IR 05000269/2013004

IR 05000269-13-004, 05000270-13-004 & 05000287-13-004; 07/01/2013 09/30/2013; Oconee Nuclear Station Units 1, 2 and 3; and Emergency Preparedness IR 05000269-13-501, 05000270-13-501 & 05000287-13-501

ML13318A936
Person / Time
Site:	Oconee
Issue date:	11/14/2013
From:	Gerald Mccoy NRC/RGN-II/DRP/RPB1
To:	Batson S Duke Energy Corp
References
IR-13-004, IR-13-501
Download: ML13318A936 (35)

Text

UNITED STATES ber 14, 2013

SUBJECT:

OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000269/2013004, 05000270/2013004, 05000287/2013004 AND EMERGENCY PREPAREDNESS INSPECTION REPORT 05000269/2013501, 05000270/2013501, 05000287/2013501

Dear Mr. Batson:

On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Oconee Nuclear Station Units 1, 2, and 3. On October 3, 2013, the NRC inspectors discussed the results of this inspection with you and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented two findings of very low safety significance (Green) in this report of which both involved violations of NRC requirements. One of these violations was also determined to be a Severity Level IV violation under the traditional enforcement process.

Further, inspectors documented two licensee-identified violations which were determined to be of very low safety significance. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. 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 Oconee. If you disagree with a cross-cutting aspect assignment 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 Oconee.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "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 NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-269, 50-270, 50-287 License Nos.: DPR-38, DPR-47, DPR-55

Enclosure:

NRC Integrated Inspection Report 05000269/2013004, 05000270/2013004, 05000287/2013004 and 5000269/2013501, 05000270/2013501, 05000287/2013501 w/Attachment: Supplementary Information

REGION II==

Docket Nos: 50-269, 50-270, 50-287 License Nos: DPR-38, DPR-47, DPR-55 Report Nos: 05000269/2013004, 05000270/2013004, 05000287/2013004 05000269/2013501, 05000270/2013501, 05000287/2013501 Licensee: Duke Energy Carolinas, LLC Facility: Oconee Nuclear Station, Units 1, 2 and 3 Location: Seneca, SC 29672 Dates: July 1, 2013, through September 30, 2013 Inspectors: E. Crowe, Senior Resident Inspector K. Ellis, Resident Inspector G. Croon, Resident Inspector N. Childs, Resident Inspector M. Thomas, Senior Reactor Inspector (Section 1R05)

G. MacDonald, Senior Reactor Analyst (Section 1R05)

R. Rodriguez, Senior Project Inspector/Team Leader (Section 1R05)

P. Braxton, Reactor Inspector (Section 1R05)

G. Crespo, Senior Construction Inspector (Section 1R17)

T. Fanelli, Reactor Inspector (Section 1R17)

M. Speck, Senior Emergency Preparedness Inspector (Sections 1EP2, 1EP3, 1EP5)

S. Sanchez, Senior Emergency Preparedness Inspector (Sections 4OA1, 4OA6)

C. Rapp, Senior Project Engineer (Section 4OA3)

Approved by: Gerald J. McCoy, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000269/2013-004, 05000270/2013-004, 05000287/2013-004; 07/01/2013 - 09/30/2013;

Oconee Nuclear Station Units 1, 2 and 3; Fire Protection IR 05000269/2013-501; 05000270/2013-501; 05000287/2013501; 09/16-19/2013; Oconee Nuclear Station, Units 1, 2 and 3; Emergency Preparedness Baseline Inspection The report covered a three-month period of inspection by the resident inspectors and five region-based inspectors. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process revision 4.

Cornerstone: Mitigating Systems

Green.

An NRC-identified non-cited violation (NCV) of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805), Section 2.4.3.2, was identified for the licensees failure to address in their fire probabilistic safety analysis (also referred to as fire probabilistic risk assessment (PRA)) the risk contributions associated with all potentially risk-significant fire scenarios for a given fire area/fire zone. The licensee entered the issue in the corrective action program (CAP) as Problem Investigation Program (PIP) O-13-08059 and PIP O-13-08061 and implemented fire watches as compensatory measures.

The licensees failure to comply with the requirements of 10 CFR 50.48(c) and NFPA 805 was a performance deficiency (PD). The PD was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e., fire), and adversely affected the cornerstone because the excluded ignition sources had the potential to impact the ability to achieve safe shutdown.

The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP), and determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, review was required. The inspectors were unable to screen out this finding in the SDP Phase 1 or Phase 2. A senior reactor analyst (SRA) performed a Phase 3 SDP analysis and determined that this finding was of very low safety significance (i.e., Green) because the fire damage would not result in loss of offsite power to the main feeder buses which enabled feed and bleed. The risk was further mitigated by the recovery potential for emergency feedwater (EFW) by local manual control of the steam driven EFW pump and the ability to crosstie EFW to Unit 1 from the other units. The cause of this finding was determined to have a cross-cutting aspect of H.4(c) in the Work Practices component of the Human Performance area because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported. (Section 1R05.2)

Green.

An NRC-identified Green finding and associated traditional enforcement Severity Level IV non-cited violation of Oconee Nuclear Station Renewed Facility Operating License Condition 3.D for Units 1, 2, and 3 were identified for the licensees failure to implement and maintain in effect all provisions of the approved fire protection program (FPP) that comply with 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805.

The licensee made a change to the approved FPP involving control of combustible materials when the definition of transient fire loads was revised to exclude fire retardant scaffolding materials as transient fire loads, which would not require the licensee to track these items as combustible fire loads. The licensee also failed to submit the FPP change to the NRC for review and approval prior to implementation which impacted the ability of the NRC to perform its regulatory oversight function. The licensee entered this issue into the corrective action program as Problem Investigation Program O-13-08584 and implemented compensatory measures in the form of combustible tracking impairments and fire watches in the high safety significant fire zones which contained the scaffolding.

