determined that the licensee's failure to integrate a riskassessment into the site's on-line risk program constituted a failure to perform an adequate risk assessment, which was a performance deficiency. The inspectors utilized MC 0612, Appendix B Section 3, to assess if the finding was more than minor. The finding was considered to be more than minor because the licensee's risk assessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. Utilizing MC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that the incremental core damage probability deficit for the affected time period was less than 1.0E-6. As such, the finding is of very low safety significance (Green). The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.Enforcement: 10 CFR 50.65(a)(4) "Requirements for monitoring the Effectiveness ofMaintenance at Nuclear Power Plants" requires, in part, that before performing maintenance activities the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, during the time period from October 8 through 24, 2006, the licensee failed to perform an adequate risk assessment due to the failure to integrate a Dominion corporate risk assessment into the site's risk program. Because the finding was determined to be of very low safety significance and has been entered into the licensee's corrective action program as Condition Report 003611, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000280,281/2007003-02, Failure to Perform an adequate Risk Assessment for Unit 2 Cross-Under Relief Valve Event.4OA6 Management Meetings (Including Exit Meeting) Exit Meeting SummaryOn July 17, 2007, the resident inspectors presented the inspection results to Mr. Sloaneand other members of his staff who acknowledge the findings.The inspectors confirmed that proprietary information was not provided or examinedduring the inspection.
A Green, non-cited violation (NCV) was identified by the NRC regarding a failure to adequately assess the increase in risk due to an emergent condition consisting of the cross-under relief valve (CURV) configuration which resulted in a partial loss of offsite power on Units 1 and 2.
 
=====Description:=====
On October 7, 2006, Unit 2 was manually tripped during a transient based on indications associated with main steam flow, main steam pressure, and steam generator feedwater flow and level perturbations. During the transient, exhaust steam discharging from the Unit 2 CURVs impacted the adjacent turbine building siding and created flying debris. The flying debris impacted the A and C Reserve Service Station Transformers electrical conductors resulting in a loss of normal offsite power to both Unit 1 and one of the Unit 2 emergency buses. Additional details associated with this event are contained in Inspection Report 05000280/2006011 and 05000281/2006011.
 
Upon arrival at the site on October 23, 2006, approximately two weeks after the event, the inspectors requested a risk assessment of this event and the existing configuration of the Unit 1 cross-under relief valves on the south side of the turbine building. The current plant configuration could result in removal and ejection of turbine building siding on discharge of the relief valves similar to that which occurred on Unit 2 on October 7, 2006. The licensee informed the inspectors that they did not have the risk calculations available, initiated action to perform the risk evaluation, and subsequently incorporated the results into the risk matrix for Unit 1 maintenance rule evaluations.
 
The inspectors obtained additional correspondence information from the licensee which demonstrated that the licensee had indeed received a risk evaluation with recommended compensatory actions completed by a Dominion corporate risk analyst on October 11, 2006. However, the licensee failed to integrate this risk assessment, which included a new baseline core damage frequency and compensatory actions, into the site risk program. Following the inspectors request to review a risk assessment on October 23, 2006, the licensee obtained a second risk assessment from another corporate risk analyst on October 25, 2006, and appropriately it was included within the sites overall risk program.
 
=====Analysis:=====
The inspectors determined that the licensees failure to integrate a risk assessment into the sites on-line risk program constituted a failure to perform an adequate risk assessment, which was a performance deficiency. The inspectors utilized MC 0612, Appendix B Section 3, to assess if the finding was more than minor. The finding was considered to be more than minor because the licensees risk assessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. Utilizing MC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that the incremental core damage probability deficit for the affected time period was less than 1.0E-6. As such, the finding is of very low safety significance (Green). The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.
 
=====Enforcement:=====
10 CFR 50.65(a)(4) Requirements for monitoring the Effectiveness of Maintenance at Nuclear Power Plants requires, in part, that before performing maintenance activities the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, during the time period from October 8 through 24, 2006, the licensee failed to perform an adequate risk assessment due to the failure to integrate a Dominion corporate risk assessment into the sites risk program. Because the finding was determined to be of very low safety significance and has been entered into the licensees corrective action program as Condition Report 003611, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000280,281/2007003-02, Failure to Perform an adequate Risk Assessment for Unit 2 Cross-Under Relief Valve Event.
 
{{a|4OA6}}
==4OA6 Management Meetings (Including Exit Meeting)==
 
===Exit Meeting Summary===
 
On July 17, 2007, the resident inspectors presented the inspection results to Mr. Sloane and other members of his staff who acknowledge the findings.
 
