IR 05000395/2014002

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IR 05000395-14-002; on 01/01/2014 - 03/31/2014: Virgil C. Summer Nuclear Station, Unit 1; Maintenance Effectiveness and Operability Determinations and Functionality Assessments
ML14122A130
Person / Time
Site: Summer South Carolina Electric & Gas Company icon.png
Issue date: 05/01/2014
From: Mark King
NRC/RGN-II/DRP/RPB5
To: Gatlin T
South Carolina Electric & Gas Co
References
IR-14-002
Download: ML14122A130 (21)
v • d • e


Text

UNITED STATES May 1, 2014

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000395/2014002

Dear Mr. Gatlin:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station, Unit 1. On April 23, 2014, the NRC inspectors discussed the results of this inspection with you and members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

NRC inspectors documented in this report two NRC-identified findings of very low safety significance (Green) and which involved violations of NRC requirements. The NRC is treating the violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the violations or significance of the NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Virgil C. Summer Nuclear Station, Unit 1.

Additionally, 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 Virgil C. Summer Nuclear Station, Unit 1. Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter 0310.

Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross cutting aspect assigned, 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 Virgil C. Summer Nuclear Station, Unit 1.

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

Sincerely,

/RA/

Michael King, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12

Enclosure:

NRC Integrated Inspection Report 05000395/2014002 w/Attachment: Supplemental Information

REGION II==

Docket No. 50-395 License No. NPF-12 Report No. 05000395/2014002 Licensee: South Carolina Electric & Gas (SCE&G) Company Facility: Virgil C. Summer Nuclear Station, Unit 1 Location: P.O. Box 88 Jenkinsville, SC 29065 Dates: January 1, 2014, through March 31, 2014 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector J. Rivera-Ortiz, Senior Reactor Inspector (Section 4OA5)

Approved by: Michael King, Chief Reactor Projects Branch 5 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000395/2014002; 01/01/2014 - 03/31/2014: Virgil C. Summer Nuclear Station, Unit 1;

Maintenance Effectiveness and Operability Determinations and Functionality Assessments The report covered a three-month period of inspection by resident inspectors and a senior reactor inspector from the region. Two NRC-identified findings were identified and determined to be Green, non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. The cross-cutting aspects were determined using IMC 0310, Components Within the Cross Cutting Areas, dated December 19, 2013.

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. 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 System

The inspectors determined that the failure to promptly identify and correct the CAQ for the A CCW pumps inboard bearing oil leak was a performance deficiency (PD). The inspectors reviewed Inspector Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the PD was more than minor and therefore a finding, because it affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of equipment performance.

Specifically, an in-service train of CCW was declared inoperable due to a large oil leak that could have depleted all available oil for inboard bearing lubrication within a short time period. The inspectors reviewed IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and Appendix A - Exhibit 2, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance or Green because the finding was not a design deficiency or loss of function. The cause of the finding involved the cross-cutting area of problem identification and resolution and the aspect of resolution, P.3, because the licensee failed to take effective corrective actions commensurate with an issues safety significance in that they failed to promptly identify and correct an A CCW pump inboard bearing oil leak that was a CAQ. (Section 1R15)

Procedures, and Drawings, for the licensees failure to enter TS 3.5.2, Action a, due to inoperability of the A charging/safety injection (SI) pump during periods when its room cooler was out of service, as required by SAP-209, Operability Determination Process,

Revision 1. The issue was entered into the licensees CAP as condition report CR-14-00778 The inspectors determined that the failure to declare the A SI pump inoperable and enter the respective TS 3.5.2, Action a, when the necessary support room cooler was incapable of performing its function, as required by SAP-209 is a performance deficiency (PD). The inspectors reviewed Inspector Manual Chapter (IMC) 0612 and determined the PD is more than minor because, if left uncorrected, it would have had the potential to lead to a more significant safety concern in that the failure to identify and monitor an applicable technical specification action statement could lead to plant operations outside of TS analyzed conditions. The inspectors reviewed IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and Appendix A - Exhibit 2, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance or Green because the system was not inoperable in excess of the TS allowed outage time. Since the original TS interpretation allowing removal of the SI pump room cooler from service was from 1997, this issue is not indicative of current performance and therefore no cross-cutting aspect is assigned. (Section 1R12)

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at full Rated Thermal Power (RTP) and operated at or near full RTP for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

