IR 05000269/2014005

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IR 05000269/2014005, 05000270/2014005, 05000287/2014005, on 10/01/2014 - 12/31/2014, Oconee Nuclear Station, Units 1, 2, and 3, Problem Identification and Resolution, and Follow-up of Events and Notices of Enforcement Discretion (NOED)
ML15035A213
Person / Time
Site: Oconee  Duke Energy icon.png
Issue date: 02/03/2015
From: Frank Ehrhardt
NRC/RGN-II/DRP/RPB1
To: Batson S
Duke Energy Carolinas
References
IR 2014005
Download: ML15035A213 (33)
v • d • e


Text

February 3, 2015

SUBJECT:

OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000269/2014005, 05000270/2014005, 05000287/2014005

Dear Mr. Batson:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Oconee Nuclear Station Units 1, 2, and 3. On January 15, 2015, 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 one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. Additionally, NRC inspectors documented a Severity Level IV violation with no associated finding. 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 the violations or significance of 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 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC resident inspector at the Oconee Nuclear Site.

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 Nuclear Site.

In accordance with Title10 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 NRCs Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Documents Access and Management 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/

Frank Ehrhardt, 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 05000269/2014005, 05000270/2014005, 05000287/2014005 w/Attachment: Supplementary Information

REGION II==

Docket Nos:

50-269, 50-270, 50-287

License Nos:

DPR-38, DPR-47, DPR-55

Report Nos:

05000269/2014005, 05000270/2014005, 05000287/2014005

Licensee:

Duke Energy Carolinas, LLC

Facility:

Oconee Nuclear Station, Units 1, 2 and 3

Location:

Seneca, SC 29672

Dates:

October 1, 2014, through December 31, 2014

Inspectors:

E. Crowe, Senior Resident Inspector

G. Croon, Resident Inspector

N. Childs, Resident Inspector

T. Morrissey, Senior Resident Inspector - St Lucie

B. Collins, Reactor Inspector (Section 1R08)

P. Cooper, Reactor Inspector (Section 1R08)

M. Riley, Reactor Inspector M. Meeks, Senior Operations Engineer (Section 1R11)

Approved by:

Frank Ehrhardt, Chief

Reactor Projects Branch 1

Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000269/2014-005, 05000270/2014-005, 05000287/2014-005; 10/01/2014 - 12/31/2014;

Oconee Nuclear Station Units 1, 2 and 3; Problem Identification and Resolution, and Follow-up of Events and Notices of Enforcement Discretion (NOED)

The report covered a three-month period of inspection by resident inspectors, a visiting resident inspector and region-based reactor inspectors. One Green finding and one SL IV violation, which were determined to involve non-cited violations (NCVs) of NRC requirements, were identified. The significance of inspection findings are indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within The Cross-Cutting Areas, dated December 19, 2013. 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 5.

Cornerstone: Mitigating Systems

  • Green A self-revealing Green NCV of Oconee Nuclear Station Technical Specification (TS)3.8.1, AC Sources - Operating, was identified for Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The licensee modified Keowee Hydro Unit 2 electrical protection circuitry with a faster response relay which was susceptible to an existing degraded system condition and ultimately caused Keowee Hydro Unit 2 to be inoperable. The licensee implemented engineering change (EC111358) which moved the 86E2X relay to another cabinet which was not susceptible to the vibration from the governor oil system. The licensee entered this issue in their corrective action program (CAP) as PIP-O-13-09152.

The licensees failure to properly evaluate a modification to the electrical control circuit of the governor oil system, which resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time, was a performance deficiency. The issue is more than minor because it was associated with the equipment performance attribute of the mitigating system cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the modification of the governor oil system, including the addition of the 86E2X governor TXS catastrophic relay, resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time.

The finding was screened in accordance with NRC IMC 0609, Significance Determination Process (SDP), Attachment 4 and Attachment A and determined to require a detailed risk evaluation. A regional Senior Reactor Analyst performed a risk analysis of the performance deficiency which was found to be Green (CDF < 1E-6/year). The dominant accident sequence was a loss of offsite power where Keowee Unit 1 fails independently and unrelated to the performance deficiency and power is not successfully restored by Oconee operators. The influential factors in the Green result were the limited exposure time (19 days) and the ability to quickly restore power to the unit via the Lee Station gas turbines via the Fant Line.