The inspectors confirmed that proprietary information was not provided or examined during the inspection.


=SUPPLEMENTAL INFORMATION=
=SUPPLEMENTAL INFORMATION=
Line 318: Line 454:
: [[contact::M. Adams]], Director, Nuclear Station Safety and Licensing
: [[contact::M. Adams]], Director, Nuclear Station Safety and Licensing
: [[contact::K. Grover]], Manager, Operations
: [[contact::K. Grover]], Manager, Operations
: [[contact::B. Garber]], Supervisor, Licensing  
: [[contact::B. Garber]], Supervisor, Licensing
: [[contact::J. Grau]], Manager, Nuclear Oversight
: [[contact::J. Grau]], Manager, Nuclear Oversight
: [[contact::E. Hendrixson]], Director, Site Engineering
: [[contact::E. Hendrixson]], Director, Site Engineering
Line 324: Line 460:
: [[contact::L. Jones]], Manager, Radiation Protection and Chemistry
: [[contact::L. Jones]], Manager, Radiation Protection and Chemistry
: [[contact::C. Luffman]], Manager, Protection Services
: [[contact::C. Luffman]], Manager, Protection Services
: [[contact::R. Simmons]], Manager, Outage and Planning  
: [[contact::R. Simmons]], Manager, Outage and Planning
: [[contact::K. Sloane]], Director, Nuclear Station Operations and Maintenance
: [[contact::K. Sloane]], Director, Nuclear Station Operations and Maintenance
: [[contact::B. Stanley]], Manager, Maintenance
: [[contact::B. Stanley]], Manager, Maintenance
Line 330: Line 466:
NRC
NRC
: [[contact::E. Guthrie]], Chief, Branch 5, Division of Reactor Projects, Region II
: [[contact::E. Guthrie]], Chief, Branch 5, Division of Reactor Projects, Region II
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened NoneOpened and
 
===Closed===
===Opened===
05000280,281/2007003-01NCVFailure to Ensure the Suitability ofApplication of Equipment Essential to
 
Safety-Related Functions (Section 1R17.2)05000280,281/2007003-02NCVFailure to Perform an adequte RiskAssessment for Unit 2 Cross-Under Relief
None
Valve Event (Section 4OA5)
 
===Opened and Closed===
: 05000280,281/2007003-01              NCV          Failure to Ensure the Suitability of Application of Equipment Essential to Safety-Related Functions (Section 1R17.2)
: 05000280,281/2007003-02              NCV          Failure to Perform an adequte Risk Assessment for Unit 2 Cross-Under Relief Valve Event (Section 4OA5)


===Closed===
===Closed===
05000280,281/2006011-01URIEvaluation of Risk Analysis for Unit 1 forCross Under Relief Valve Events (Section
: 05000280,281/2006011-01              URI          Evaluation of Risk Analysis for Unit 1 for Cross Under Relief Valve Events (Section 40A5)


40A5)
2Attachment
==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
==Section 1R02: Evaluation of Changes, Tests, or ExperimentsEvaluationsDCP-05-031,==
 
: NRC
: GSI-191 Containment Sump Strainer Design, Rev. 0 (Regulatory Evaluation,RE, 06-011)
}}
}}

Revision as of 04:07, 23 November 2019

IR 05000280-07-003 and 05000281-07-003 on 04/01/2007 - 06/30/2007 for Surry Power
ML072120265
Person / Time
Site: Surry  Dominion icon.png
Issue date: 07/30/2007
From: Eugene Guthrie
NRC/RGN-II/DRP/RPB5
To: Christian D
Virginia Electric & Power Co (VEPCO)
References
IR-07-003
Download: ML072120265 (31)
v • d • e


Text

uly 30, 2007

SUBJECT:

SURRY POWER STATION - INTEGRATED INSPECTION REPORT 05000280/2007003 AND 05000281/2007003

Dear Mr. Christian:

On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station. The enclosed report documents the inspection results which were discussed on July 17, 2007, with Mr. Sloane and members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, the NRC has identified two findings of very low safety significance (Green), which were determined to be violations of NRC requirements. However, because of the very low safety significance and because the issue was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV)

consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Surry Power Station.