Seasonal Weather Susceptibilities

a. Inspection Scope

The inspectors performed one seasonal extreme weather inspection for readiness of cold weather for two risk significant components. The inspectors verified the licensee had implemented applicable sections of operations administrative procedure, OAP-109.1, Revision (Rev.) 3G, Guidelines for Severe Weather. The inspectors reviewed preparations for extreme cold weather and walked down the refueling water storage tank (RWST) and associated outside emergency core cooling system (ECCS) suction piping and the sodium hydroxide (NaOH) tank and associated outside piping to assess whether the equipment was adequately protected from cold weather and would function as expected during an accident event. Also, the inspectors reviewed the licensees corrective action program (CAP) database to verify that freeze protection problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns

a. Inspection Scope

The inspectors conducted three partial equipment alignment walkdowns which are listed below, to evaluate the operability of selected redundant trains or backup systems with the other train or system inoperable or out of service (OOS). Correct alignment and operating conditions were determined from the applicable portions of drawings, system operating procedures (SOP), and technical specifications (TS). The inspections included review of outstanding maintenance work orders (WOs) and related condition reports (CRs) to verify that the licensee had properly identified and resolved equipment alignment problems that could lead to the initiation of an event or impact mitigating system availability. Documents reviewed are listed in the Attachment.

  • Partial walkdown of A EDG during planned maintenance on B EDG

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Protection Walkdowns

a. Inspection Scope

The inspectors reviewed recent CRs, WOs, and impairments associated with the fire protection system. The inspectors reviewed surveillance activities to determine whether they supported the operability and availability of the fire protection system. The inspectors assessed the material condition of the active and passive fire protection systems and features, and observed the control of transient combustibles and ignition sources. Documents reviewed are listed in the Attachment. The inspectors conducted routine inspections of the following five areas (respective fire zones also noted):

  • Auxiliary building 397 elevation (fire zone AB-1.4)
  • Relay room, solid state protection system (SSPS) instrumentation, and inverter (fire zones CB-6, CB-10 CB-12)
  • 1DA switchgear room (fire zone IB-20)
  • 1DB switchgear rooms and heating, ventilation & air conditioning (HVAC) rooms (fire zones IB-16, IB-17, IB-22.2)

b. Findings

No findings were identified.

1R07 Heat Sink Performance

Annual Review

a. Inspection Scope

The inspectors conducted one heat sink performance sample. The inspectors reviewed a visual inspection report for the B EDG lube oil heat exchanger, jacket water heat exchanger and intercooler heat exchanger. The inspectors reviewed the applicable health reports, and verified that the heat exchanger performance issues were entered into the licensees CAP.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Quarterly Review of Operator Requalification

a. Inspection Scope

The inspectors observed an operator requalification training scenario occurring on March 3, 2014, and involving a unit shutdown sequence in preparation for refueling outage activities. The inspectors observed crew performance in terms of communications; ability to prioritize failures in order to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions and, when required, emergency action levels as the Site Emergency Director. The inspectors reviewed the licensees critique comments to verify that performance deficiencies were captured for appropriate corrective action.

b. Findings

No findings were identified.

.2 Resident Quarterly Observation of Control Room Operations

a. Inspection Scope

During the inspection period, the inspectors conducted observations of licensed reactor operator activities to ensure consistency with licensee procedures and regulatory requirements. For the three listed activities, the inspectors observed the following elements of operator performance: 1) operator compliance and use of plant procedures including technical specifications; 2) control board component manipulations; 3) use and interpretation of plant instrumentation and alarms; 4) documentation of activities; 5) management and supervision of activities; and 6) control room communications.

  • Observation of A EDG maintenance run
  • B Train SSPS testing

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated three equipment issues described in the CRs listed below to verify the licensees effectiveness with the corresponding preventive or corrective maintenance associated with structure, system, and components (SSCs). The inspectors reviewed Maintenance Rule (MR) implementation to verify that component and equipment failures were identified, entered, and scoped within the MR program.

Selected SSCs were reviewed to verify proper categorization and classification in accordance with 10 CFR 50.65. The inspectors examined the licensees 10 CFR 50.65(a)(1) corrective action plans to determine if the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were established and effective. The inspectors review also evaluated if maintenance preventable functional failures or other MR findings existed that the licensee had not identified. The inspectors reviewed the licensees controlling procedures consisting of engineering services procedure, ES-514, Rev. 6, Maintenance Rule Program Implementation, and station administrative procedure, SAP-0157, Rev. 1, Maintenance Rule Program, to verify consistency with the MR program requirements.

  • CR-13-03733, existing oil leak on the A component cooling water (CCW) pump results in the pump being declared inoperable
  • CR-14-00760, Maintenance Rule (a)(1) goal setting is established on the chill water (VU) system due to repetitive issues resulting in excessive unavailability of the A chiller
  • CR-13-02406, Maintenance Rule (a)(1) goal setting is established on the local ventilation and cooling system due to repetitive issues with the A and B safety injection (SI) pump room cooler fans

b. Findings

Introduction:

The NRC identified a Green, non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to enter TS 3.5.2, Action a, due to inoperability of the A charging/SI pump during periods when its room cooler was out of service, as required by SAP-209, Operability Determination Process, Rev. 1.