This finding was determined to have a cross-cutting aspect in the problem identification and resolution cross cutting area because the licensees organization failed to take effective corrective actions to address the issue in a timely manner commensurate with its safety significance. Specifically, the licensee failed to take effective corrective actions to address system interactions (i.e. high vibrations) which ultimately had an adverse effect upon modifications to the governor oil system of the Keowee Hydro Unit 2. (P.3) (Section 4OA3.1)

Other Findings

  • SL-IV An NRC identified Severity Level IV violation of 10 CFR 50.71(e), "Maintenance of Records, Making of Reports," was identified for the licensees failure to update the final safety analysis report (FSAR) after the licensee adopted the improved technical specifications (ITS). The licensee adoption of ITS introduced the possibility of a Mode 4 loss of cooling accident (LOCA), which was an accident of a different type than previously evaluated in the FSAR. The licensee initiated PIP O-15-00260 in order to determine future corrective actions. Continued non-compliance does not present an immediate safety concern because the inspectors assessed this as a very low safety significant issue.

The licensees failure to update the FSAR as required by 10 CFR 50.71(e) was a performance deficiency. The performance deficiency impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Specifically, a failure to update the UFSAR challenges the regulatory process because it serves as a reference document used, in part, for recurring safety analyses, evaluating license amendment requests, and in preparation for and conduct of inspection activities. This violation was determined to be a Severity Level IV violation per Section 6.1.d.3 of the NRC Enforcement Policy, revised July 9, 2013, because the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. The NRC Enforcement Policy also requires disposition of findings in the significance determination process, which determined the finding was not more than minor. Since this issue was dispositioned using traditional enforcement, there was no cross-cutting aspect associated with this violation. (Section 4OA2.3)

REPORT DETAILS

Summary of Plant Status

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

The unit was shut down on November 3, 2014 for a refueling outage. The reactor was made critical on December 4, 2014 and the unit was maintained at a low reactor power level of 19 percent RTP for repairs to the main generator excitation circuit. The unit returned to 100 percent RTP on December 11, 2014. The unit remained at or near 100 percent RTP for the remainder of the inspection period.

Unit 2 began the inspection period at approximately 100 percent RTP. The unit was shut down on October 13, 2014 for a forced outage to replace control rod drive fans. The unit was returned to 100 percent RTP on October 16, 2014. The unit remained at or near 100 percent RTP for the remainder of the inspection period.

Unit 3 began the inspection period at approximately 100 percent RTP. Power was reduced to 19 percent RTP on October 25, 2014 for the planned addition of oil to the upper motor oil bearing reservoir for the 3A1 reactor coolant pump. The unit was returned to 100 percent RTP on October 26, 2014. The unit remained at or near 100 percent RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

==

Readiness for Extreme Seasonal Weather Condition

The inspectors reviewed the licensees preparations for adverse weather associated with the cold ambient temperatures at the site. This included field walkdowns to assess the material condition and operation of freeze protection equipment, as well as other preparations made to protect plant equipment from freezing conditions. In addition, the inspectors reviewed the licensees procedures for preparing for cold weather and conducted interviews with personnel responsible for implementing the licensees cold weather protection program to assess the licensees ability to identify and resolve deficient conditions associated with cold weather protection equipment prior to cold weather events. Documents reviewed are listed in the Attachment.

Impending Adverse Weather Conditions

On October 14, 2014, the inspectors reviewed the licensees response to a tornado watch and subsequent tornado warning for the local area. The inspectors evaluated the licensees implementation of site procedures and determined if licensee staffs actions were adequate. There was no tornado experienced onsite. Documents reviewed are listed in the Attachment.

External Flooding

The inspectors reviewed the licensees compensatory measures identified in CAL 2-10-003, Confirmatory Action Letter - Oconee Nuclear Stations Units 1, 2, and 3 Commitments to Address External Flooding Concerns to ensure the measures were available and properly maintained. This review included field walkdowns of temporary equipment to assess its material condition and operability. In addition, the inspectors reviewed the licensees procedures for external flood mitigation and conducted interviews with personnel responsible for implementing the licensees program to assess the licensees ability to respond to potential events.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

==

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed the three 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.

