IR 05000338/2010002

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IR 05000338-10-002, 05000339-10-002, on 01/01/2010 - 03/31/2010, North Anna Power Station, Units 1 and 2. Routine Integrated Inspection Report, Fire Protection, Event Followup, and Other Activities
ML101270273
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 05/07/2010
From: Gerald Mccoy
NRC/RGN-II/DRP/RPB5
To: Heacock D
Virginia Electric & Power Co (VEPCO)
References
IR-10-002
Download: ML101270273 (33)
v • d • e


Text

UNITED STATES May 7, 2010

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2010002 AND 05000339/2010002

Dear Mr. Heacock:

On March 31, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2. The enclosed integrated inspection report documents the inspection findings which were discussed on April 20 and May 6, 2010, with Mr.

Larry Lane and other members of your staff.

The inspection examined activities conducted under your licenses as they related 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.

This report documents three self-revealing findings, and two NRC-identified findings of very low safety significance (Green) of which three findings were determined to be violations of NRC requirements. However, because of the very low safety significance of these issues and because they were entered into your corrective action program, the NRC is treating these as non-cited violations (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you wish to contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.

Additionally, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the North Anna Power Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

VEPCO 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7

Enclosure:

Inspection Report 05000338/2010002 and 05000339/2010002 w/ Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7 Report No: 05000338/2010002 and 05000339/2010002 Licensee: Virginia Electric and Power Company (VEPCO)

Facility: North Anna Power Station, Units 1 & 2 Location: 1022 Haley Drive Mineral, Virginia 23117 Dates: January 1, 2010 through March 31, 2010 Inspectors: J. Reece, Senior Resident Inspector R. Clagg, Resident Inspector G. Laska, Senior Operations Examiner, Section 1R11.1 M. Meeks, Operations Examiner, Section 1R11.1 Approved by: Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000338/2010-002, 05000339/2010-002; 01/01/2010 - 03/31/2010; North Anna Power

Station, Units 1 and 2. Routine Integrated Inspection Report, Fire Protection, Event Followup, and Other Activities.

The report covered a 3 month period of inspection by resident inspectors, a Senior Operations Examiner, and an Operations Examiner from the region. Seven findings were identified and were determined to be either non-cited violations (NCV), findings (FIN) or an apparent violation (AV). The significance of most findings is indicated by their color (Green, White, Yellow, Red)using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspect was determined using IMC 0305, Operating Reactor Assessment Program. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs 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.

A Green, self-revealing finding was identified for the licensees failure to follow or adhere to licensee procedures for switchyard relay maintenance, human performance and management oversight, which resulted in the loss of the Technical Specifications (TS) required offsite circuit for the 1H and 2J emergency buses and the consequent auto-start of the respective emergency diesel generators (EDGs).

The licensee entered this problem into their corrective action program as condition report 361280.

The inspectors determined that the failure to follow procedures to successfully accomplish nuclear switchyard relay maintenance was a performance deficiency (PD). The PD had a credible impact on safety due to the loss of a TS required offsite power supply and the start of the respective EDGs to restore power to the affected emergency buses. The inspectors determined the PD was more than minor because it impacted the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations, and the related attribute of human performance due to human error in the implementation of a non-safety nuclear switchyard related procedures. In accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, the inspectors performed a Phase 1 risk analysis and determined the finding was of very low safety significance (Green)because the finding did contribute to a reactor trip but did not contribute to the likelihood that mitigation equipment or functions would not be available. This finding involved the cross-cutting area of human performance, the component of the work practices, and the aspect of personnel use human error prevention techniques commensurate with risk for the assigned task, H.4(a), because a licensee technicians failure to use proper human error prevention techniques resulted in a partial loss of offsite power on both units. (Section 4OA3.2a)

Green.

A Green, self-revealing finding was identified for the licensees failure to establish an adequate procedure for calibration of under voltage timers which resulted in the failure of the Unit 2 G bus to fast transfer from C reserve station service transformer (RSST) to the B RSST and consequent loss of main turbine condenser vacuum causing a main turbine/reactor trip. The licensee entered this problem into their corrective action program as condition report 361280.

A self-revealing performance deficiency (PD) involving a Unit 2 turbine trip on loss of condenser vacuum was identified and resulted from the failure to establish an adequate procedure for the calibration of the time delay relays associated with the G bus cross-tie fast transfer circuit. This PD was the result of the failure to establish an adequate procedure for calibration of fast transfer relays. Specifically, licensee did not have mandated documentation in place to require technicians to use a proven method for timer calibration. The cause of PD was reasonably within the licensees ability to foresee and correct. Specifically, the NRC previously issued NCV 05000338/2008002-03, Inoperability of '1H' EDG Due to Failure to Adequately Establish Procedural Requirements for Protective Relay Testing, which involved a lack of procedural guidance and reliance of worker skill of the craft to successfully complete the activity. The PD adversely impacted the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations and was related to the attribute of procedure quality because the correct timing relay calibration methodology was not documented in a procedure. In accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, a phase 1 significance determination process (SDP) screening determined that a phase 2 evaluation was required as the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. A phase 3 SDP evaluation was performed by a regional SRA since the North Anna Risk Informed Inspection Notebook did not have the level of detail to accurately assess the finding. The NRCs SPAR model was utilized to assess the risk significance of the finding modeling the impact of a loss of power to the 2G Bus without the fast transfer circuit available resulting in a reactor trip due to low condenser vacuum. The dominant sequence was a reactor trip without the condenser heat sink, caused by loss of power to the 2G bus with a failure of the cross-tie fast transfer circuit, with subsequent failures of main feedwater, auxiliary feedwater, and failure of feed and bleed cooling leading to core damage. The evaluation determined that the risk increase in core damage frequency was <1E-6 per year, a finding of very low safety significance,

Green.