Failure to comply with Oconee Operating License Condition 3.D was a performance deficiency (PD). This PD was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e. fire), and it adversely affected the cornerstone objective in that the change to the FPP had the potential to adversely affect the ability to achieve and maintain safe and stable plant conditions. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), and determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, review was required. The inspectors determined that a systematic plant-wide assessment effort was beyond the intended scope of the fire protection Phase 1 and Phase 2 SDP.

Therefore, a Phase 3 SDP risk analysis was performed by a regional senior reactor analyst (SRA). The fire risk associated with the fire retardant treated wood (FRTW) scaffolding material was mitigated by the FRTW burning characteristics and the few scaffold locations which were in proximity to valid ignition sources and safe shutdown (SSD) target sets. The SRA determined that the risk increase associated with the FRTW scaffolding materials represented an increase in annual core damage frequency of <1E-6, a finding of very low safety significance. Additionally, the licensees failure to submit the FPP change to the NRC for review was determined to be a Severity Level IV traditional enforcement violation in accordance with the NRC Enforcement Policy because it impacted the ability of the NRC to perform its regulatory oversight function. The cause of this finding was determined to have a cross-cutting aspect of H.1 (b) in the Decision-Making component of the Human Performance area because the licensee used non-conservative assumptions in the decision making associated with this FPP change. (Section 1R05.2)

Violations of very low safety or security significance that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. These violations and associated CAP tracking numbers are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at approximately 100 percent rated thermal power (RTP) during the inspection period.

Unit 2 operated at approximately 100 percent RTP during the inspection period.

Unit 3 operated at approximately 100 percent RTP during the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Impending Adverse Weather Conditions: The inspectors reviewed the licensees preparation for impeding seasonal thunderstorms and potential high winds to ensure equipment used in the licensees procedures was capable of functioning as intended.

The inspectors also evaluated site conditions to ensure that potential missiles had been properly addressed to ensure that safety related equipment would not be adversely affected. Risk significant systems and area reviewed included the standby shutdown facility (SSF), the auxiliary building, portions of the turbine building and the essential siphon vacuum building. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown: The inspectors performed the five partial walkdowns listed below to assess the operability of redundant or diverse trains and components when safety-related equipment was inoperable or out-of-service and to identify any discrepancies that could impact the function of the system potentially increasing overall risk. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers, valves, and support equipment to determine if they were correctly aligned to support system operation. The inspectors reviewed protected equipment sheets, maintenance plans, and system drawings to determine if the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP. Documents reviewed are listed in the Attachment.

• 3A reactor building spray (RBS) train during planned maintenance of 3B RBS pump

• Electrical distribution and Turbine Driven Emergency Feedwater (TDEFW) on all three units during SSF inoperability

• 2A low pressure injection (LPI) train during planned maintenance of 2B LPI pump

• 1A and 1B EFW during planned maintenance of TDEFW

• Electrical distribution and TDEFW on all three units during Keowee Hydro Unit 2 86E2 lockout activation

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Fire Area Tours

a. Inspection Scope

The inspectors walked down accessible portions of the four plant areas listed below to assess the licensees control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspectors observed the fire protection suppression and detection equipment to determine if any conditions or deficiencies existed which could impair the operability of that equipment. The inspectors selected the areas based on a review of the licensees safe shutdown analysis probabilistic risk assessment and sensitivity studies for fire-related core damage accident sequences. Documents reviewed are listed in the Attachment.

• Unit 3 cable room (Zone 101)

• Unit 1 east penetration room (Zone 108)

• Unit 1 west penetration room (Zone 107)

• Unit 1 & 2 control room (Zone 110)

b. Findings

No findings were identified.

.2 Significance Determination of Apparent Violations (AVs)

a. Inspection Scope

Two AVs and one unresolved item (URI) were documented in the ONS 2013 triennial fire protection inspection (TFPI) report (ADAMS Accession Number ML13268A071).

Subsequently, the licensee provided additional information. The inspectors reviewed the additional information to determine the significance of these issues.

.1 Apparent Violation (AV)05000269/2013007-02, Failure to Identify Ignition Sources and

Targets During Initial Fire Scenario Development

Introduction:

An NRC-identified Green NCV of 10 CFR 50.48(c) and NFPA 805, Section 2.4.3.2, was identified for the licensees failure to address in their fire probabilistic safety analysis (also referred to as fire PRA) the risk contributions associated with all potentially risk-significant fire scenarios for a given fire area (FA)/fire zone (FZ). The licensee entered the issue in the corrective action program as PIP O-13-08059 and PIP O-13-08061 and implemented fire watches as compensatory measures.

Description:

During the walkdown of the Unit 1 Cable Room fire scenario AB106N1, the inspectors identified several electrical cabinets that the licensee screened out as being well-sealed and/or were excluded from the evaluation as ignition sources without adequate documentation to support the basis for exclusion. The inspectors asked the licensee to open electrical control cabinets and found that the control rod drive system logic cabinet was not well-sealed because of an open/unsealed penetration on top. The inspectors questioned the licensees justification for excluding the ventilated cabinet from the fire scenarios. The licensee informed the inspectors that they were not aware of the open/unsealed penetration because the cabinet was not opened during their initial fire scenario development walkdown. Additionally, the inspectors found other electrical cabinets that were not well sealed but were excluded from the fire scenario development and a 600V breaker that was susceptible to high energy arching faults excluded from the fire scenario without adequate technical basis for being excluded.