Description:

The licensee initiated the following CRs for failure of the A SI pump room coolers due to spurious thermal overload trips:

  • CR-13-00841 on February 23, 2013
  • CR-13-01223 on March 19, 2013
  • CR-13-01245 on March 21, 2013 For each of the above events, the inspectors noted that the licensee did not declare the A SI pump inoperable. Each of the three SI pump rooms has their own dedicated, safety-related room cooler. The inspectors reviewed TS 3.7.9, Area Temperature Monitoring, which provides a room temperature limit for each of the SI pump rooms, as well as other areas. The inspectors also reviewed TS interpretation, TS Relocation (TSR) 1020, Rev. 6, which stated in part that any of the room coolers for either SI pump room could be taken out of service for up to 7 days, provided temperature monitoring was performed. The inspectors noted that similar verbiage existed in previous revisions back to TSR 1020, Rev. 1, dated April 17, 1997. However, TSR 1020, Rev. 0, dated November 17, 1995, additionally stated, in part: Enter the most limiting TS action for the applicable mode: 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement with only 1 pump operable (TS 3.1.2.4, 3.5.2). The inspectors noted that this statement was missing in TSR 1020, Rev. 1 through Rev. 6, which is the latest revision.

The inspectors evaluated related licensee design documentation to review room temperature calculations for respective equipment qualification (EQ) limits. The inspectors noted that Design calculation, DC00020-229, Charging/SI Pump Room AB-12 Heat-up Calculation, Rev. 0, dated August, 2011, and respective figure 6-1, Auxiliary Bldg. El. 388 Charging/SI Pump Cubicle Temperature, showed a temperature graph of approximately 198°F and increasing at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following a loss of chilled water to the room cooler. Furthermore, the most limiting equipment temperature, 140°F, identified by TS 3.7.9 was reached in 39 minutes.

The inspectors noted that TS defines operability as: a system, subsystem, train, component or device shall be operable or have operability when it is capable of performing its specified function(s), and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function(s) are also capable of performing their related support function(s). Also, TS LCO 3.5.2, ECCS Subsystems - TAVG 350°F, requires that while the plant is in Modes 1, 2 and 3, two independent ECCS subsystems shall be operable, where an ECCS subsystem consists in part of one operable centrifugal charging/SI pump. TS 3.5.2, Action a, requires that, with one ECCS subsystem inoperable, restore the inoperable subsystem to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in hot shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The inspectors reviewed SAP-209, Operability Determination Process, Rev. 1, of which step 6.3.4.B.5, states, in part: The Shift Supervisor shall enter the appropriate Tech Spec required action if a Tech Spec SSC or Tech Spec support SSC is affected.

Consequently, the inspectors concluded that for each of the above occurrences of room cooler inoperability, the licensee was required to declare the respective SI pump inoperable and enter TS 3.5.2, Action a. The inspectors also concluded that failure to identify and monitor an applicable technical specification action statement could lead to plant operations outside of TS analyzed conditions.

Additionally, the inspectors determined that CR-03-03179 dated October 9, 2003, identified a past NRC concern related to TSR-1020 and listed the following as one of the concerns: Allowing specific support equipment to be out of service is contrary to the concept of operability which requires all necessary attendant equipment to be capable of performing the related support functions. The inspectors concluded that given this CR, TSR 1020, Rev 0, and DC00020-229, Rev. 0, the underlying cause of the issue was reasonably within the licensees ability to foresee and correct prior to 2013.

Analysis:

The inspectors determined that the failure to declare the A SI pump inoperable and enter the respective TS 3.5.2, Action a, when the necessary support room cooler was incapable of performing its function, as required by SAP-209 is a performance deficiency (PD). The inspectors reviewed inspector Manual Chapter (IMC)0612 and determined the PD is more than minor because, if left uncorrected, it would have had the potential to lead to a more significant safety concern in that the failure to identify and monitor an applicable TS action statement could lead to plant operations outside of TS analyzed conditions. The inspectors reviewed IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and Appendix A - Exhibit 2, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance or Green because the system was not inoperable in excess of the TS allowed outage time. Since the original TS interpretation allowing removal of the SI pump room cooler from service was from 1997, this issue is not indicative of current performance and therefore no cross-cutting aspect is assigned.

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, states in part that activities affecting quality shall be accomplished by documented procedures. Contrary to the above, on February 22, March 19, and March 21, 2013, the licensee failed to adequately accomplish procedure SAP-209 which required the shift supervisor to enter TS 3.5.2, Action a, for inoperability of the A SI pump during periods when the A SI room cooler was out of service. Because this violation was of very low safety significance and was entered into the licensee's corrective action program as CR-14-00778, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000395/2014002-01, Failure to Declare the A Safety Injection Pump Inoperable and Enter TS 3.5.2 Action a.