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

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

Sincerely,

/RA/

Eugene F. Guthrie, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37

Enclosure:

NRC Integrated Inspection Report 05000280/2007003 and 05000281/2007003 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37 Report No.: 05000280/2007003, 05000281/2007003, Licensee: Virginia Electric and Power Company (VEPCO)

Facility: Surry Power Station, Units 1 & 2 Location: 5850 Hog Island Road Surry, VA 23883 Dates: April 1, 2007 - June 30, 2007 Inspectors: G. McCoy, Senior Resident Inspector J. Reece, Senior Resident Inspector E. Riggs, Acting Senior Resident Inspector D. Arnett, Resident Inspector R. Chou, Senior Reactor Inspector (Sections 1R02, 1R17)

G. Gardner, Reactor Inspector (Sections 1R02, 1R17)

A. Issa, Reactor Inspector (Sections 1R02, 1R17)

W. Lewis, Reactor Inspector (Sections 1R02, 1R17)

D. Mas-Penaranda, Reactor Inspector (Sections 1R02, 1R17)

L. Miller, Senior Emergency Preparedness Inspector (Section 4OA2.3)

J. Kreh, Emergency Preparedness Inspector (Section 4OA2.3)

Approved by: E. Guthrie, Chief, Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000280/2007003, 05000281/2007003; 04/01/07 - 06/30/07; Surry Power Station Units 1 and 2; Other Activities and Permanent Plant Modifications.

The report covered a three-month period of inspection by resident inspectors and announced regional-based inspections conducted by five reactor inspectors and two emergency preparedness inspectors. Two Green findings, all of which were non-cited violations (NCVs),

were identified. The significance of the finding is indicated by the color (Green, White, Yellow,

Red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a non-cited violation of 10 CFR 50.65 (a)(4), which requires that the licensee assess and manage the increase in risk that may result from the proposed maintenance activities. Specifically, in assessing the increase in risk of planned maintenance activities, the licensee failed to adequately assess planned risk.

The licensee entered this issue in their corrective action program as CR-003611 for resolution.

The finding was considered to be more than minor because the licensees risk assessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. The inspectors determined that the finding is of very low safety significance (Green) since the incremental core damage probability deficit was less than 1E-6. The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.

(Section 4OA5)

Cornerstone: Mitigating Systems

Green.

The NRC identified a non-cited violation (NCV) for the failure to ensure the suitability of application of equipment essential to the safety-related functions of structures, systems, and components (SSCs) through their commercial dedication process as required by 10 CFR Part 50, Appendix B, Criterion III, Design Control. The licensee entered each of the two examples identified by the team into their corrective actions program as CR-013984, including an action to review their overall commercial dedication program.

The examples involve Agastat 7000 relays used in supporting the emergency diesel generator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensees commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics. Both examples of the finding are more than minor because they are associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The examples to the finding were evaluated using the SDP for Reactor Inspection Findings for At-Power Situations. The SDP Phase 1 analysis demonstrates the finding to be of very low safety significance (Green) as the licensee confirmed operability in accordance with plant procedures for both examples. The cause of the first example is related to the cross cutting aspect of human performance. (Section 1R17.2)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On May 30, the unit was down-powered to 88.6 percent until June 1, due to a malfunctioning Turbine Stop Valve. The unit operated at or near full RTP for the remainder of the report period.

Unit 2 operated at or near full RTP for the entire reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

Hurricane Preparations

a. Inspection Scope

On June 11 and 27, 2007, inspectors conducted a tour of the owner-controlled area to evaluate the licensees preparedness for high winds and hurricane conditions well in advance of the approach of any hurricanes. Specifically, the inspectors toured the following areas: Service and Auxiliary Building rooftop, the low level intake, the construction buildings, the sewage treatment plant, the area outside the warehouse, and the area surrounding the Gravel Neck gas turbines. The tour emphasized the identification of loose material, which could become airborne and potentially damage structures, systems, components (SSCs) or the switchyard. The inspectors also reviewed Operations Checklist OC-21 Severe Weather Checklist, Abnormal Procedure (AP) 37.01 Abnormal Environmental Conditions, and the Dominion Hurricane Response Plan (Nuclear).

b. Findings

No findings of significance were identified.

1R02 Evaluations of Changes, Tests or Experiments

a. Inspection Scope

The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility, Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for six changes and additional information, such as calculations, supporting analyses, the UFSAR, and drawings to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed in the Attachment to this report.

The inspectors also reviewed samples of changes for which the licensee had determined that evaluations were not required, to confirm that the licensees conclusions to screen out these changes were correct and consistent with 10CFR50.59. The 13 screen out changes reviewed are listed in the Attachment to this report.