Analysis:

The licensees failure to comply with the requirements of 10 CFR 50.48(c) and NFPA 805 to address the risk contributions associated with all potentially risk significant fire scenarios (by incorrectly screening out electrical cabinets that were considered as well-sealed and/or excluded without adequate technical basis) was a PD. This PD was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e., fire), and adversely affected the cornerstone objective because the excluded ignition sources had the potential to impact the ability to achieve safe shutdown due to the impact on main and emergency feedwater. The finding was screened in accordance with NRC IMC 0609, dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, review was required because it affected the ability to reach and maintain safe and stable conditions in the event of a fire. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F, and performed Phase 1 and Phase 2 SDP screening assessments using IMC 0609, Appendix F, Attachments 1 and 2, and were unable to screen out this finding in the SDP Phase 1 or Phase 2 (i.e., the finding preliminarily had a delta core damage frequency > 1E-6).

A Phase 3 SDP evaluation to estimate the fire risk increase for this finding was performed by a regional SRA in accordance with the guidance in NRC IMC 0609 Appendix F, and NUREG/CR6850, Fire PRA Methodology for Nuclear Power Facilities, Revisions 0 and 1. The evaluation estimated the fire risk of Unit 1 Control Rod Drive (CRD) Control Cabinets IFC-1 and IFC-2 and the Unit 1CRD Switchgear Breaker Cabinets. Cabinets IFC-1 and IFC-2 were modeled as a single cabinet with thermal fires of 200kw and 650kw heat release rate (HRR) intensity. The CRD Switchgear was modeled as 2 vertical 600V cabinets with a high energy arc fault (HEAF) fire scenario and a 200kw HRR thermal fire scenario. The major analysis assumptions included:

target cables were assumed to follow thermoset cable damage criteria; a one year exposure period was assumed; thermal fire ignition frequencies (IF) were obtained from the Oconee NFPA 805 project data while the HEAF IF data was from NRC IMC 0609 Appendix F Attachment 1; no credit given for the Unit 1 Cable Room manually initiated fire sprinkler system as the cable damage time preceded the manual activation time for the sprinkler system; and the conditional core damage probability data for the fire damage scenarios was from the Oconee fire PRA. The dominant sequence was a challenging fire in the IFC-1 and IFC-2 cabinet which would result in a reactor trip, a loss of main feedwater and EFW, implementation of feed and bleed with a failure of a pressurizer safety valve to close and failure of the operator to implement low pressure recirculation leading to core damage. The fire damage did not result in loss of offsite power to the main feeder buses which enabled feed and bleed. The risk was further mitigated by the recovery potential for EFW by local manual control of the steam driven EFW pump and the ability to crosstie EFW to Unit 1 from the other units. The Phase 3 SDP analysis determined that risk increase associated with the finding was an increase in core damage frequency of <1E-6/year, a finding of very low safety significance (Green).

The cause of this finding was determined to have a cross-cutting aspect of H.4

(c) in the Work Practices component of the Human Performance area because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported.

Enforcement:

Oconee Nuclear Station, Unit 1 Renewed Facility Operating License Condition 3.D required the licensee to implement and maintain in effect all provisions of the approved FPP that complied with 10 CFR 50.48 (c), National Fire Protection Association Standard NFPA 805, as specified in the NRC safety evaluation report (SER) dated December 29, 2010. NFPA 805 Section 2.4.3.2 stated that the Fire PRA evaluation shall address the risk contribution associated with all potentially risk-significant fire scenarios.

Contrary to the above, since April 2012, the licensee failed to address the risk contribution of all ignition sources and targets associated with potentially risk significant fire scenarios during the initial fire scenario development resulting in potentially underestimating post-fire safe shutdown risk. The licensee entered this issue into the corrective action program as PIPs O-13-08059 and O-13-08061 to update the Fire PRA scenarios to explicitly describe the treatment of the questionable electrical cabinets and cable trays in the ZOI. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. For administrative purposes, AV 05000269/2013007-02 is updated as NCV 05000269/2013007-02, Failure to Identify Ignition Sources and Targets During Initial Fire Scenario Development.

.2 AV 05000269, 270, 287/2013007-03, Fire Protection Program Change did not Meet

Oconee License Condition Requirements for NFPA 805 Chapter Three

Introduction:

An NRC-identified Green finding and associated traditional enforcement Severity Level IV NCV of ONS Renewed Facility Operating License Condition 3.D for Units 1, 2, and 3 were identified for the licensees failure to implement and maintain in effect all provisions of the approved FPP that comply with 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805. The licensee made a change to the approved FPP involving control of combustible materials when the definition of transient fire loads was revised to exclude FRTW scaffolding materials as transient fire loads, which would not require the licensee to track these items as combustible fire loads. The licensee also failed to submit the FPP change to the NRC for review and approval prior to implementation which impacted the ability of the NRC to perform its regulatory oversight function.

Description:

During walkdowns of the selected FAs/FZs the inspectors noted that many elevated scaffold work platforms were constructed of FRTW planking or plywood.

Nuclear System Directive (NSD) 313, Control of Transient Fire Loads, stated, in part, that the following items are not considered transient fire loads when used as indicated.

• FRTW that is installed as part of in-place scaffold or temporary damming.

• Fire retardant mesh/netting that is installed as part of in-place scaffolding or FME installation.

• In place/installed fire retardant plastic sheeting that meets the requirements of NFPA 701 large scale test or equivalent.

These materials were excluded from various ONS offset and quantity restrictions associated with transient fire loads. The document revision section for Revision 10 to NSD 313 dated September 27, 2011, stated; Revised the definition of Transient Fire Load to exclude the fire retardant treated wood installed as part of in-place scaffolding, fire retardant mesh/netting installed as part of in-place scaffolding and in-place fire retardant plastics. These were previously exempt from approval areas. It was always the intent to exempt these items from consideration as a Transient Fire Load due to their difficulty to ignite and low flame spread rating. The inspectors noted that neither of these categories of materials met the NFPA 805 definition of a Non-Combustible Material, which stated; A material that, in the form in which it is used and under the conditions anticipated, will not ignite, burn, support combustion or release flammable vapors when subjected to heat.