  • Unit 0, electrical alignment with KHU-2 (overhead unit) unavailable for emergency start during 230 KV Yellow bus relay work
  • Unit 0, electrical alignment of emergency AC buses during maintenance activity on the standby shutdown facility (SSF)
  • Unit 1, emergency feedwater alignment during surveillance testing on the 1A motor driven emergency feedwater pump

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

The inspectors performed a full system walkdown of the Keowee Hydro Station. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers and support equipment to determine if they were correctly aligned to support system operation. The inspectors reviewed open maintenance work requests and open design issues to determine if the licensee had properly identified and resolved equipment alignment problems that could potentially affect the ability of the system to perform its safety functions and entered them into the CAP. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

==1R05 Fire Protection

a. Inspection Scope

Fire Area Tours:==

The inspectors walked down accessible portions of the five 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 2, equipment room (Zone 92)
  • Unit 2, cable room (Zone 105)
  • Unit 1, containment building (Zone 122)
  • Unit 2, 6900 & 4160 Volt switchgear area (Zone 33)

b. Findings

No findings were identified.

==1R06 Flood Protection Measures

a. Inspection Scope

Internal Flood Protection:==

The inspectors reviewed risk-important plant design features and licensee procedures to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analysis documentation associated with the internal plant areas to determine the effects of flooding for the area listed below. The internal area was selected and walked down based on the flood analysis calculation. The inspectors reviewed sealing of doors, holes in elevation penetration, sump pump operations and potential flooding sources. The inspectors also reviewed corrective action program documents to ascertain the licensee was identifying and resolving issues. Documents reviewed are listed in the Attachment.

  • standby shutdown facility battery rooms

b. Findings

No findings were identified.

==1R08 Inservice Inspection Activities

a. Inspection Scope

==

Non-Destructive Examination Activities and Welding Activities: From November 11-18, 2014, the inspectors conducted an onsite review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 1. The inspectors activities included a review of non-destructive examinations (NDEs) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 1998 Edition with 2000 Addenda), and to verify that indications and defects were appropriately evaluated and dispositioned, in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

The inspectors directly observed the following NDEs mandated by the ASME Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

  • Penetrant Testing (PT) of RCP drain nozzle on 1A1 suction piping 1-PIA1-11, 2.5, ASME Class 1

The inspectors reviewed records of the following NDEs mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

The inspectors observed the welding activities referenced below and reviewed associated documents in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order (WO), repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities: For the Unit 1 vessel head, a bare metal visual examination and volumetric examinations were not required this outage (EOC 28) pursuant to 10 CFR 50.55a, as it had been performed during the last refueling outage (EOC 27). Their next scheduled examination will be performed during the EOC 32. Therefore, no NRC review was done for this inspection procedure attribute.

Boric Acid Corrosion Control Inspection Activities: The inspectors reviewed the licensees boric acid corrosion control (BACC) program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an onsite record review of procedures and the results of the licensees containment walkdown inspections performed during the current spring refueling outage. The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected, in accordance with the licensees BACC and CAP.

The inspectors reviewed the following problem investigation program (PIPs) and associated corrective actions related to evidence of boric acid leakage, to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code Section XI, and 10 CFR Part 50, Appendix B, Criterion XVI.

  • O-14-11948, Boron Leak on 1-CF-61
  • O-14-11838, Unit 1 RB Tour Results
  • O-14-11762, Boron Leak on Building Spray
  • O-14-11756, Unit 1 RB Tour Results (Mode 4)
  • O-14-11718, Unit 1 RB Tour Results (Mode 3)
  • O-13-13177, 1EOC27A FLM Mode 3 Hot Shutdown Tour

The inspectors reviewed the engineering evaluations contained in the following PIPs that were completed for evidence of boric acid leakage to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded components to determine if they met the ASME Section XI Code.

  • O-13-14213, 1B1 RCP Shaft seal with 1/4 teaspoon boron ring

Steam Generator Tube Inspection Activities: The inspectors observed the following activities and/or reviewed the following documentation, and evaluated them against the licensees technical specifications, commitments made to the NRC, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines.