The inspectors also reviewed one Condition Report (CR) to confirm that the problem was identified at an appropriate threshold, was entered into the corrective action program, and appropriate corrective actions had been initiated.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdown

a. Inspection Scope

The inspectors conducted partial equipment alignment walkdowns to evaluate the operability of selected redundant trains or backup systems while the other train or system was inoperable or out of service (OOS). The walkdowns included, as appropriate, reviews of plant procedures and other documents to determine correct system lineups, and verification of critical components to identify discrepancies which could affect operability of the redundant train or backup system. Additionally, the inspectors reviewed the corrective action system to verify that equipment alignment problems were being identified and properly resolved. Specific documents utilized for this inspection sample are listed in the Attachment to this report. The following three systems were included in this review:

  • Number 1 and 3 EDGs while number 2 EDG was OOS for maintenance and testing
  • Unit 1, A and B Emergency Service Water Pumps, 1-SW-P-1A/B, while 1-SW-P-1C was OOS for maintenance

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown on the accessible portions of the Unit 2 containment spray system. The walkdown emphasized piping routing, pump and piping overall conditions, proper bolting, plant issues associated with system deficiencies, valve and breaker position verifications, and component labeling. The inspectors reviewed the following operating procedures (OPs) and drawings: 0-OP-CS-001/2/3/4/5, FM-84A, DCP 94-059, RC and CS MOV Modification and UFSAR Section 6.3.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Fire Area Walkdowns

a. Inspection Scope

The inspectors conducted inspections in twelve areas of the plant to verify that combustibles and ignition sources were properly controlled, and that fire detection and suppression capabilities were intact. The inspectors selected the areas based on a review of the licensees safe shutdown analysis and probabilistic risk assessment based sensitivity studies for fire-related core damage sequences. Specific documents utilized for this inspection sample are listed in the Attachment to this report. Inspections of the following areas were conducted during this inspection period:

  • EDG room #2 (1)
  • Battery room 1A (1)
  • Battery room 1B (1)
  • Battery room 2A (1)
  • Battery room 2B (1)
  • Unit 1 and 2 Control Room (1)
  • Unit 1 Emergency Switchgear room (1)
  • Unit 2 Emergency Switchgear room (1)
  • Auxiliary Building - 2 foot level (1)
  • Auxiliary Building - 13 foot level (1)
  • Auxiliary Building - 27 foot level (1)
  • Auxiliary Building - 45 foot level (1)

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed licensed operator simulator training on June 27, 2007, to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The scenario involved manually tripping the reactor and initiating safety injection following the development of excessive reactor coolant system leakage with a loss of all makeup capability and a faulted steam generator (SG). As the scenario progressed, multiple tubes in the faulted SG ruptured, resulting in a radiological release.

The inspectors observed crew performance in terms of: communications; ability to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including alarm response procedures; and timely control board operation and manipulation, including high-risk operator actions. Additionally, the inspectors observed the oversight and direction, provided by the shift supervisor, including the ability to identify and implement appropriate technical specification (TS)actions.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two equipment issues described in the plant issues listed below, the inspectors evaluated the licensees effectiveness of the corresponding preventive and corrective maintenance. For each selected item below, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. Inspectors performed walkdowns of the accessible portions of the system, performed in-office reviews of procedures and evaluations, and held discussions with system engineers. Inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65), VPAP 0815 Maintenance Rule Program, and the Surry Maintenance Rule Scoping and Performance Criteria Matrix.

  • Condition Report (CR) 007238, Multiple indications of valve plug to valve stem separation in steam dump valve 1-MS-TCV-105B
  • CR 012712, Unit 1 and 2 turbine stop valves and associated limit switches

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated the adequacy, accuracy, and completeness of plant risk assessments performed prior to changes in plant configuration for maintenance activities or in response to emergent conditions. When applicable, inspectors assessed if the licensee entered the appropriate risk category in accordance with plant procedures. Specifically, the inspectors reviewed:

  • Plan of the Day (POD) for the week of 4/2 - 6, including the removal of smoke detectors, emergent work on D control room chiller breaker 1-VS-E-4D, and a RECO involving B Residual Heat Removal pump,1-RH-P-1B
  • POD for the week of 4/9 - 13, including the addition of OC-21 Severe Weather Checklist, due to a tornado warning, verified that the proper IPT term was being used for the rods being placed in manual, and shifting of safety related maintenance
  • POD for the week of 4/30 - 5/4, including shifting 2-OPT-CS-002, adding 2-OPT-CH-001, and the possible inclusion of any system affected by the bolting hardness issue
  • POD for the week of 5/21 - 25, including emergent work for the failure of Unit 1 main steam flow channel, 1-MS-FI-1495 and the shifting of safety related surveillances
  • POD for the week of 5/28 - 6/1, including the decrease in RTP of Unit 1 for Turbine Valve Freedom testing, maintenance on 1-MS-TV-3 and increase in RTP of Unit 1
  • POD for the week of 6/17 -23, including emergent repair of 2-BC-E-1C endbell leak, as well as disassembly and drying of A and B main feedwater pump recirculation valve limit switches and clearing the resulting grounds on DC busses