This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish an accurate procedure to ensure correct calibration of under voltage timers. (Section 4OA3.2b)

Cornerstone: Mitigating Systems

Green.

A self-revealing, non-cited violation of Technical Specifications 5.4.1d was identified for the failure to adequately implement procedural requirements to reset a high pressure carbon dioxide (CO2) fire suppression system for the EDG pump room

  1. 1. The licensee entered this problem into their corrective action program as condition report 371298.

A self-revealing performance deficiency (PD) was identified for the failure to adequately implement fire protection procedure requirements of 0-PT-104.2 to ensure zone 3 was adequately reset. This PD had a credible impact on safety due to an inoperable fire suppression system for safety-related components. The PD was more than minor because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attributes of external events regarding fire due to the adverse impact on the capability of the fire suppression system and human performance due to the failure to properly implement a test procedure. In accordance with NRC Inspection Manual Chapter 0609,

Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance (Green) because core damage frequencies related to the fuel oil pump room #1 were less than 1E-6 and the duration of the system inoperability was less than three days. This finding involved the cross-cutting area of human performance, the component of work practices and the aspect of personnel do not proceed in the face of unexpected circumstances, H.4(a), because licensee personnel encountered problems with a CO2 system reset and failed to stop for proper guidance from supervision. (Section 1R05)

Green.

A non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions,

Procedures and Drawings, was identified by the NRC for the failure to accomplish the installation of low head safety injection (LHSI) and outside recirculation spray (ORS) pump discharge piping in accordance with prescribed drawings which resulted in piping interference involving hard contact between the aforementioned system piping. The licensee entered this problem into their corrective action program as condition report 343744.

A performance deficiency (PD) was identified by the NRC for the failure to adequately to accomplish the installation of LHSI and ORS pump discharge piping in accordance with prescribed drawings which resulted in hard contact between the aforementioned system piping. This PD had a credible impact on safety due to the loss of design margin resulting in a reasonable doubt regarding long term reliability.

The PD was more than minor because if left uncorrected it would have the potential to result in a more significant event involving Unit 1 A train LHSI pump discharge nozzle failure from excessive stress. In accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green due to a design deficiency confirmed not to result in a loss of operability or functionality. The finding had no cross-cutting aspects due to its legacy nature.

(Section 4OA5.2)

Green.

A Green, non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified by the NRC for the failure to establish an adequate post-modification test program for piping supports affected by piping design changes (modifications). The licensee entered this problem into their corrective action program as condition report 357450.

The inspectors determined that the failure to establish an adequate post-modification test program for piping supports affected by piping modifications as required by 10 CFR 50, Appendix B, Criterion III, was a performance deficiency (PD). This PD had a credible impact on safety due to a programmatic deficiency that resulted in safety-related piping supports adversely affected by modifications. The PD was more than minor because if left uncorrected it would have the potential to result in a more significant event involving inoperable, unidentified safety-related piping supports with consequent adverse impact on the respective system during a seismic event. In accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green due to a design deficiency confirmed not to result in a loss of operability or functionality. This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish up-to-date program procedures to ensure adequate post-modification testing of piping supports. (Section 4OA5.3)

Licensee Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full Rated Thermal Power (RTP) and operated at full power for the entire report period.

Unit 2 began the inspection period at full RTP but shutdown for a refueling outage on March 21,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors assessed the external flood vulnerability of the North Anna site for the south side of the plant from failure of the Service Water reservoir dam. The inspectors verified the condition of the flood protection dike between the service water reservoir and the plant and related drainage ditches and culverts. The inspectors also reviewed applicable station procedures and design documents to assess proper surveillance and maintenance for external flood protection features.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

The inspectors conducted two equipment partial alignment walkdowns to evaluate the operability of selected redundant trains or backup systems, listed below, with the other train or system inoperable or out of service. The inspectors reviewed the functional systems descriptions, Updated Final Safety Analysis Report (UFSAR), system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions. The inspectors performed walkdowns of the systems to verify that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system.

  • Unit 1 'B' train motor driven auxiliary feedwater (AFW) pump during maintenance associated with A train motor driven AFW pump and related components

b. Findings

No findings of significance were identified

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted tours of the five areas listed below that are important to reactor safety to verify the licensees implementation of fire protection requirements as described in fleet procedures CM-AA-FPA-100, Revision 0, Fire Protection/Appendix R (Fire Safe Shutdown) Program, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 0, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 0.

The inspectors evaluated, as appropriate, conditions related to:

(1) licensee control of transient combustibles and ignition sources;
(2) the material condition, operational status, and operational lineup of fire protection systems, equipment, and features; and
(3) the fire barriers used to prevent fire damage or fire propagation.
  • Fuel Oil Pump House - Room A (fire zone 10Aa / FOPR-A), Fuel Oil Pump House -

Room B1 (fire zone 10Ba / FOPR-B10C), Motor Control Center Room (fire zone B10C), Casing Cooling Tank & Pump House Unit 1 (fire zone Z-41-1 / CCT&PH-1),and Casing Cooling Tank & Pump House Unit 2 (fire zone Z-41-2 / CCT&PH-2)

  • Normal Switchgear Room Unit 1 (fire zone 5-1 / NSR-1) and Unit 2 (fire zone 5-2 /

NSR-2)

  • Battery Room 1 - I Unit 1 (fire zone 7A-1 / BR1-I), Battery Room 2 - I Unit 2 (fire zone 7A-2 / BR2-1), Battery Room 1 - II Unit 1 (fire zone 7B-1 / BR1-II), Battery Room 2 - II Unit 2 (fire zone 7B-2 / BR2-II), Battery Room 1 - III Unit 1 (fire zone 7C-1 / BR1-III), Battery Room 2 - III Unit 2 (fie zone 7C-2 / BR2-III), Battery Room 1 - IV Unit 1 (fire zone 7D-1 / BR1-IV), and Battery Room 2 -IV Unit 2 (fire zone 7D-2 /

BR2-IV)

TDAFW-1), Turbine-Driven Auxiliary Feedwater Pump Room Unit 2 (fire zone 14A-2a / TDAFW-2), Motor-Driven Auxiliary Feedwater Pump Room Unit 1 (fire zone 14B-1a / MDAFW-1), and Motor-Driven Auxiliary Feedwater Pump Room Unit 2 (fire zone 14B-2a / MDAFW-2)

b. Findings

Introduction:

A self-revealing, non-cited violation of TS 5.4.1d was identified for the failure to adequately implement procedural requirements to reset a high pressure carbon dioxide (CO2) fire suppression system for the EDG pump room #1.