The inspectors requested the FPP change evaluation which justified the changes to the combustible control program procedure (NSD 313) of the approved FPP which excluded these items from the program. The licensee responded that no NSD 320, Guidance for Performing Licensing Review of Proposed Changes to the Fire Protection Program, change evaluation was performed at the time of the NSD 313 procedure revision, and that a subsequent audit identified the discrepancy (documented in PIP G-11-01663, dated November 14, 2011) which resulted in the NSD 320 change evaluation being performed after the fact. The inspectors reviewed the after the fact change evaluation (documented on NSD 320, Form 320-1, Fire Protection Program Change Review Form) which stated that the proposed change did not adversely affect the ability to achieve and maintain SSD in the event of a fire and NRC approval of the change was not required because the proposed change satisfied applicable fire protection regulatory requirements and the proposed change satisfied the fire protection licensing basis.

Form 320-1 evaluation question Does the proposed change meet the requirements of NFPA 805, Chapter 3? was answered not applicable (N/A).

The inspectors concluded that the after the fact NSD 320 change evaluation was inadequate because it failed to recognize that such a program element self-approval did not meet ONS Fire Protection License Condition 3.D. The license condition states, in part, that the licensee is not allowed to self-approve quantitative risk-informed fire protection program changes except those implementation items needing a plant change evaluation as part of the Transition License Condition or NFPA 805 Chapter 3 element Section(s) 3.8 through 3.11 only. The change to the transient combustible program was made to NFPA 805 Chapter 3 element Section 3.3 which required prior NRC approval.

Because FRTW used for scaffolding was excluded from the requirements of NSD 313, Oconee offset and quantity restrictions over the use of these materials was not maintained. Licensee walkdowns performed immediately after the inspection revealed that approximately 50,000 lbs. of FRTW was distributed through 56 fire zones of the three units.

Analysis:

Failure to comply with Operating License Condition 3.D for a change to the approved FPP involving control of FRTW scaffolding materials was a PD. This PD was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e. fire), and it negatively affected the cornerstone objective in that the change to the FPP had the potential to adversely affect the ability to achieve and maintain safe and stable plant conditions due to the increased transient fire load in the affected FZs. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, review was required because the finding involved fire prevention and administrative controls. The inspectors evaluated the finding using the guidance in IMC 0609, Appendix F, to assess the significance of the licensees change to their FPP. The finding applied to most FZs within the plant because the licensee stopped tracking the FRTW scaffolding materials used throughout the plant. IMC 0609, Appendix F, Assumptions and Limitations states in part that the Fire Protection SDP Phase 2 approach is intended to support the assessment of known issues only in the context of an individual fire area. A systematic plant-wide assessment effort was beyond the intended scope of the fire protection SDP. Therefore, an SDP Phase 3 analysis was required to assess the significance of this finding.

A Phase 3 SDP risk analysis was performed by a regional SRA to assess the risk associated with this finding. Site walkdowns were conducted by the licensee to identify all scaffold locations in Oconee Units 1, 2, and 3 using the FRTW. Scaffolding material in close proximity to valid ignition sources and SSD target cables or equipment could increase an existing fire scenario ZOI to additional equipment or increase the time to damage for an existing fire SSD target set. NRC inspectors and a regional SRA reviewed the licensees walkdown output and performed an independent walkdown of the cases requiring detailed review. The Phase 3 SDP analysis consisted of a bounding risk evaluation which utilized the following assumptions: 1) FRTW scaffold fires assumed to relocate to the scaffold location; 2) FRTW resulted in a heat release rate reduction of 70 percent due to the retardant material (49kw and 140kw HRR utilized);and 3) fire impact assessed using the NUREG1805 Fire Dynamics Tools spreadsheets for plume temperature and radiant heating effects of the FRTW materials. The evaluation also considered the results of burn testing conducted by the licensee to determine the energy required to ignite and create sustaining and fire growth scenarios with the FRTW materials. The fire risk associated with the FRTW scaffold material was mitigated by the FRTW burning characteristics and the few scaffold locations which were in proximity to valid ignition sources and SSD target sets. None of the FRTW fire scenarios would have damaged both trains of SSD equipment simultaneously and the SSF would still be available. The SDP analysis determined that the risk increase associated with the FRTW scaffolding materials represented an increase in annual core damage frequency of <1E-6, a finding of very low safety significance (Green). The cause of this finding was determined to have a cross-cutting aspect of H.1

(b) in the Decision-Making component of the Human Performance area because the licensee used non-conservative assumptions in the decision making associated with this FPP change.

Additionally, the licensees failure to submit the FPP change to the NRC for review was determined to be a Severity Level IV traditional enforcement NCV in accordance with the NRC Enforcement Policy because it impacted the ability of the NRC to perform its regulatory oversight function.

Enforcement:

ONS Units 1, 2, and 3 Renewed Facility Operating License Condition 3.D states in part, that the licensee shall implement and maintain in effect all provisions of the approved FPP that comply with 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805. License Condition 3.D further states, in part, that the licensee is not allowed to self-approve quantitative risk-informed FPP changes except those implementation items needing a plant change evaluation as part of the Transition License Condition or NFPA 805 Chapter 3 element Section(s) 3.8 through 3.11 only.