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors evaluated the technical adequacy of the four operability evaluations to ensure that operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The operability evaluations were described in the engineering transmittals and plant issues listed below:

  • CR012712, Unit 1, Number 3 Turbine Stop Valve

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

.1 Annual Review

a. Inspections Scope The inspectors reviewed one Design Change Package (DCP) related to a safety significant system to verify that the associated systems design bases, licensing bases, and performance capability would be maintained following the modifications; and that the modifications would not render or place the plant in an unsafe condition. The associated 10 CFR 50.59 screenings/evaluations were also reviewed for technical accuracy and to verify license amendments were not required. The DCP contained the technical basis for the modification, the post maintenance test (PMT) requirements to return the pump to service, revised drawings, and other engineering documents. The inspectors reviewed:

DCP 04-036, Change Nuttall Gear to IMO Pump Coupling on 2B Charging Pump.

b. Findings

No findings of significance were identified.

.2 Biennial Review

a. Inspection Scope

The inspectors evaluated nine engineering Design Change Packages (DCPs), for adverse effects on system availability, reliability, and functional capability. The nine modifications and the associated attributes reviewed are as follows:

DCP-06-031, 1-CH-MOV-1381 Defeat Torque Closure, Rev. 0 (Barrier Integrity)

- Control Signals

- Failure Modes DCP-06-047, Defeat Auto-Open Function for Auxiliary Feedwater Flow Isolation Motor Operated Valves, Rev. 0 (Mitigating Systems)

- Equipment Protection

- Operations

- Flowpaths

- Control Signals PTE 9002974, Circle Seal Controls PCV Commercial Dedication Inspection Plan, Ver. 0 (Mitigating Systems)

- Materials/Replacement Components

- Pressure Boundary

- Failure Modes DCP-06-046, Emergency Diesel Generator Timing Relay Replacement, Surry Units 1 &

2, Rev. 0 (Mitigating Systems)

- Materials/Replacement Components

- Timing

- Licensing Basis DCP-5-020, Alternate Power Supply for Appendix R Remote Monitoring Panels, Surry Units 1 & 2, 2/23/06 (Mitigating Systems)

- Energy Needs

- Materials/Replacement Components

- Control Signals

- Operations DCP-05-052, Installation of Replacement Annubars for 38-01-SW-FE-121A, B, & C (Mitigating Systems)

- Control Signals

- Licensing Basis

- Flowpaths

- Structural

- Material/Replacement Components DCP-06-019, Pressurizer Pressure Controller Modification (Mitigating Systems)

- Control Signals

- Licensing Basis

- Operations

- Energy Needs DCP-06-052, Modify Circuit Breaker Logic for Loading AAC Diesel onto the Emergency Buses (Mitigating Systems)

- Control Signals

- Licensing Basis

- Operations

- Energy Needs DCP-05-060, Replace Stainless Steel Service Water Piping, Rev. 0 (Mitigating Systems)

- Materials/Replacement Components

- Pressure Boundary Documents reviewed included procedures, engineering calculations, modification design and implementation packages, work orders, drawings, corrective action documents, applicable sections of the current UFSAR, supporting analyses, Technical Specification (TS), and design basis information. The inspectors additionally reviewed test documentation to ensure adequacy in scope and conclusion. The inspectors verified that as-built notice details were incorporated in licensing and design basis documents and associated plant procedures.

The inspectors also reviewed selected CRs, Deviation Reports (DRs), and one Audit Report associated with modifications to confirm that problems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated and tracked to completion.

b. Findings

Introduction:

The NRC identified a non-cited violation (NCV) of very low safety significance (Green) involving commercial grade dedication with two examples. The examples involved Agastat 7000 relays used in supporting the emergency diesel generator (EDG) start sequence and pressure control valves (PCVs) for use in the safety-related air supply supporting design operation of the power-operated relief valves (PORVs). In the first example, the licensees commercial grade dedication did not verify the adequacy of seismic qualification. In the second, the licensee utilized a non-conservative test pressure as part of their dedication to critical characteristics.