Description:

On March 7, 2010, the licensee received a control room alarm for low pilot pressure associated with the high pressure CO2 fire suppression system for the safety-related EDG fuel oil pump rooms. The inspectors reviewed the subsequent investigation which revealed that the nitrogen pilot bottle for zone 3 protecting fuel oil pump room #1 was isolated, which rendered this section of the fire suppression system inoperable and unable to automatically actuate. The inspectors found that there were problems re-performing a reset on zone 3 after completing that section of the procedure, performance test, 0-PT104.2, Fire Protection: High Pressure CO2 System, Zones 3 and 4, Revision 13, on March 4, 2010. Following multiple resets of zone 3, which were performed without procedure guidance, the nitrogen pilot bottle was left isolated. The inspectors also found that the procedure step to open the nitrogen pilot bottle outlet valve had a peer check signoff.

Analysis:

A self-revealing performance deficiency (PD) was identified for the failure to adequately implement fire protection procedure requirements of 0-PT-104.2 to ensure zone 3 was adequately reset. This PD had a credible impact on safety due to an inoperable fire suppression system for safety-related components. The PD was more than minor because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attributes of external events regarding fire due to the adverse impact on the capability of the fire suppression system and human performance due to the failure to properly implement a test procedure. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significant Determination Process, (SDP) the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance (Green) because core damage frequencies related to the fuel oil pump room #1 were less than 1E-6 and the duration of the system inoperability was less than three days. This finding involved the cross-cutting area of human performance, the component of work practices and the aspect of personnel do not proceed in the face of unexpected circumstances, H.4(a), because licensee personnel encountered problems with a CO2 system reset and failed to stop for proper guidance from supervision.

Enforcement:

TS 5.4.1d, requires in part, that written procedures shall be implemented covering the activities for the Fire Protection program implementation. Contrary to this, on March 7, 2010, the licensee failed to adequately implement fire protection procedure, 0-PT-104.2, which resulted in the isolation of a nitrogen pilot bottle with consequent inoperability of zone 3 of the high pressure CO2 system. Because this finding is of very low safety significance and because it was entered in the licensees corrective action program (CAP) as Condition Report (CR) 371298, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000338, 339/2010002-01, Inadequate Procedure Implementation Results in Inoperability of a Fire Suppression System.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors assessed the internal flooding vulnerability of the Unit 1 and 2 charging pumps in the auxiliary building with respect to adjacent safety-related areas to verify that the flood protection barriers and equipment were being maintained consistent with the UFSAR. The licensees corrective action documents were reviewed to verify that corrective actions with respect to flood-related items identified in condition reports were adequately addressed. The inspectors conducted a field survey of the selected areas to evaluate the adequacy of flood barriers, and floor drains to protect the equipment, as well as their overall material condition.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Biennial Review

a. Inspection Scope

The inspectors reviewed the facility operating history and associated documents in preparation for this inspection. During the week of January 11, 2010, the inspectors reviewed documentation, interviewed licensee personnel, and observed the administration of operating tests associated with the licensees operator requalification program. Each of the activities performed by the inspectors was done to assess the effectiveness of the facility licensee in implementing requalification requirements identified in 10 CFR Part 55, Operators Licenses. The evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification Program. The inspectors also evaluated the licensees simulation facility for adequacy for use in operator licensing examinations using ANSI/ANS-3.5-1998, American National Standard for Nuclear Power Plant Simulators for use in Operator Training and Examination. The inspectors observed two crews during the performance of the operating tests. Documentation reviewed included written examinations, Job Performance Measures, simulator scenarios, licensee procedures, on-shift records, simulator modification request records, simulator performance test records, operator feedback records, licensed operator qualification records, remediation plans, watchstanding records, and medical records. The records were inspected using the criteria listed in Inspection Procedure 71111.11. Documents reviewed during the inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.2 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed and observed the performance of a simulator scenario on February 16, 2010, that involved a failure of a pressurizer pressure channel, the rod control system, main generator voltage regulator, reactor protection system, and a reactor coolant system leak which required entry into an emergency action level for a site area emergency. The scenario required classifications and notifications that were counted for NRC performance indicator input.

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 the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions. The inspectors observed the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructor and reviewed with the operators.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the equipment issue listed below, the inspectors evaluated the effectiveness of the licensee's respective preventive and corrective maintenance. The inspectors performed walk-downs of the accessible portions of the systems, performed in-office reviews of procedures and evaluations, and held discussions with licensee staff. The inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65) using ER-AA-MRL-10, Maintenance Rule Program, Revision 4.

b. Findings

Safety-Related Breaker Cubicle Fire Issue

Introduction:

An unresolved item (URI) was identified by the inspectors relating to preventative maintenance of main contactors or motor starters for 480V circuit breakers.