Contrary to the above, on September 27, 2011, the licensee self-approved quantitative risk-informed FPP changes that were not implementation items for the Transition License Condition or NFPA 805 Chapter 3 Sections 3.8 through 3.11. The licensee failed to comply with the requirements of ONS Units 1, 2, and 3 Renewed Facility Operating License Condition 3.D for a change to the approved FPP involving the control of combustible materials. Procedure NSD 313, Control of Transient Fire Loads, Revision 10, excluded FRTW, netting and plastics (installed as part of in-place scaffolding) from procedural offset and quantity restriction requirements. This change to the combustible control program required prior NRC approval because it affected NFPA 805 Chapter 3 element Section 3.3. The licensees failure to submit the FPP change to the NRC for review and approval impacted the ability of the NRC to perform its regulatory oversight function. The licensee entered this issue into the corrective action program as PIP O-13-08584 and performed site wide walkdowns to quantify the amount and location of all FRTW materials used for in-place scaffolding and initiated additional roving fire watches in all affected high safety significant FZs that had not been covered by the existing fire watch rounds. Because this finding was of very low safety significance (Green), the associated traditional enforcement violation was determined to be a Severity Level IV violation. This violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. For administrative purposes, AV 05000269, 270, 287/2013007-03 is updated as NCV 05000269, 270, 287/2013007-03, Fire Protection Program Change did not Meet Oconee License Condition Requirements for NFPA 805 Chapter Three.

.3 (Closed) URI 05000269, 270, 287/2013007-05, Non-Compliance to License Condition

Requiring Modifications to LPG Tank was not Identified During Transition to NFPA 805 Based on review of the additional information provided to inspectors and discussions with NRC personnel in the Office of Nuclear Reactor Regulation/Fire Protection Branch, the inspectors concluded that the LPG tank deterministic anchorage requirement specified in the August 11, 1978 SER was superseded by the new fire protection license condition for each ONS unit. The performance-based method allowed in NFPA 805 was acceptable for application at ONS and the LPG tank met the requirements of ONS current licensing basis. No violation of NRC requirements was identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

Routine Operator Requalification Review: On September 24, 2013, the inspectors observed one active simulator training session to assess the performance of licensed operators during the session. The scenario involved a dropped control rod, asymmetric rod runback, high bearing vibration on a main feedwater pump, and a loss of all main feedwater and EFW. Events progressed to a point where the crew entered an Alert emergency declaration. The post-scenario critique conducted by the training instructor and the crew was also observed. Documents reviewed are listed in the Attachment.

Observation of Operator Performance: The inspectors observed operator performance in the main control room on July 26 - 27, 2013, during turbine valve testing to assess the following:

• Use of plant procedures

• Control board manipulations

• Communications between crew members

• Use and interpretation of instruments, indications, and alarms

• Use of human error prevention techniques

• Documentation of activities

• Management and supervision

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees effectiveness in performing the following two corrective maintenance activities. These reviews included an assessment of the licensees practices pertaining to the identification, scoping, and handling of degraded equipment conditions, as well as common cause failure evaluations. For each activity selected, 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. For those structures, systems and components (SSCs) scoped in the Maintenance Rule per 10 CFR 50.65, the inspectors verified that reliability and unavailability were properly monitored and that 10 CFR 50.65 (a)(1) and (a)(2) classifications were justified in light of the reviewed degraded equipment condition. Documents reviewed are listed in the

.

• PIP O-13-08345, trip of compressor circuit breaker from air handling unit 42

• PIP O-10-08435, 1FDW-315 opened unexpectedly when instrument air and auxiliary instrument are were isolated

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated the following attributes for the three activities listed below:

1) the effectiveness of the risk assessments performed before maintenance activities were conducted; 2) the management of risk; 3) that, upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and 4) that maintenance risk assessments and emergent work problems were adequately identified and resolved. Documents reviewed are listed in the Attachment.

• Emergent Orange Condition for SSF Inoperability due to inoperable Air Handling Unit

• Emergent Orange Condition for SSF Inoperability due to Keowee Underground Path Inoperable during PSW Modifications

• Emergent Red Condition for Keowee Underground Path Inoperable due to Keowee Hydro Unit-2 86E2 Lockout Activation

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following eight operability evaluations or functionality assessments affecting risk significant systems to assess: 1) the technical adequacy of the evaluations; 2) whether continued system operability was warranted; 3) whether other existing degraded conditions were considered; 4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were appropriately controlled; and 5) where continued operability was considered unjustified, the impact on Technical Specifications (TS) limiting condition for operations.

Operating Experience Smart Sample (OpESS) 2012/02, Technical Specification Interpretation and Operability Determination was used by the inspectors during the review.

• KHU-2 run out exceeded acceptance limits

• 3B Letdown Cooler discharge piping leak

• 1 LP-21 inadvertently closed

• SSF breakers OTS1-4 and OTS1-1 protective relaying

• Relays of Keowee Unit 2 panel KOIC-B discovered not properly seated

• PIP O-13-08748, bracing of power cables in underground path from Keowee Hydro

• PIP O-13-09151, Keowee emergency lockout (86E-2) activation for unknown reasons

• PIP O-13-09104, Pipe penetration above U1 north control room door

b. Findings

No findings were identified.

1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications

a. Inspection Scope

Evaluations of Changes, Tests, and Experiments: The inspectors reviewed four screenings pursuant to 10 CFR 50.59 where licensee personnel had determined that a 10 CFR 50.59 evaluation was not necessary. The inspectors reviewed these documents to determine if:

• the changes, tests, or experiments performed were evaluated in accordance with 10 CFR 50.59 and that sufficient documentation existed to confirm that a license amendment was not required;

• the safety issues requiring the changes, tests, or experiments were resolved;

• the licensee conclusions for evaluations of changes, tests, or experiments were correct and consistent with 10 CFR 50.59; and

• the design and licensing basis documentation used to support the change was updated to reflect the change.