Description:

Regarding the Agastat 7000 relay example, the licensee issued commercial grade dedication PTE 9002287 pending Design Change Package (DCP) and seismic qualification approval. The approved seismic qualification justification in DCP-06-046 did not qualify the dedicated commercial grade Agastat 7000 relays, but used the justification for the Safety Related (SR) E7000 series relays. This oversight was not dispositioned through DCP closeout and review. The affected relays had not been installed in the plant, but were available for use.

Regarding the PCV example, the licensee routinely performs commercial grade dedication of new or rebuilt PCVs for use in regulating the 2200 psi safety-related air supply (from storage flasks) to the nominal 85 psi application pressure for the PORVs in the absence of the normal non-safety instrument air supply as described in TS 3.1.A.6.C. Commercial grade dedication plan PTE 9002974 specifies a test pressure of only 1500 pounds per square inch (PSI) minimum for satisfying pressure boundary, pressure regulation and air-flow-shutoff requirements necessary in support of the design basis. The licensee used an existing maintenance procedure as the basis for the pressure selection, vice the original equipment manufacturer (OEM) testing or system operating requirements. The licensee performed an operability determination for valves currently installed in the system with the reactor coolant system operating at temperatures above 350E F and pressures above 2000 psi, and determined that the valves were operable based upon OEM-performed commercial-grade testing.

Analysis:

In the first example, the inspectors found that the licensees failure to adequately perform the commercial grade dedication of the Agastat 7000 series relays for applications that provide safety-related timing control during EDG start was more than minor in that it was associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety significance (Green) because the dedicated relays were available for use but were not placed into service. In the second example, the licensees failure to adequately perform the commercial grade dedication of the PCVs for applications that provide the safety-related air supply to the PORVs was more than minor in that it is associated with the Design Control attribute affecting the Reactor Safety Mitigating Systems Cornerstone objective. The finding was found to be of very low safety significance (Green) based upon confirmation of operability by the licensee as described above.

In addition, the inspectors identified a cross-cutting aspect of this finding, associated with the first example, in the area of human performance - decision making - as illustrated in NRC Inspection Manual Chapter 0305, Section 06.07.c, Substantive Cross-Cutting Issues, Components Within the Cross-Cutting Areas H.1(a). The licensee did not make safety significant or risk significant decisions using a systematic process causing the seismic qualification justification to be missed.

Enforcement:

10 CFR 50 Appendix B Criterion III, Design Control, requires in part that measures shall be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components (SSCs). Contrary to this requirement, in the first example, the licensee failed to establish that the dedicated relays are suitable for the application by not performing an adequate seismic qualification; and in the second example, the licensee failed to establish test criteria which demonstrated that the dedicated PCVs were appropriate for system pressure requirements. Because this finding is of very low safety significance and was entered into the licensee's corrective action program (CRs 013815, 013846, and 013984), it is considered an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000280, 281/2007003-01, Failure to Ensure the Suitability of Application of Equipment Essential to Safety-Related Functions.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed PMT procedures and/or test activities, as appropriate, for selected risk significant systems to assess whether:

(1) plant testing had been adequately addressed by control room and/or engineering personnel;
(2) testing was adequate for the maintenance performed;
(3) acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;
(4) test instrumentation had current calibrations, range, and accuracy consistent with the application;
(5) tests were performed as written with applicable prerequisites satisfied;
(6) jumpers installed or leads lifted were properly controlled; (7)test equipment was removed following testing; and
(8) equipment was returned to the status required to perform its safety function. The inspectors observed testing and/or reviewed the results of the following six tests listed below:
  • 2-OPT-CH-001, Charging Pump Operability and Performance Test for 2-CH-P-1A
  • 0-OPT-SW-001, ESW Pump, 1-SW-P-1A
  • 2-OPT-CH-002, Charging Pump Operability and Performance Test for 2-CH-P-1B
  • 0-OPT-EG-001, Number 3 EDG Monthly Start Exercise Test
  • 1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors witnessed surveillance tests and/or reviewed test data of the seven risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, the Updated Final Safety Analysis Report (UFSAR), and licensee procedural requirements.

The inspectors also determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions.