  • Reviewed the licensees in-situ steam generator (SG) tube pressure testing screening criteria. In particular, the inspectors assessed whether assumed NDE flaw sizing accuracy was consistent with data from the Electric Power Research Institute (EPRI) examination technique specification sheets (ETSS), or other applicable performance demonstrations.
  • Compared the numbers and sizes of SG tube flaws/degradation identified against the licensees previous outage Operational Assessment.
  • Evaluated if the licensees SG tube ECT examination scope included potential areas of tube degradation identified in prior outage SG tube inspections, and/or as identified in NRC generic industry operating experience applicable to the licensees SG tubes.
  • Reviewed the licensees implementation of their extent-of-condition inspection scope and repairs for new SG tube degradation mechanism(s). No new degradation mechanisms were identified during the ECT examinations.
  • Reviewed the licensees repair criteria and processes.
  • Verified that primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons per day, or the detection threshold, during the previous operating cycle.
  • Evaluated if the ECT equipment and techniques used by the licensee to acquire data from the SG tubes were qualified or validated to detect the known/expected types of SG tube degradation, in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.
  • Reviewed ECT personnel qualifications.
  • Reviewed five samples of eddy current data.

Identification and Resolution of Problems: The inspectors reviewed a sample of ISI-related problems that were identified by the licensee and entered into the CAP as PIP reports. The inspectors reviewed the PIPs to confirm the licensee had appropriately described the scope of the problem, and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the report Attachment.

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification

a. Inspection Scope

==

Routine Operator Requalification Review: On November 21, 2014, the inspectors observed licensed operator just-in-time-training in the simulator for the protected service water (PSW) injection test to the unit 1 steam generators. Documents reviewed are listed in the Attachment.

Observation of Operator Performance: The inspectors observed operator performance in the main control room on October 13, 2014 and November 3, 2014, during Unit 2 and Unit 1 shutdowns. Additionally, the inspectors observed the reactor startup of Unit 2 on October 15, 2014. Inspectors observed licensed operator performance 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

Annual Review of Licensee Requalification Examination Results: On March 20, 2014, the licensee completed the annual requalification operating examinations required to be administered to all licensed operators in accordance with Title 10 of the Code of Federal Regulations 55.59(a)(2), Requalification Requirements, of the NRCs Operators Licenses. During the week of December 1, 2014, the inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP)71111.11, Licensed Operator Requalification Program. These results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11.

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 completeness 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.
  • Orange risk assessment and management in response to tornado warning with Unit 2 in forced outage and aligned to CT-2
  • Orange risk assessment and management response to Unit 1 condenser cooling water (CCW) water-box discharge valve outage combined with PSW unavailability
  • Yellow risk assessment and management response to 1 DID panel board removal combined with PSW unavailability

b. Findings

No findings were identified.

==1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

==

The inspectors reviewed the following seven 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 TS limiting condition for operations.
  • PIP-O-14-10372, U3 turbine driven emergency feedwater pump
  • PIP-O-14-10499, RCP turning vane
  • PIP O-14-10521, Eaton Cutler-Hammer D26 series relays are not being dedicated by AREVA to the more conservative pickup voltages specified in DPM-1393.01-0002
  • PIP O-14-10804, current transformers 1, 2, and 3 87 relays
  • PIP O-14-11237, LOCA analysis limits
  • PIP O-14-13012, 3A reactor building cooling unit found tripped

b. Findings

No findings were identified.

==1R18 Plant Modifications

a. Inspection Scope

==

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

  • U1/2 Reverse Osmosis Upgrade

b. Findings

No findings were identified.

==1R19 Post-Maintenance Testing

a. Inspection Scope

==

The inspectors reviewed the following four 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.
  • PT/3/A/0203/006 A, 3A LPI Pump Test, Rev. 91 after routine maintenance
  • PT/3/A/0160/008, Reactor Building Cooling Unit Air Flow Test and PT/3/A/0160/008, Reactor Building Cooling Unit Fan Operation Test following replacement of 3A Reactor Building Cooling Unit motor
  • PT/1/A/0400/007, SSF RC Makeup Pump Test, Rev 67 after motor replacement
  • PT/1/A/0152/012, Low Pressure Injection System Valve Stroke Test, Rev 39 after breaker replacement

b. Findings

No findings were identified.