Description:

On April 22, 2009, a licensee operator escorting several fire watch personnel to instruct them on which areas to patrol noticed an odor from an electrical fire located in the Unit 1 cable vault area. After an initial search was performed, the Shift Manager was notified and responded with additional operators who performed a search of the area. The source of the fire was identified at the safety-related breaker cubicle for 01-EE-BKR-1J1-2S-J1, D CRDM fan. The operators obtained a CO2 fire extinguisher, opened the cubicle and observed flame/smoke, and extinguished the fire with CO2. A visual examination of the breaker revealed that the molded case circuit breaker and main contactor had experienced the most damage. The licensee initiated CR331819 and the associated root cause evaluation (RCE) 000976 in accordance with their CAP.

The inspectors review of RCE000976, which was completed on February 9, 2010, following input from a vendor evaluation, is continuing with additional information required to determine if a performance deficiency exists and its respective significance.

This issue is identified as URI 05000338, 339/2010002-02, Safety-Related Breaker Cubicle Fire Issue.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated, as appropriate, the six activities listed below for the following:

(1) effectiveness of the risk assessments performed before maintenance activities were conducted;
(2) management of risk;
(3) upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and
(4) maintenance risk assessments and emergent work problems were adequately identified and resolved. The inspectors verified that the licensee was complying with the requirements of 10 CFR 50.65 (a)(4) and the data output from the licensees safety monitor associated with the risk profile of Units 1 and 2.
  • CR364799, No PRA assessment performed for operating a boom truck in the vicinity of the main steam and feedwater lines
  • Emergent work on breaker for 2-SI-MOV-2863A, A LHSI discharge to charging pumps
  • Emergent work to repair Unit 1 pressurizer low pressure channel III
  • Emergent work to evaluate radiator leak on 1H EDG
  • Unit 2 refueling outage (RFO) outage safety review
  • Emergent entry into 0-AP-89, Response to Grid Instability, Revision 6, due to elevated switchyard voltage

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed six operability evaluations, listed below, affecting risk-significant mitigating systems, to assess, as appropriate:

(1) the technical adequacy of the evaluations;
(2) whether continued system operability was warranted;
(3) whether other existing degraded conditions were considered as compensating measures;
(4) whether the compensatory measures, if involved, were in place, would work as intended, and were appropriately controlled; and
(5) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation and the risk significance in accordance with the SDP. The inspectors review included a verification that determinations of operability were made as specified by Procedure OP-AA-102, Operability Determination, Revision 5.
  • OD000283, Create OD to document operability of associated components, related to air operated valves using 20 hole diaphragms in 40 hole actuators.
  • OD000351, Evaluate discrepancies with 1-SI-R-603A and B to ensure 1-SI-P-1B remains operable
  • OD000361, OD to Engineering for 1-RS-MOVA regarding seismic
  • CR367957, NANN-NAPS 01-FC-E-1A Spent Fuel Pit Cooler Tube Plugging Evaluation, and respective Corrective Action (CA) 159773, NAF to Revise Necessary Calculations
  • OD000368, Determine operability of 1H EDG based on existing radiator tube coolant leak

b. Findings

The enforcement aspects relating to OD000353 are discussed in section 4OA5.3 of this report.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed cold weather procedure controlled temporary modifications for the Units 1 and 2 EDGs and the Station Blackout Generator to verify that the modifications did not affect system operability or availability as described by the TS and UFSAR. In addition, the inspectors verified that the temporary modifications were in accordance with Virginia Power Administrative Process (VPAP) -1403, Temporary Modifications, Revision 13, and the related work packages and that adequate controls were in place, procedures and drawings were updated, and post-installation tests verified the operability of the affected systems as applicable.

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed six post maintenance test procedures and/or test activities, as appropriate, for selected risk-significant mitigating systems listed below, to assess whether:

(1) the effect of testing on the plant 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 in accordance with licensee procedure VPAP-2003, Post Maintenance Testing Program, Revision 13.
  • WO 59102065357, Replace fuse block in breaker for 2-SI-MOV-2863A, A LHSI discharge to charging pumps
  • WO 59102071058, Test loop/replace required cards for 01-RC-LOOP-P-1457-1-LOOP, 1-RC-E-2, Pressurizer Protection Channel III Press
  • WO 59102051274, Rebuild valve operator/inspect gears on 1-CH-MOV-1286A

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety review (OSR) and contingency plans for the Unit 2 RFO, which began March 21, 2010, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors used Inspection Procedure 71111.20, Refueling and Other Outage Activities, to observe portions of the shutdown, cooldown, refueling, and maintenance activities to verify that the licensee maintained defense-in-depth commensurate with the OSR and applicable TS, and monitor the licensees fatigue management in accordance with 10 CFR 26. The inspectors monitored licensee controls over the outage activities listed below.

  • Licensee configuration management, including daily outage reports, to evaluate maintenance of defense-in-depth commensurate with the OSR for key safety functions and compliance with the applicable TS when taking equipment out of service.
  • Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.
  • Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and an accounting for instrument error.
  • Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities.
  • Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.
  • Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.
  • Controls over activities that could affect reactivity.
  • Licensee identification and resolution of problems related to refueling outage activities.
  • Licensee management of worker fatigue including waiver requests, self declarations and fatigue assessments as available.
  • Licensee control of refuelling activities.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the five surveillance tests listed below, the inspectors examined the test procedures, witnessed testing, or reviewed test records and data packages, to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable, and that the surveillance requirements of TS were met. The inspectors also determined whether the testing effectively demonstrated that the systems or components were operationally ready and capable of performing their intended safety functions.

In-Service Test:

  • 2-PT-64.4A, Casing Cooling Pump (2-RS-P-3A) Test, Revision 24
  • 1-PT-44.7, PORV Block Valves, Revision 24
  • 2-PT-14.2, Charging Pump 2-CH-P-1B, Revision 44
  • 1-PT-82.4A, 1H Diesel Generator Test (Start by ESF Actuation), Revision 44

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors performed a periodic review of the three following Unit 1 and 2 PIs to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspection was conducted in accordance with NRC Inspection Procedure 71151, Performance Indicator Verification. Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period January 1, 2009 through December 31, 2009. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

  • Unplanned Scrams per 7000 Critical Hours
  • Unplanned Scrams With Complications

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program:

As required by Inspection Procedure 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 a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily CR summaries and periodically attending daily CR Review Team meetings.