Surveillance Tests

  • 1-OPT-EG-001, Number 1 EDG Monthly Start Exercise
  • 1-IPT-FT-RP-SI-001A (B), Train A (B) Safeguards Actuation Logic Functional Test
  • 2-IPT-FT-RC-444/445, Pressurizer Pressure Control Loop Test
  • 1-OSP-TM-001, Unit 1 Turbine Inlet Valve Freedom Test
  • 2-OSP-TM-001, Unit 2 Turbine Inlet Valve Freedom Test Inservice Tests
  • 1-OPT-CH-002, Charging Pump Operability and Performance Test for 1-CH-P-1B Reactor Coolant System (RCS) leakage detection surveillances

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed documents and observed portions of the S2-07-052 and 2-RC-P-1C Frame Alert set-point modification. Among the documents reviewed were system design bases, the UFSAR, TS, system operability/availability evaluations, and the 10 CFR 50.59 screening. The inspectors observed, as appropriate, that the installation was consistent with the modification documents, was in accordance with the configuration control process, adequate procedures and changes were made, and post installation testing was adequate.

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed the announced emergency response training drill conducted on May 23, 2007, to assess the licensees performance in emergency classification, off-site notification and protective action recommendations. The drill included emergency response actions taken by the management team in the Technical Support Center. This drill evaluation is included in the Emergency Response Performance Indicator statistics.

a. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Initiating Events Cornerstone

.1 Unplanned Scrams per 7000 Critical Hours Performance Indicator

a. Inspection Scope

The inspectors performed a periodic review of the Unplanned Scrams per 7000 Critical Hours performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.

b. Findings

No findings of significance were identified.

.2 Scrams with Loss of Normal Heat Removal Performance Indicator

a. Inspection Scope

The inspectors performed a periodic review of the Scrams with Loss of Normal Heat Removal performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.

b. Findings

Inspectors found that the licensee had not counted the Unit 2 reactor trip on October 7, 2006, as a Scram with Loss of Normal Heat Sink. The licensee submitted the corrected PI and documented the revision in CR 16147.

.3 Unplanned Power Changes per 7000 Critical Hours Performance Indicator

a. Inspection Scope

The inspectors performed a periodic review of the Unplanned Power Changes per 7000 Critical Hours performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the second quarter of 2006 through the first quarter of 2007. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Review of Plant Issues

a. Inspection Scope

As required by Inspection Procedure (IP) 71152 Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed daily screening of items entered into the licensees corrective action program (CAP). This review was accomplished by reviewing copies of CRs, attending daily screening meetings, and accessing the licensees computerized database.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Review of Plant Issues

a. Inspection Scope

As required by Inspection Procedure 71152, the inspectors performed a review of the licensees corrective action program (CAP) and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1, above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of January 2007, through June 2007, although some examples expanded beyond those dates when the scope of the trend warranted. The review included the following areas/documents:

  • 2007 first quarter trend report and graphs
  • NRC performance indicators
  • Station indicators
  • 2007 first quarter system heath reports
  • Station reliability issues list
  • Corrective action program status reports
  • Work management/normal process list

b. Findings

No findings of significance were identified.

.3 Focused Review

a. Inspection Scope

The inspectors performed an in-depth review of Emergency Preparedness (EP) related CRs for the October 7, 2006, loss of offsite power event. The inspectors reviewed the actions taken to determine if the licensee had adequately addressed the following attributes:

  • Complete, accurate and timely identification of the problem
  • Evaluation and disposition of operability and reportability issues
  • Consideration of previous failures, extent of condition, generic or common cause implications
  • Prioritization and resolution of the issue commensurate with safety significance
  • Identification of the root cause and contributing causes of the problem
  • Identification and implementation of corrective actions commensurate with the safety significance of the issue.

The following EP related CRs and corrective actions for the October 7, 2006, loss of offsite power event were reviewed:

  • CR 002191, Emergency Classification Opportunity
  • CR 002562, Performance Indicator Evaluation
  • CR 003087, Final Evaluation of Performance Indicator Opportunity on missed NOUE 10/07/2006
  • CR 002193, TSC response adversely affected by loss of power
  • CR 002300, VPAP2802 reportability review for CR002193 (loss of power to the TSC) relate to equipment problems associated with the loss of offsite power event of October 7, 2006.

b. Findings and Observations

No findings of significance were identified.

4OA5 Other Activities

(Closed) Unresolved Item (URI) 5000280,281/2006011-01, Evaluation of Risk Analysis for Unit 1 For Cross-under Relief Valve Events

a. Inspection Scope

The inspectors completed the review and risk determination of URI 05000280, 281/2006011-01. The inspectors reviewed the licensees risk procedures and program requirements, correspondence between licensee site personnel and Dominion corporate personnel, and interviewed licensing personnel to evaluate the adequacy of the risk assessments relative to the requirements of 10 CFR 50.65 (a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.

b. Findings

Introduction:

A Green, non-cited violation (NCV) was identified by the NRC regarding a failure to adequately assess the increase in risk due to an emergent condition consisting of the cross-under relief valve (CURV) configuration which resulted in a partial loss of offsite power on Units 1 and 2.