==1R20 Refueling and Outage Activities

a. Inspection Scope

==

Refueling Outage: The inspectors evaluated licensee outage activities associated with the Unit 1 1EOC28 refueling outage to determine if the licensee adhered to operating license, TS, selected licensee commitments, and applicable procedural guidance. The inspectors reviewed the licensees risk control plan associated with the receipt and movement of new nuclear fuel to assess the adequacy of the risk assessments that had been conducted and that the licensee had implemented appropriate risk management strategies as required by 10 CFR 50.65(a)(4). The inspectors conducted portions of the following activities associated with the pre-refueling outage. Documents reviewed are listed in the Attachment.

  • Reviewed the licensees integrated risk profile for the 1EOC28 refueling outage.
  • Observed power reduction process, removing the reactor from service and portions of the cooldown from normal operating pressure and temperature to ensure that the requirements in TS and selected licensee commitments were followed.
  • Conducted a containment entry once Mode 3 had been reached to observe the condition of major, normally inaccessible equipment and check for indications of previously unidentified leakage from the reactor coolant system.
  • Observed fuel handling operations during core off-loading and reloading activities to verify that those operations and activities were being performed in accordance with TS and procedural guidance.
  • Reviewed the licensees responses to emergent work and unexpected conditions to verify that resulting configuration changes were controlled in accordance with the outage risk control plan.
  • Periodically reviewed the setting and maintenance of containment integrity, to establish that the RCS and containment boundaries were in place and had integrity when necessary.
  • Reviewed system lineups and/or control board indications to substantiate TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations.
  • Reviewed the items that had been entered into the CAP to verify that the licensee had identified outage related problems at an appropriate threshold.
  • Observed activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS when taking equipment out of service.

Forced Outage: The inspectors evaluated licensee outage activities associated with Unit 2 forced outage to replace control rod drive mechanism (CRDM) fans. The inspectors evaluated the licensees consideration of risk and risk reduction methodologies in developing a repair schedule; adherence to the operating license, TS and selected licensee commitment requirements and procedural guidance that maintained defense-in-depth; and development of mitigation strategies for losses of the key safety functions.

The inspectors conducted the following activities associated with the forced outage.

Documents reviewed are listed in the Attachment.

  • Observed power reduction process, removing the reactor from service and portions of the cooldown from normal operating pressure and temperature to ensure that the requirements in the TS and selected licensee commitments were followed.
  • Conducted containment walkdown to inspect for overall cleanliness and material condition of plant equipment.
  • Observed the approach to criticality, placing the main generator on-line which completed the forced outage and portions of the power ascension activities.
  • Reviewed the items that had been entered into the CAP to verify that the licensee had identified outage related problems at an appropriate threshold.
  • Observed activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS when taking equipment out of service.

b. Findings

No findings identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors either witnessed and/or reviewed test data for the five 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 Attachment.

Routine Surveillances

  • PT/0/A/0400/011, SSF Diesel Generator Test, Rev 14
  • PT/1/A/0610/001 B, EPSL Startup Source Voltage Sensing Circuit, Rev 32

In-Service Tests

  • PT/3/A/0202/011, 3B HPI Pump Test

Containment Isolation

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data to confirm the accuracy of reported PI data for the following six 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, Revision 6. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

  • Mitigating System Performance Index (MSPI) Emergency AC (3 units)

For the period of December 31, 2013, through December 31, 2014, the inspectors reviewed 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.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Daily Screening of Corrective Action Reports

a. Inspection Scope

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.

b. Findings

No findings were identified.