.2 Annual Samples

a. Inspection Scope

The inspectors selected CR364194 and its associated root cause evaluation (RCE)000998 for follow-up based on the potential adverse impact on the licensees ability to meet the emergency plans minimum staffing requirements. The inspectors reviewed the CR and RCE against the applicable performance attributes contained in NRC inspection procedure 71152, Problem Identification and Resolution.

b. Findings

Introduction:

An unresolved item (URI) was identified by the inspectors relating to maintenance of the required minimum onsite staffing in accordance with the licensees Emergency Plan.

Description:

On January 4, 2010, the licensee identified issues relating the Emergency Plan minimum staffing requirements for maintenance personnel. They subsequently initiated CR364194 in their CAP and the respective root cause evaluation, RCE000998, for corrective actions. The inspectors reviewed RCE000998 and require additional information from the licensee to appropriately characterize a performance deficiency which may be greater than minor. This issue is identified as URI 05000338, 339/2010002-03, Emergency Plan Minimum Staffing.

4OA3 Event Followup

.1 (Closed) Licensee Event Report (LER) 05000338/2009-003-00: Inoperable Reserve

Station Service Transformer Due to Improper Load Tap Changer Setting On November 15, 2009, with Units 1 and 2 operating in Mode 1 at 100% power, the licensee declared the A reserve station service transformer (RSST) inoperable in accordance with TS 3.8.1 due to an incorrect load tap changer (LTC) setting discovered by NRC inspectors. This human error caused a problem which prevented the A RSST from performing its design function in accordance with General Design Criteria 17 requirements during certain switchyard bus alignments following a Unit 2 reactor trip and occurred during a modification to replace the LTC in December, 2008. The licensee entered this problem in their CAP as CR358215 and subsequently corrected the LTC setting to return the RSST to an operable status. The B and C RSSTs were unaffected because the aforementioned modification only impacted the A RSST. The enforcement aspects of this issue are discussed in NRC Inspection Report 05000338, 339/2009007, Component Design Basis Inspection. This LER is closed.

.2 (Closed) Licensee Event Report (LER) 05000338/2009-004-00: Automatic Reactor Trip

and ESF Actuation Due to Human Performance Error During Testing On December 9, 2009, during a test of the H602 relay using procedure, NA-M-DCO-604, Relay Maintenance on TX #6, and CBs H602 and H3TL6, Revision 0, a licensee technician inadvertently closed the wrong knife switch which resulted in a trip of switchyard breaker L102. This caused a loss of power to the C RSST, a consequent loss of offsite power to the Unit 1 1H emergency bus and the Unit 2 2J emergency bus and auto-start of the respective EDG. Additionally, the Unit 2 G bus did not automatically fast transfer from the C RSST to the B RSST which resulted in the loss of the condenser circulating water pumps. The resulting low condenser vacuum caused a main turbine/reactor trip. The enforcement aspects of this event and the licensee corrective actions are discussed below. This LER is closed.

.2 a

Failure to Follow Procedures Results in Loss of Offsite Power to 1H and 2J Emergency Buses

Introduction:

A Green, self-revealing finding was identified for the licensees failure to follow or adhere to licensee procedures for switchyard relay maintenance, human performance and management oversight, which resulted in the loss of the TS required offsite circuit for the 1H and 2J emergency buses and the consequent auto-start of the respective EDGs.

Description:

On December 9, 2009, during a test of the H602 relay using switchyard maintenance procedure, NA-M-DCO-604, Relay Maintenance on TX #6, and CBs H602 and H3TL6, Revision 0, a licensee technician inadvertently closed an adjacent knife switch in addition to the correct knife switch, which resulted in a trip of switchyard breaker L102. This caused a loss of power to the C RSST and resulting loss of offsite power to the Unit 1 1H emergency bus and the Unit 2 2J emergency bus. Both of the respective EDGs started to restore power to the affected emergency buses. The licensee entered this event in their CAP as CR361280.

The inspectors reviewed the associated RCE000995, interviewed licensee personnel, and reviewed other related licensee documentation regarding work activities in the switchyard involving nuclear and transmission personnel. The inspectors identified the following procedures governing maintenance practices for switchyard work-related activities and noted the following specific, self-imposed standards:

  • CO-AGREE-000-IA1-5, Nuclear Switchyard Administrative Policy, Revision 5, section 1-9A, Basic Procedure Rules, states in part, Perform the work as specified in the procedure unless a Procedure Change is needed.
  • CO-AGREE-000-IA-3, Nuclear Switchyard Interface Agreement - Maintenance Protocol, Revision 1, section 5.4, Controls (refer to the Nuclear Switchyard Interface Agreement / Switchyard Control), step 5.4.6 states, Applicable procedures should be used with verbatim compliance and in accordance with the nuclear program for the Dominion Nuclear Procedure Adherence and Usage; step 11.3 states, Personnel assigned to work in the switchyard should receive site specific training equivalent to that of other supplemental personnel working in the plant and/or within the Owner Controlled Area (OCA). (For example, Human Performance, FME, Safety, Fitness for Duty, etc.); step 3.5 notes, DNAP-1907, Human Performance (HU) Program; step 3.3 notes, DNAP-0509, Dominion Nuclear Procedure Adherence and Usage; and step 4.5.3 delineates the level of management oversight.
  • DNAP-0509, Dominion Nuclear Procedure Adherence and Usage, Revision 12, section 5.2, Responsibilities, step 5.2.2, Station Personnel, subpart a. states, All personnel who use procedures are responsible for following policies on procedure use and adherence during activities in which they are involved.
  • DNAP-1907, Human Performance (HU) Program, Revision 11, Attachments 5, 6 and 8 for self-checking, peer checking, and procedure compliance, respectively, provide directions for the required human performance necessary to prevent the manipulation of the incorrect knife switch.