The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision (Rev.) 1, to determine acceptability of the completed screenings. The NEI document was endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, dated November 2000.

This inspection sample consisted of four screenings as defined in section 04 of Inspection Procedure 71111.17T, Evaluations of Changes, Tests, and Experiments and Permanent Plant Modifications, dated March 2013.

The inspectors reviewed licensee activities associated with the following two permanent plant modifications.

Tornado and High Energy Line Break Project Modification - Emergency Power Supply for the Protected Service Water (PSW) System: The inspectors reviewed engineering change (EC) package 91875, Keowee AC Power Supply Tie-ins, Rev. 15, which evaluated the design and installation of the emergency power feed for the PSW station from the Keowee Hydro Units (KHU). The inspectors reviewed breaker coordination studies and one-line and control schematic diagrams to assess the effectiveness of the licensees implementation of design controls measures with respect to the design change.

The inspectors conducted direct observations of very low frequency and partial discharge testing for a sample of the emergency power supply cables. The inspectors evaluated equipment used for control of testing to determine whether the system was sufficiently controlled and reviewed completed test records to assess whether adequate controls were in place to validate the test results. Additionally, the inspectors conducted direct observations of testing of the protective relays associated with breakers KPF 9, 10, 11, and 12 of the KHU supply to the PSW building. The inspectors evaluated the content and use of test procedures to verify activities followed planned and approved sequences. Completed test records were reviewed to assess whether procedural controls were adequate to minimized errors and validated the test results.

Tornado and High Energy Line Break Project Modification - Electrical Equipment for the New PSW System: The inspectors reviewed EC 91833, OD500921 - (OMP) PSW Electrical Equipment Termination (Part B), Rev. 5. The inspectors assessed the implementation of test procedure TN/0/A/EC91833/005, PSW Building Equipment Energized Functional Testing, Rev. 0, used for the initial energizing of B6T, B7T, and PX13 switchgear and associated transformers from the 13.8 kilovolt (kV) fan line feeder circuits.

The inspectors reviewed corrective action documentation, initiated during implementation of the modification, to evaluate the accuracy and thoroughness of the licensees investigations, conclusions, and corrective actions. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following three plant modifications to verify the adequacy of the modification package and the 10 CFR 50.59 screenings and to evaluate the modification for adverse effects on system availability, reliability, and functional capability. Documents reviewed are listed in the Attachment.

Temporary Plant Modifications

• 100512, Install SSF alternate cooling/ventilation

• EC 111253, ICCM install temporary RTD Permanent Plant Modifications

• Electronic dosimetry auxiliary equipment in auxiliary building

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following five post-maintenance test procedures and/or test activities to assess if: 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 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. Documents reviewed are listed in the Attachment.

• MP/0/A/1840/040A, Pump-Motors-Miscellaneous Components-Lubrication Post Maintenance Testing of the 2B Reactor Building Spray Pump Following Realignment for Motor Rub

• OP/2/A/1104/004 Removal, Restoration and Vent of 2B LPI Pump/Train in Modes 1,2,3,& 4 for Hydraulic Maintenance, Rev. 153

• PT/1/A/0203/06AB LPI Pump Test

• WO 02083325-03, Switchyard Battery (SY2) Final Readings/PMT

• WO 02068712-02, Breaker 3X5-6A functional testing following breaker refurbishing

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors either witnessed and/or reviewed test data for the six surveillance tests listed below to assess if the SSCs met TS, Updated Final Safety Analysis Report (UFSAR), and licensee procedure requirements. In addition, the inspectors determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions. Documents reviewed are listed in the

.

Routine Surveillances

• WO 02055536-04, 0SYD BA SY2 Performance Test SY-2 Battery

• PT/2/A/0230/015, High Pressure Injection Motor Cooler Flow Test In-Service Tests

• PT/1/A/0600/013, Motor driven emergency feedwater pump test (1A MDEFDWP)

• PT/1/A/0600/012, Turbine driven emergency feed water pump test (1C MDEFDWP)

RCS Leakage

• PT/1/A/0600/010, Reactor Coolant Leakage, Rev. 094

• OP/0/B/1106/033, Primary System Leak identification, Encls 4.1, 4.4, 4.5, 4.13, 4.14, Rev. 17

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors evaluated the adequacy of the licensees methods for testing and maintaining the alert and notification system in accordance with NRC Inspection Procedure 71114, Attachment 02, Alert and Notification System Evaluation. The applicable planning standard, 10 CFR Part 50.47(b)(5) and its related 10 CFR Part 50, Appendix E, Section IV.D requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Rev. 1, were also used as a reference.

The inspectors reviewed various documents which are listed in the Attachment, interviewed personnel responsible for system performance, and observed aspects of periodic siren maintenance and testing. This inspection activity satisfied one inspection sample for the alert and notification system on a biennial basis.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed the licensees Emergency Response Organization (ERO)augmentation staffing requirements and process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection was reviewed to assess the effectiveness of corrective actions.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 03, Emergency Response Organization Staffing and Augmentation System.

The applicable planning standard, 10 CFR 50.47(b)(2), and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

Documents reviewed are listed in the Attachment. This inspection activity satisfied one inspection sample for the ERO staffing and augmentation system on a biennial basis.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues, the completeness and effectiveness of corrective actions, and to determine if issues were recurring. The licensees post-event after action reports, self-assessments, and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. Inspectors reviewed the licensees 10 CFR 50.54(q) change process, personnel training, and selected screenings and evaluations to assess adequacy. The inspectors toured facilities and reviewed equipment and facility maintenance records to assess licensees adequacy in maintaining them. The inspectors evaluated the capabilities of selected radiation monitoring instrumentation to adequately support Emergency Action Level (EAL)declarations.