.2 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. Oconee nuclear system directive NSD-506, Operator Workarounds and Control Room Deficiencies, was superseded on July 29, 2014 by procedure, AD-OP-ALL-0202. The inspectors noted that the licensee was slow in transitioning to the requirements specified in AD-OP-ALL-0202. AD-OP-ALL-0202 specified a different classification scheme for degraded conditions than that contained in NSD-506. The licensee had not evaluated each degraded condition under the new guidance until October 2014. The first monthly aggregate operator impact assessment under AD-OP-ALL-0202 was completed in October 2014. The inspector noted that there have been no new operator workarounds identified since the last NSD-506 aggregate assessment performed in July 2014. Therefore, the significance of missing two monthly aggregate assessments is minimal. The quarterly team review of the current Operator Challenge Aggregate Operator Impact Assessment is expected to be completed by the end of the December 2014.

.3 In Depth Review

a. Inspection Scope

In addition to the routine review, the inspectors selected the four issues 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 problem identification reports; and 7) completion of corrective actions in a timely manner.

  • PIP-O-14-07988, 1B High Pressure Injection Pump upper oil level indication low
  • PIP-O-14-11743, Unit 2 entered AP/1-2/A/1700/035, Loss of SFP Cooling and/or Level, due to spent fuel pool temperature rise greater than 5 degrees in less than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

b. Findings

Introduction:

An NRC identified Severity Level IV violation of 10 CFR 50.71(e),

"Maintenance of Records, Making of Reports," was identified for the licensees failure to update the FSAR after the licensee adopted the ITS. The licensee adoption of ITS introduced the possibility of a Mode 4 LOCA, which was an accident of a different type than previously evaluated in the final safety analysis report FSAR.

Description:

In December 1998, the licensee adopted ITS. Improved Technical Specification Section 3.6.5 added a new requirement for one train of reactor building spray (RBS) to be in engineered safeguards (ES) alignment in Mode 4. The licensee implemented this requirement by aligning the RBS to the decay heat removal (DHR)suction from the reactor coolant system (RCS).

In April 2000, the licensee identified the new requirement created the possibility of a LOCA in Mode 4, a previously unanalyzed condition in the FSAR. As such, implementation of the ITS caused a departure from the plants original licensing basis.

The licensee documented their recognition of this departure from their original licensing basis in their corrective action program as PIPs O-00-02461 and O-00-02967.

The licensee approved a corrective action in PIP O-00-02967 to amend the ITS to remove the requirement for one train of RBS in Mode 4, eliminating the possibility of a Mode 4 LOCA, and thus returning the plant to its original licensing basis. In 2000, the licensee instituted temporary procedure changes to administratively control the risk of a Mode 4 LOCA until the ITS amendment could be drafted and implemented. In 2014, the licensee decided the procedural changes were sufficient to address the risk concern with a Mode 4 LOCA, and decided to not pursue an ITS amendment. However, the licensee failed to identify that without either an ITS amendment or an update to the FSAR, the plant remained outside its original licensing basis.

Analysis:

The licensees failure to update the FSAR as required by 10 CFR 50.71(e)was a performance deficiency. This performance deficiency impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Specifically, failures to update the UFSAR challenges the regulatory process because it serves as a reference document used, in part, for recurring safety analyses, evaluating license amendment requests, and in preparation for and conduct of inspection activities. This violation was determined to be a Severity Level IV violation per Section 6.1.d.3 of the NRC Enforcement Policy, revised July 9, 2013, because the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. Since this issue was dispositioned using traditional enforcement, there was no cross-cutting aspect associated with this violation.

Enforcement:

Title 10 CFR Part 50.71(e), "Maintenance of Records, Making of Reports," requires, in part, that the licensee shall periodically update the FSAR originally submitted as part of the application for the license, to assure that the information included in the report contains the latest information developed. Contrary to the above, from December 1998 to the present, Oconee failed to update its FSAR as required by 10 CFR 50.71(e), when it adopted the ITS, for an accident of a different type (Mode 4 LOCA) than any previously evaluated in the FSAR. The licensee initiated PIP O-15-00260 in order to determine future corrective actions. Continued non-compliance does not present an immediate safety concern because the inspectors assessed this as a very low safety significance issue. Because this violation was determined to be a SL IV violation and the licensee entered the issue in their corrective action program as PIP O-15-00260, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. This finding will be tracked as NCV 05000269, 05000270,05000287/2014005-01; Failure to Update FSAR for Mode 4 LOCA.