The inspectors concluded that the available self-imposed standards regarding procedural requirements were not followed with respect to performance of the actual work, the human performance standards, and the required level of management oversight considering the risk of losing TS required offsite power supply.

Analysis:

The inspectors determined that the failure to follow the aforementioned procedures to successfully accomplish nuclear switchyard relay maintenance was a PD.

The PD had a credible impact on safety due to the loss of a TS required offsite power supply and the start of the respective EDGs to restore power to the affected emergency buses. The inspectors determined the PD was more than minor because it impacted the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations, and the related attribute of human performance due to human error in the implementation of a non-safety nuclear switchyard related procedures. In accordance with NRC IMC 0609, Significant Determination Process, the inspectors performed a Phase 1 risk analysis and determined the finding was of very low safety significance (Green) because the finding did contribute to a reactor trip but did not contribute to the likelihood that mitigation equipment or functions would not be available. This finding involved the cross-cutting area of human performance, the component of the work practices, and the aspect of personnel use human error prevention techniques commensurate with risk for the assigned task, H.4(a), because a licensee technicians failure to use proper human error prevention techniques resulted in a partial loss of offsite power on both units.

Enforcement:

Enforcement action does not apply because the finding did not involve a violation of regulatory requirements. NA-M-DCO-604 states the requirements for relay maintenance; CO-AGREE-000-IA-3 and 5 state the requirements for procedure adherence and management oversight; and DNAP-0509 and 1907 state the requirements for procedure adherence and human performance respectively. Contrary to the above, on December 9, 2009, the licensee failed to follow the aforementioned procedures resulting in the loss of the TS required offsite circuit for the 1H and 2J emergency buses and the consequent auto-start of the respective EDGs. Because this finding does not involve a violation of regulatory requirements, has very low safety significance, and has been entered into the licensees CAP as CR361280, it is identified as FIN 05000338, 339/2010002-04, Failure to Follow Procedures Results in Loss of Offsite Power to 1H and 2J Emergency Buses.

.2 b Failure to Establish an Adequate Procedure for Undervoltage Timers Results in Main

Turbine/Reactor Trip

Introduction:

A Green, self-revealing finding was identified for the licensees failure to establish an adequate procedure for calibration of under voltage timers which resulted in the failure of the Unit 2 G bus to fast transfer from C RSST to the B RSST and consequent loss of main turbine condenser vacuum causing a main turbine/reactor trip.

Description:

On December 9, 2009, during a test of the H602 relay using switchyard maintenance procedure, NA-M-DCO-604, Relay Maintenance on TX #6, and CBs H602 and H3TL6, Revision 0, a licensee technician inadvertently closed the wrong knife switch in addition to the correct knife switch, which resulted in a trip of switchyard breaker L102. This caused a loss of power to the C RSST and a consequent loss of power to the Unit 2 G bus. However, due to improper calibration of the 2G bus undervoltage timers, a fast transfer of the bus to the B RSST was delayed resulting in the trip of the main turbine condenser circulating water pumps, loss of condenser vacuum, and a main turbine/reactor trip. The licensee entered this event in their CAP as CR361280. The inspectors reviewed the associated RCE000995, interviewed licensee personnel, and reviewed other related licensee documentation regarding work activities in the switchyard involving nuclear and transmission personnel.

The inspectors reviewed licensee administrative procedure, CO-AGREE-000-IA1-5, Nuclear Switchyard Administrative Policy, Revision 5, of which section 1-6, Which Switchyard Activities Must Be Procedurally Controlled, states, A management directive was issued requiring the use of written procedures for construction and maintenance activities, performed on nuclear switchyard equipment which could pose a risk of causing a loss of off-site power to station loads or an inadvertent transient to the power system. These activities must be procedurally controlled. The inspectors also noted that the existing practice of calibrating the undervoltage relays involved a procedure section, General Electric type SAM11 timing relays, from Control Operations Relay Test Procedures manual, Revision 1, effective May 4, 1995, which, due to no specific guidance, allowed up to four different methods utilizing different test equipment. One of these methods consistently resulted in as-left settings outside of the acceptable band.

The inspectors concluded that the self-imposed standards regarding activities requiring procedures as identified in CO-AGREE-000-IA1-5 were not met with respect to the establishment of an adequate procedure to successfully accomplish calibration of the undervoltage relays.

Analysis:

A self-revealing PD involving a Unit 2 turbine trip on loss of condenser vacuum was identified and resulted from the failure to establish an adequate procedure for the calibration of the time delay relays associated with the G bus cross-tie fast transfer circuit. This PD was the result of the failure to establish an adequate procedure for calibration of fast transfer relays. Specifically, licensee did not have mandated documentation in place to require technicians to use a proven method for timer calibration. The cause of PD was reasonably within the licensees ability to foresee and correct. Specifically, the NRC previously issued NCV 05000338/2008002-03, Inoperability of '1H' EDG Due to Failure to Adequately Establish Procedural Requirements for Protective Relay Testing, which involved a lack of procedural guidance and reliance of worker skill of the craft to successfully complete the activity.

The PD adversely impacted the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations and was related to the attribute of procedure quality because the correct timing relay calibration methodology was not documented in a procedure. In accordance with NRC IMC 0609, Significant Determination Process, a phase 1 SDP screening determined that a phase 2 evaluation was required as the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. A phase 3 SDP evaluation was performed by a regional SRA since the North Anna Risk Informed Inspection Notebook did not have the level of detail to accurately assess the finding. The NRCs SPAR model was utilized to assess the risk significance of the finding modeling the impact of a loss of power to the 2G Bus without the fast transfer circuit available resulting in a reactor trip due to low condenser vacuum. The dominant sequence was a reactor trip without the condenser heat sink, caused by loss of power to the 2G bus with a failure of the cross-tie fast transfer circuit, with subsequent failures of main feedwater, auxiliary feedwater, and failure of feed and bleed cooling leading to core damage. The evaluation determined that the risk increase in core damage frequency was <1E-6 per year, a finding of very low safety significance, Green. This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish an accurate procedure to ensure correct calibration of under voltage timers.