The inspection was conducted in accordance with NRC Inspection Procedure 71114.05, Maintenance of Emergency Preparedness. The applicable planning standards, related 10 CFR 50, Appendix E requirements, and 10 CFR 50.54(q) and

(t) were used as reference criteria.

Documents reviewed are listed in the Attachment. This inspection activity satisfied one inspection sample for the maintenance of emergency preparedness on a biennial basis.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data to confirm the accuracy of reported PI data for the following PIs. To determine the accuracy of the report PI elements, the reviewed data was assessed against PI definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Rev. 6. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

• MSPI Heat Removal (3 units)

• Safety System Functional Failures (3 units)

Cornerstone: Barrier Integrity

• RCS Leakage (3 units)

For the period of September 20, 2012, through September 30, 2013, the inspectors reviewed Chemistry database data, Operating Logs, Train Unavailability Data, Maintenance Records, Maintenance Rule Data, PIPs, Consolidated Derivation Entry Reports, and System Health Reports to verify the accuracy of the PI data reported for each PI.

Emergency Preparedness Cornerstone

• Drill/Exercise Performance (DEP)

• Emergency Response Organization Drill Participation (ERO)

• Alert and Notification System Reliability (ANS)

For period July 1, 2012, through June 30, 2013, the inspector examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records. The inspectors reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO. The inspectors verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspectors also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data and observed drill scenarios in the main control simulator used for DEP credit. Licensee procedures, records, and other

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Daily Screening of Corrective Action Reports

In accordance with 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 CAP. This review was accomplished by reviewing copies of PIPs, attending daily screening meetings, and accessing the licensees computerized database.

.2 In Depth Review

a. Inspection Scope

In addition to the routine review, the inspectors selected the issue listed below for a more in-depth review. The inspectors considered the following during the review of the licensees actions: 1) complete and accurate identification of the problem in a timely manner; 2) evaluation and disposition of operability/reportability issues; 3) consideration of extent of condition, generic implications, common cause, and previous occurrences; 4) classification and prioritization of the resolution of the problem; 5) identification of root and contributing causes of the problem; 6) identification of CRs; and 7) completion of corrective actions in a timely manner.

• Maintenance Work Order (MWO)02061777, 3A Reactor Building Spray Pump

b. Findings and Observations

During performance of a partial equipment walkdown of the 3A reactor building spray pump, the inspectors observed a deficiency tag, 38666, dated December 27, 2012, on the pump. The inspectors also observed an oil drip pan located below the pump shaft that contained a small quantity of lubrication oil. The inspectors reviewed the work order associated with this deficiency tag, WO 02061777, and there were no tasks associated with this work order addressing oil leakage.

The inspectors performed a search on PIPs associated with the 3A RBS pump. They identified seven PIPs dated between May 2010 and September 2013, associated with the 3A RBS pump having low oil levels. The latest PIP, O-13-01826, dated February 2013, again identified the oil leakage from the pump, and stated the oil level was being tracked in the licensees fluid leak management program. The inspectors interviewed the licensee about oil leakage from the pump and were told the pump had a known oil leakage problem that was extremely small and an operability determination was previously completed. The inspectors confirmed the pump was previously entered into the fluid leak management program. As a result of the inspectors questions, the licensees system engineer performed a review of PIPs, inspected the pump and determined a complete rebuild of the 3A RBS pump was necessary. The licensee identified the condition of the pump as a condition adverse to quality and entered it into their CAP program as PIP O-13-07384 and submitted Work Request WR 01090047 to rebuild the pump. The NRC inspectors determined the issue was minor because the operability of the pump was not challenged.

.3 Operator Workarounds

a. Inspection Scope

The inspectors reviewed the cumulative effects of deficiencies that constitute operator workarounds to determine whether or not they could: affect the reliability, availability, and potential for misoperation of a mitigating system; affect multiple mitigating systems; or affect the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspectors also assessed whether operator workarounds were being identified and entered into the licensees corrective action program at an appropriate threshold.

b. Findings

No findings were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (NOED)

.1 (Closed) Licensee Event Report (LER) 05000269/2013-02, 00: LPI and RBS Trains

Inoperable When 1LP-21 Was Closed Due to Human Error On June 26, 2013, Oconee Unit 1 was operating at 100 percent power with the 1B train of Low pressure injection (LPI) and RBS out of service for scheduled maintenance and testing. This maintenance required valve 1LP-22, 1B train LPI and RBS pump suction, be cycled closed and then reopened several times from the control room. During one cycle, a control room operator inadvertently closed valve 1LP-21, 1A train LPI and RBS pump suction. The inadvertent action was immediately recognized by the control room operator and, after assessment and communications with shift personnel, valve 1LP-21 was reopened. Closing 1LP-21 while 1LP-22 was out of service resulted in both trains of LPI and RBS being inoperable for about 13 minutes. TS 3.5.3 and 3.6.5 required two trains of LPI and RBS to be operable in Mode 1. The inspectors further verified the accuracy of the LER, the appropriateness of completed, and planned corrective actions, and reviewed the licensees root cause evaluation. The enforcement aspects associated with this LER are documented in Section 4OA7.

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 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 reviews and inspection activities.

b. Findings

No findings were identified.

.2 Verification of Completion of Milestone 1 of Protected Service Water Major Plant

Modification

a. Inspection Scope

The inspectors observed licensee activities related to installation and testing of permanent equipment necessary to power the Standby Shutdown Facility electrical bus from the Protected Service Water facility. The inspectors verified that station procedures were adequate for station operators to accomplish the energization of the Standby Shutdown Facility electrical bus from the Protected Service Water facility. The inspectors also verified that adequate training was provided to personnel to accomplish the above task.