.4 Semi-annual Trend Review

a. Inspection Scope

As required by IP 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on open corrective actions greater than five years old, but also considered the results of daily inspector CAP item screenings discussed in section 4OA2.1 above, licensee trending efforts, licensee human performance results and inspector observations made during in-plant inspections and walk-downs. The inspectors review primarily considered the six-month period of July 2014 through December 2014, although some examples expanded beyond those dates when the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health reports, Independent Nuclear Oversight reports, self-assessment reports, and maintenance rule reports. The inspectors compared and contrasted their results with the results contained in the licensees latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Observations and Findings

No findings were identified. In general, the licensee performs adequate monitoring of their programs for adverse trends. Previously, the inspectors noted large number of open corrective actions greater than five years old. The licensee in general is tracking these open corrective actions in their CAP program. The inspectors reviewed corrective actions associated with problem identification reports for potential trends and observed the corrective actions were adequate to address the trends.

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

.1 (Closed) Licensee Event Report (LER) 05000269,270,287/2013-03-00:

Keowee Hydroelectric Station Unit 2 - Emergency Power Lockout

a. Inspection Scope

On September 4, 2013, Keowee Hydroelectric Station Unit 2 (KHU-2) experienced an emergency lockout that rendered the unit inoperable. The licensee evaluated the event and determined that from August 17, 2013 until September 4, 2013 KHU-2 had been susceptible to an emergency lockout condition resulting from vibration of the governor oil system causing the 86E2X governor TXS catastrophic failure relay to chatter and pass current on to the 86E2 emergency lockout relay. This condition provided a false actuation signal to the 86E2 emergency lockout relay and prevented Unit 2 Keowee Hydro from powering its intended emergency AC electrical bus. The licensee documented this condition in multiple corrective action documents (PIPs) and documented an apparent cause determination in PIP-O-13-09152. The inspectors reviewed related corrective action documents to verify licensee corrective actions to restore operability of the KHU-2. The inspectors also reviewed work related documents to verify installation and testing of the 86E2 emergency lockout relay. This LER is closed.

b. Findings

Introduction:

A self-revealing Green NCV of Oconee Nuclear Station TS 3.8.1, AC Sources - Operating, was identified for Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The licensee modified Keowee Hydro Unit 2 electrical protection circuitry with a faster response relay which was susceptible to an existing degraded system condition and ultimately caused Keowee Hydro Unit 2 to be inoperable.

Description:

On August 7, 2013, the licensee replaced emergency lockout relay (86E2),a GE HEA type relay with an electroswitch model as part of the implementation of a permanent plant modification to allow Keowee Hydro units to supply electrical power to the protected service water system (PSW). The modification was necessary to provide additional wiring connections for control inputs to the emergency lockout relay. The new style relay had a faster response time which allowed sensing and thus actuation due to momentary currents in the control circuit. On August 21, 2013, governor TXS catastrophic failure relay (86E2X) provided a false actuation signal to the 86E2 relay and prevented Unit 2 Keowee Hydro from powering its intended emergency AC electrical bus. The false actuation occurred due to mechanical vibration in the governor oil system being transmitted into the generator auxiliaries cabinet where the 86E2X relay was located and causing momentary closure of the 86E2X relay contacts. The licensee performed troubleshooting and was unable to determine the exact cause of the 86E2 relay actuation at that time. The licensee replaced the 86E2 relay with an identical emergency lockout relay and also replaced four susceptible relays in the generator auxiliaries cabinet, tested Keowee Hydro Unit 2, and declared the hydro unit operable on August 24. On September 4, Keowee Hydro Unit 2 experienced a second 86E2 emergency lockout relay actuation during planned testing of the unit. The licensee performed additional troubleshooting and determined that starting of the governor oil pump with system pressure just above the automatic start setpoint created vibration in the oil system and subsequently a blue flash inside the 86E2X relay. The licensee implemented engineering change (EC111358) which moved the 86E2X relay to another cabinet which was not susceptible to the vibration from the governor oil system.