Enforcement:

Enforcement action does not apply because the finding did not involve a violation of regulatory requirements. CO-AGREE-000-IA1-5 states in part that construction and maintenance activities, performed on nuclear switchyard equipment which could pose a risk of causing a loss of off-site power to station loads or an inadvertent transient to the power system must be procedurally controlled. Contrary to the above, on December 9, 2009, the licensee failed to establish a procedure to successfully accomplish calibration of the undervoltage relays which caused a loss of offsite power to the main condenser circulating water pumps, a consequent turbine/reactor trip and a transient imposed to the power system. Because this finding does not involve a violation of regulatory requirements, has very low safety significance, and has been entered into the licensees CAP as CR361280, it is identified as FIN 05000339/2010002-05, Failure to Establish a Procedure for Undervoltage Timers Results in Main Turbine/Reactor Trip.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with the licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.2 Closed: Unresolved Item (URI)05000338/2009004-04, LSHI/ORS Pump Discharge

Piping Interference

Introduction:

A non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified by the NRC for the failure to accomplish the installation of low head safety injection (LHSI) and outside recirculation spray (ORS)pump discharge piping in accordance with prescribed drawings which resulted in piping interference involving hard contact between the aforementioned system piping.

Description:

The inspectors had previously opened URI 05000338/2009004-04, LSHI/ORS Pump Discharge Piping Interference, in NRC Integrated Inspection Report 05000338/2009004 and 05000339/2009004, based on the identification of piping interference involving hard contact between the Unit 1 A train LHSI pump and ORS pump discharge piping by the inspectors on August 7, 2009. The associated drawings, 11715-ECI-104A and 11715-ECI-104D, for LHSI and ORS piping respectively, do not allow contact between the system piping.

The inspectors and NRC staff from the regional and national headquarters office reviewed the licensees operability determination, OD000314, which incorporated engineering transmittal, ET-CEM-09-0006, Input to Operability Determination OD000314 for CR343774. The staff and inspectors concluded that the piping configuration resulted in an operable but not fully qualified condition. The inspectors found that there was a reduction in calculated design margin of approximately 30% and that based on a review of relative piping movements during the worst case thermal and seismic interactions, a clearance of approximately 1.25 inches would be necessary to eliminate all potential for contact.

Analysis:

A PD was identified by the NRC for the failure to adequately to accomplish the installation of LHSI and ORS pump discharge piping in accordance with prescribed drawings which resulted in hard contact between the aforementioned system piping.

This PD had a credible impact on safety due to the loss of design margin resulting in a reasonable doubt regarding long term reliability. The PD was more than minor because if left uncorrected it would have the potential to result in a more significant event involving Unit 1 A train LHSI pump discharge nozzle failure from excessive stress. In accordance with NRC IMC 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green due to a design deficiency confirmed not to result in a loss of operability or functionality. The finding had no cross-cutting aspects due to its legacy nature.

Enforcement:

10 CFR 50, Appendix B, Criterion V, requires in part, that activities affecting quality shall be accomplished in accordance with prescribed drawings.

Contrary to this, on August 7, 2009 the inspectors identified that the licensee failed to adequately accomplish the installation of Unit 1 A train LHSI and ORS pump discharge piping in accordance with documented drawings. Consequently, piping interference involving hard contact and a loss of design margin resulted in an operable but not fully qualified condition. Because this finding is of very low safety significance and because it was entered in the licensees CAP as CR343744, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000338/2010002-06, Failure to Install LSHI/ORS Pump Discharge Piping in accordance with Prescribed Drawings.

.3 Closed: URI 05000338, 339/2009005-02, Feedwater Pipe Support Issues

Introduction:

A Green, non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified by the NRC for the failure to establish an adequate post-modification test program for piping supports affected by piping design changes (modifications).

Description:

The inspectors had previously opened URI 05000338, 339/2009005-02, Feedwater Pipe Support Issues, in NRC Integrated Inspection Report 05000338/2009005 and 05000339/2009005, based on the identification of a Unit 1 C feedwater (FW) pipe support, 1-FW-PH-13, involving no contact (floating) between the floor-mounted section of the support and the section attached to the pipe. An extent of condition review was performed by the licensee and additional problems were identified with Unit 2 A feedwater pipe supports, 2-FW-PH-18 and 2-FW-PH-20. The inspectors conclusion that issues on both units were caused by piping modifications involving feedwater venturi cleaning and installation of new ultrasonic feedwater flow instrumentation.

On January 11, 2010, the inspectors identified an AFW pipe support, 1-WAPD-H-23, on the B train motor driven AFW pump discharge piping that was floating. The licensee initiated CR364805 and OD000353 for the affected AFW train. OD000353 was submitted to NRC regional inspectors for independent review. The conclusion of operable but not fully qualified was verified. Since this piping was associated with a modification involving full flow recirculation piping changes implemented by design changes 89-18 and 89-19 for Units 1 and 2, respectively, in the early 1990s, the inspector also reviewed Unit 2 piping and on January 14, 2010, identified AFW full flow recirculation piping support, H-1008 (2-FW-PH-R-451.1008), in which the pipe was floating in the vertical direction. Consequently, the licensee initiated CR365294, performed extent of review inspections of the Unit 1 & 2 AFW system piping and identified additional piping support issues. OD000353 was revised to incorporate the additional problems with the same conclusion of operable but not fully qualified.