Description:

On October 7, 2006, Unit 2 was manually tripped during a transient based on indications associated with main steam flow, main steam pressure, and steam generator feedwater flow and level perturbations. During the transient, exhaust steam discharging from the Unit 2 CURVs impacted the adjacent turbine building siding and created flying debris. The flying debris impacted the A and C Reserve Service Station Transformers electrical conductors resulting in a loss of normal offsite power to both Unit 1 and one of the Unit 2 emergency buses. Additional details associated with this event are contained in Inspection Report 05000280/2006011 and 05000281/2006011.

Upon arrival at the site on October 23, 2006, approximately two weeks after the event, the inspectors requested a risk assessment of this event and the existing configuration of the Unit 1 cross-under relief valves on the south side of the turbine building. The current plant configuration could result in removal and ejection of turbine building siding on discharge of the relief valves similar to that which occurred on Unit 2 on October 7, 2006. The licensee informed the inspectors that they did not have the risk calculations available, initiated action to perform the risk evaluation, and subsequently incorporated the results into the risk matrix for Unit 1 maintenance rule evaluations.

The inspectors obtained additional correspondence information from the licensee which demonstrated that the licensee had indeed received a risk evaluation with recommended compensatory actions completed by a Dominion corporate risk analyst on October 11, 2006. However, the licensee failed to integrate this risk assessment, which included a new baseline core damage frequency and compensatory actions, into the site risk program. Following the inspectors request to review a risk assessment on October 23, 2006, the licensee obtained a second risk assessment from another corporate risk analyst on October 25, 2006, and appropriately it was included within the sites overall risk program.

Analysis:

The inspectors determined that the licensees failure to integrate a risk assessment into the sites on-line risk program constituted a failure to perform an adequate risk assessment, which was a performance deficiency. The inspectors utilized MC 0612, Appendix B Section 3, to assess if the finding was more than minor. The finding was considered to be more than minor because the licensees risk assessment had known errors or incorrect assumptions that had the potential to change the outcome of the assessment. Utilizing MC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that the incremental core damage probability deficit for the affected time period was less than 1.0E-6. As such, the finding is of very low safety significance (Green). The inspectors determined that the cause of the finding was related to the proper work planning aspect of the human performance cross-cutting area.

Enforcement:

10 CFR 50.65(a)(4) Requirements for monitoring the Effectiveness of Maintenance at Nuclear Power Plants requires, in part, that before performing maintenance activities the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, during the time period from October 8 through 24, 2006, the licensee failed to perform an adequate risk assessment due to the failure to integrate a Dominion corporate risk assessment into the sites risk program. Because the finding was determined to be of very low safety significance and has been entered into the licensees corrective action program as Condition Report 003611, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000280,281/2007003-02, Failure to Perform an adequate Risk Assessment for Unit 2 Cross-Under Relief Valve Event.

4OA6 Management Meetings (Including Exit Meeting)

Exit Meeting Summary

On July 17, 2007, the resident inspectors presented the inspection results to Mr. Sloane and other members of his staff who acknowledge the findings.

The inspectors confirmed that proprietary information was not provided or examined during the inspection.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Adams, Director, Nuclear Station Safety and Licensing
K. Grover, Manager, Operations
B. Garber, Supervisor, Licensing
J. Grau, Manager, Nuclear Oversight
E. Hendrixson, Director, Site Engineering
D. Jernigan, Site Vice President
L. Jones, Manager, Radiation Protection and Chemistry
C. Luffman, Manager, Protection Services
R. Simmons, Manager, Outage and Planning
K. Sloane, Director, Nuclear Station Operations and Maintenance
B. Stanley, Manager, Maintenance
M. Wilson, Manager, Training

NRC

E. Guthrie, Chief, Branch 5, Division of Reactor Projects, Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000280,281/2007003-01 NCV Failure to Ensure the Suitability of Application of Equipment Essential to Safety-Related Functions (Section 1R17.2)
05000280,281/2007003-02 NCV Failure to Perform an adequte Risk Assessment for Unit 2 Cross-Under Relief Valve Event (Section 4OA5)

Closed

05000280,281/2006011-01 URI Evaluation of Risk Analysis for Unit 1 for Cross Under Relief Valve Events (Section 40A5)

LIST OF DOCUMENTS REVIEWED

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