The inspectors identified, from multiple corrective action documents in the licensees corrective action program, that system vibration issues has existed dating back to March, 2000. The inspectors noted that the licensee performed operability determinations which maintained that the governor oil system was operable as long as one pump in the system did not have high vibrations. The inspectors identified the licensee had taken corrective actions which included rebuilding pumps and completing two vendor evaluations of system vibration. On two occasions (2005 and 2010), a vendor had recommended the licensee address system interactions (i.e. high vibrations)which were also contributing to the problem. On the second occasion, the vendor provided specific actions to address system interactions. The inspectors did not discover any licensee corrective actions or evaluation of these system interactions in the modification packages.

In 2004, the licensee implemented a modification to the governor oil system which, in addition to other changes, installed the 86E2X governor TXS catastrophic failure relay.

The licensee did not evaluate the effect of mechanical vibration upon this relay at the time of its installation. In 2013, the licensee implemented a modification which replaced the emergency lockout relay (86E2), a GE HEA type relay, with an electroswitch model.

The licensee did not evaluate the effect of mechanical vibration upon this modification.

The inspectors noted that the licensee indicated that this was a contributing cause of Keowee Hydro emergency lockout and system inoperability which was documented in PIP-O-13-09152.

Technical Specification 3.8.1 requires two Keowee Hydro Units with one capable of automatically providing power through the underground emergency power path to both main feeder buses and the other capable of automatically providing power through the overhead emergency power path to both of the main feeder buses in Modes 1, 2, 3, and

4. From August 7, 2013 until September 4, 2013, Keowee Hydro Unit 2 was susceptible

to a false actuation signal from the 86E2X governor TXS catastrophic failure relay. The licensee determined this condition made Keowee Hydro Unit 2 inoperable for greater than the allowed outage time of TS 3.8.1 of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Analysis:

The licensees failure to properly evaluate a modification to the electrical control circuit of the governor oil system which resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time, was a performance deficiency. The issue was more than minor because it was associated with the equipment performance attribute of the mitigating system cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the modification of the governor oil system including the addition of the 86E2X governor TXS catastrophic relay resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process (SDP), Attachment 4 and Attachment A and determined to require a detailed risk evaluation. A regional SRA performed a risk analysis of the performance deficiency which was found to be Green (CDF < 1E-6/year). The dominant accident sequence was a loss of offsite power where Keowee Unit 1 fails independently and unrelated to the performance deficiency and power is not successfully restored by Oconee operators. The influential factors in the Green result were the limited exposure time (19 days) and the ability to quickly restore power to the unit via the Lee Station gas turbines via the Fant Line. This finding was determined to have a cross-cutting aspect of resolution in the problem identification and resolution cross cutting area because the licensees organization failed to take effective corrective actions to address the issue in a timely manner commensurate with its safety significance. Specifically, the licensee failed to take effective corrective actions to address system interactions (i.e. high vibrations) which ultimately had an adverse effect upon modifications to the governor oil system of the Keowee Hydro Unit 2. (P.3).

Enforcement:

Technical Specification 3.8.1, AC Sources - Operating, requires two Keowee Hydro Units with one capable of automatically providing power through the underground emergency power path to both main feeder buses and the other capable of automatically providing power through the overhead emergency power path to both main feeder buses in Modes 1, 2, 3, and 4. Contrary to the above, from August 7, 2013 until September 4, 2013, Keowee Hydro Unit 2 was inoperable due to governor oil system high vibrations causing chatter in the 86E2X governor TXS catastrophic failure relay which would result in generation of an emergency lockout signal causing the inoperability. The licensee implemented engineering change (EC111358) which moved the 86E2X relay to another cabinet which was not susceptible to the vibration from the governor oil system. Because the finding is of very low safety significance and has been entered into the licensees CAP as PIP-O-13-09152, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000269,270,287/2014005-02, Keowee Hydro Unit 2 Inoperable for Longer Than Allowed TS Outage Time.

4OA6 Management Meetings (Including Exit Meeting)

Exit Meeting Summary

On January 15, 2015, the resident inspectors presented the inspection results to Mr.

Scott 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

None

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Batson, Site Vice President
E. Burchfield, Engineering Manager
R. Guy, Organization Effectiveness Manager
T. Patterson, Safety Assurance Manager
T. Ray, Station Manager
C. Wasik, Regulatory Compliance Manager

NRC

R. Hall, Project Manager, NRR

LIST OF DOCUMENTS REVIEWED

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