The inspectors concluded that the existing programmatic processes involving work activities on safety-related and important to safety piping and piping supports require corrective actions to ensure adequate post-modification or post-maintenance testing.

The licensee has established CA162077 to review procedural guidance for restoring structures, systems, and components and implement appropriate corrective actions.

Analysis:

The inspectors determined that the failure to establish an adequate post-modification test program for piping supports affected by piping modifications as required by 10 CFR 50, Appendix B, Criterion III, was a PD. This PD had a credible impact on safety due to a programmatic deficiency that resulted in safety-related piping supports adversely affected by modifications. The PD was more than minor because if left uncorrected it would have the potential to result in a more significant event involving inoperable, unidentified safety-related piping supports with consequent adverse impact on the respective system during a seismic event. In accordance with NRC IMC 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green due to a design deficiency confirmed not to result in a loss of operability or functionality. This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish up-to-date program procedures to ensure adequate post-modification testing of piping supports.

Enforcement:

10 CFR 50, Appendix B, Criterion III, requires in part, that design control measures shall provide for checking the adequacy of design by the performance of a suitable testing program. Contrary to this, on January 11, 2010 the inspectors identified that the licensee failed to adequately establish a post-modification test program for safety-related AFW piping supports affected by piping modifications. Because this finding is of very low safety significance and because it was entered in the licensees CAP as CR357450 and CR365294, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000338/2010002-07, Failure to Establish an Adequate Post-Modification Test Program for Piping Supports.

.4 Closed: URI 05000338, 339/2009005-01, Inspection of Underground Cables

The inspectors had previously opened URI 05000338, 339/2009005-01 in NRC Integrated Inspection Report 05000338/2009005 and 05000339/2009005 based on inspectors identified issues related to the adequacy of the licensees inspections for electrical cable vaults. The inspectors performed an extensive review of the licensees electrical cable vault inspection procedure, records of completed inspections, and corrective actions relating to the issues identified by the inspectors. The inspectors reviewed licensee procedure 0-MPM-1207-04, Annual Pumping of Security and Electrical Cable Vaults, Revision 2 and identified that the procedure contained steps, such as inspecting for unusually warm conductors, which could not be completed from grade level. As discussed in URI 05000338, 339/2009005-01, the inspectors noted that the licensees inspection for each of the vault inspections observed were conducted at grade level while viewing the vault equipment and supports via the vault manhole. The licensee initiated condition report CR362370 for an NRC-identified issue relating to proper inspection of risk significant cables contained in underground vaults. Corrective action taken by the licensee included re-inspection of the cable vaults covered under 0-MPM-1207-04; no degraded conditions were identified. The inspectors concluded that the failure to conduct cable vault inspections in accordance with 0-MPM-1207-04 was a performance deficiency. The inspectors reviewed IMC 0612, Appendix B and determined that the performance deficiency was minor because there were no safety consequences. This URI is closed.

4OA6 Meetings, Including Exit

.1 Quarterly Exit Meeting Summary

On April 20 and May 6, 2010, the resident inspector presented the inspection results to Mr. Larry Lane and other members of the staff, who acknowledged the findings. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Licensed Operator Requalification Biennial Inspection Exit Meeting

An exit meeting was conducted on January 14, 2010, to discuss the findings of this inspection. The inspectors confirmed that no proprietary information was retained during this inspection.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Anthes, Manager, Nuclear Maintenance
M. Crist, Plant Manager
R. Evans, Manager, Radiological Protection and Chemistry
E. Hendrixson, Director, Station Safety and Licensing
T. Huber, Director, Nuclear Engineering
S. Hughes, Manager, Nuclear Operations
P. Kemp, Supervisor, Station Licensing
L. Lane, Site Vice President
G. Lear, Manager, Organizational Effectiveness
T. Maddy, Manager, Nuclear Protection Services
G. Marshall, Manager, Nuclear Outage and Planning
C. McClain, Manager, Nuclear Training
F. Mladen, Manager, Nuclear Site Services
B. Morrison, Supervisor Nuclear Engineering
J. Scott, Supervisor, Nuclear Training (operations)
W. Shura, Supervisor Nuclear Training
R. Wesley, Supervisor of Shift Operations

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000338/2010002-02 URI Safety-Related Breaker Cubicle Fire Issue (Section 1R12)
05000338, 339/2010002-03 URI Emergency Plan Minimum Staffing (Section 4OA2.2)

Opened and Closed

05000338, 339/2010002-01 NCV Inadequate Procedure Implementation Results in Inoperability of a Fire Suppression System (Section 1R05)
05000338, 339/2010002-04 FIN Failure to Follow Procedures Results in Loss of Offsite Power to 1H and 2J Emergency Buses (Section 4OA3.2a)
05000339/2010002-05 FIN Failure to Establish a Procedure for Undervoltage Timers Results in Main Turbine/Reactor Trip (Section 4OA3.2b)
05000338/2010002-06 NCV Failure to Install LSHI/ORS Pump Discharge Piping in accordance with Prescribed Drawings (Section 4OA5.2)
05000338/2010002-07 NCV Failure to Establish an Adequate Post-Modification Test Program for Piping Supports (Section 4OA5.3)

Closed

05000338/2009-003-00 LER Inoperable Reserve Station Service Transformer Due to Improper Load Tap Changer Setting (Section 4OA3.1)
05000338/2009-004-00 LER Automatic Reactor Trip and ESF Actuation due to Human Performance Error during Testing (Section 4OA3.2)
05000338/2009004-04 URI LSHI/ORS Pump Discharge Piping Interference (Section 4OA5.2)
05000338, 339/2009005-02 URI Feedwater Pipe Support Issues (Section 4OA5.3)
05000338, 339/2009005-01 URI Inspection of Underground Cables (Section 4OA5.4)

LIST OF DOCUMENTS REVIEWED

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