.3 (Closed) Temporary Instruction 2515/190, Inspection of Licensee's Proposed Interim

Actions as a Result of the Near-Term Task Force Recommendation 2.1 Flooding Evaluation The inspectors verified that licensees interim actions will perform their intended function for flooding mitigation. The inspectors independently verified that the licensees proposed interim actions would perform their intended function for flooding mitigation.

• Visual inspection of the flood protection feature was performed if the flood protection feature was relevant.

• External visual inspection for indications of degradation that would prevent its credited function from being performed was performed.

• Reasonable simulation, if applicable to the site

• Flood protection feature functionality was determined using either visual observation or by review of other documents.

• Verified that issues identified were entered into the licensee's CAP.

The interim compensatory measures for external flooding due to Jocassee dam failure were previously inspected and the results documented in NRC inspection report 05000269, 270, 287/2012005.

4OA6 Management Meetings (Including Exit Meeting)

Exit Meeting Summary

On October 3, 2013, the resident inspectors presented the inspection results to Mr. S.

Batson and other members of licensee management. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee Identified Violations

The following violations of very low safety significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

• Technical Specification 5.4.1(a), Procedures, required in part that written procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Rev. 2, Appendix A, February 1978. Procedure OP/1/A/1102/008, Enclosure 4.35, On Line Valve Lineup for MOV Maintenance, Step 2.5, stated, in part, for the operator to cycle 1LP-22 (1B LPI BWST suction).

Contrary to the above, on June 26, 2013, the licensee operator failed to follow written procedure when he closed 1LP-21 (1A LPI BWST suction) which isolated the operable LPI train from the BWST rendered Unit 1 LPI inoperable. The licensee restored the LPI A train to its proper alignment within thirteen minutes. The finding was determined not to be greater than Green because the loss of function of at least a single train did not exceed its TS allowed outage time. The licensee entered the issue into their CAP as PIP O-13-06879.

• Technical Specification 5.4.1(a), Procedures, required in part that written procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Rev. 2, Appendix A, February 1978. Procedure OP/0/A/1107/016, Enclosure 4.4, Removal and Restoration of 230KV Switchyard PCB, Step 2.2.4, stated, in part, Ensure locked closed PCB [27] Yellow (Red) Bus Side Disconnect. Contrary to the above, on October 22, 2012, the licensee failed to ensure PCB27 was locked closed. The licensee discovered and corrected this condition on April 24, 2013. The finding was determined to represent a loss of system and/or function which required a risk evaluation by a Senior Reactor Analyst (SRA). The SRA estimated the likelihood of faults that could lead to damage of the disconnect and multiplied these by the change in conditional core damage probability due to a loss of the transformer impacted. Dominant cutsets involved failure of one Keowee hydro unit in conjunction with LOOP sequences, operators failure to recover offsite power, or the Keowee faults within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and failure of EFW. The risk impact was less than 1E-7 for the exposure period. In addition, the risk impact of seismic events was estimated not to be a major contributor to the change in risk.

Because the risk impact was less than 1E-7, the finding was determined not to be greater than Green. Licensee personnel entered the issue into their corrective action program as PIP O-13-04503.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Alter, Regulatory Compliance Manager

M. Bailey, Reactor and Electrical Systems Engineering Manager

S. Batson, Site Vice President

S. Boggs, Emergency Services Coordinator

M. Boyle, Duke - Project Control

E. Burchfield, Engineering Manager

B. Carroll, PRA Supervisor

T. Cheslak; Oconee Fire Protection Engineer

D. Crowl, Emergency Planning staff

C. Eflin, Operations Safe Shutdown Engineer

W. Elliott, Nuclear Oversight Assessment Supervisor

P. Fisk; Superintendent of Operations

R. Freudenberger, Duke - ONS/Senior Engineer

P. Gillespie, Site Vice President

R. Guy, Organization Effectiveness Manager

A. Holder, Fleet Fire Protection Engineer

J. Kaminski, Emergency Planning staff

M. Kapousouz, Duke - Engineering

R. Keener, Communications Technician

T. King, Security Manager

D. Larson, Duke - Electrical Engineer

A. Lotfi, Duke - Construction

R. Meixell, Sr. Licensing Specialist

J. Overly, Fleet Emergency Preparedness

T. Patterson, Safety Assurance Manager

S. Perry, Regulatory Affairs

J. Pounds, OMP Tornado/HELB QA Oversight

T. Ray, Station Manager

F. Rickenbaker, OMP Manager

R. Rishel, PRA Group Manager

D. Robinson, Radiation Protection Manager

E. Simbles, Erin Fire PRA Manager

J. Smith, Regulatory Affairs

J. Steely, Operations Training Manager

P. Street, Emergency Preparedness Manager

C. Sweely, Senior Specialist, Areva Fire Protection

B. Weaver, PRA Engineer

A. Wells, Engineering Programs Supervisor

NRC

J. Boska, Project Manager, NRR

LIST OF REPORT ITEMS

Closed

05000269/2013007-02 NCV Failure to Identify Ignition Sources and Targets During Initial Fire Scenario Development (Section 1R05.2)

05000269, 270, 287/2013007-03 NCV Fire Protection Program Change did not Meet Oconee License Condition Requirements for NFPA 805 Chapter Three (Section 1R05.2)

05000269, 270, 287/2013007-05 URI Non-Compliance to License Condition Requiring Modifications to LPG Tank was not Identified During Transition to NFPA 805 (Section 1R05.2)

05000269/2013-02, 00 LER LPI and RBS Trains Inoperable When 1LP-21 Was Closed Due to Human Error (Section 4OA3.1)

2515/190 TI Inspection of Licensee's Proposed Interim Actions as a Result of the Near-Term Task Force Recommendation 2.1 Flooding Evaluation (Section 4OA3)