1R13 Maintenance Risk Assessment and Emergent Work Control

a. Inspection Scope

The inspectors performed risk assessments, as appropriate, for the five selected work 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 emergent work problems were adequately identified and resolved. The inspectors evaluated the licensees work prioritization and risk characterization to determine, as appropriate, whether necessary steps were properly planned, controlled, and executed for the planned and emergent work activities.

  • Work Week 01, yellow risk condition for scheduled maintenance of B RHR pump
  • Work Week 02, yellow risk condition for scheduled maintenance and inspections of B SW pump
  • Work Week 07, yellow risk condition for scheduled maintenance on the alternate seal injection diesel generator
  • Work Week 10, yellow risk condition for scheduled maintenance on A EDG
  • Work Week 11, yellow risk condition for scheduled maintenance on the alternate seal injection system discharge relief valve

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed four operability evaluations listed below, affecting risk significant mitigating systems to assess, as appropriate: 1) the technical adequacy of the evaluations; 2) whether operability was properly justified and the subject component or system remained available, such that no unrecognized increase in risk occurred; 3) whether other existing degraded conditions were considered; 4) that the licensee considered other degraded conditions and their impact on compensatory measures for the condition being evaluated; and 5) the impact on TS limiting conditions for operations and the risk significance in accordance with the significance determination process. The inspectors also verified that the operability evaluations were performed in accordance with SAP-209, Rev. 1, Operability Determination Process, and SAP-999, Rev. 11, Corrective Action Program.

  • CR-13-03733, NRC identified inboard bearing oil leak on the A CCW pump
  • CR-13-04132, void discovered near emergency feed SW header B cross-connect valve
  • CR-13-03685, heat transfer capability of reactor building cooling units (RBCUs)cannot be determined due to inconclusive test data
  • CR-14-00321, AREVA Loose Parts Monitor had incorrect version of digital software installed since initial RF17 installation

b. Findings

Introduction:

The NRC identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," for the licensees failure to promptly identify and correct a condition adverse to quality (CAQ) involving an inboard bearing active oil leak on the A CCW pump on August 9, 2013. Specifically, the licensee failed to identify the oil leak as a CAQ, and their corrective actions were not effective for trending the active oil leak condition before the leak increased and challenged pump operability on September 9, 2013.

Description:

During a routine plant walk down on August 8, 2013, the inspectors identified oil collecting under the inboard area of the A CCW pump. The inspectors researched control room logs and reasoned that the oil leak could be related to the cause for 4 ounces of oil added to the inboard bearing oiler on July 20, 2013, and that an apparent active leak existed.

The inspectors provided pictures of the oil leak to the licensee who entered the problem in their CAP as CR-13-03290 dated August 9, 2013. The inspectors noted that CR-13-03290 stated that the area was wiped down and that the licensee would monitor.

Although no actions were attached to CR-13-03290, the inspectors noted that work order (WO) 1312668 was linked to the CR, stated, oil leakage appears to be from the pump inbd [inboard] bearing at ~2 drops/hr, and was approved for planning on August 9, 2013. However, the inspectors determined that no work was performed under the work order.

On September 9, 2013, the licensee observed that the inboard bearing oiler was empty and that oil was on the A CCW skid near the inboard side of the pump. The licensee immediately declared the pump inoperable, initiated CR-13-03733 and placed the C CCW pump in service aligned to the A train. The inspectors noted that repairs were completed under WO 1313581 which documented that a threaded ring for the inboard bearing labyrinth seal required tightening 1/32 of an inch in order to stop the oil leak.

The inspectors reviewed the maintenance rule evaluation for CR-13-03733 and noted the evaluation stated in part that the inboard bearing oil reservoir contains 128 ounces of oil and that at all times there was enough oil in the reservoir. The inspectors determined that based on the function of the oil lubrication slinger ring, only a portion of the oil reservoir is available for lubricating the bearing. The inspectors discussed this with the licensee who later documented in CR-14-00525 that only 17.727 ounces of oil was available to the bearing with the inboard oiler empty.

The inspectors determined that the licensee could have reasonably repaired the leak before September 9, 2013, because WO 1312668 specifically noted the leak location.

The inspectors also determined that the leak eventually challenged the A CCW operability and was therefore a CAQ. The inspectors also noted that CR-13-03290 was classified as category 4N/A. SAP-0999, Corrective Action Program, Rev. 11, states in part issues that are Safety Related or Quality Related that pose a Condition Adverse to Quality should be at least a Category 3 issue. Inspectors therefore concluded that the licensee failed to promptly identify a condition adverse to quality, and as a result incorrectly categorized CR-13-03290.

Analysis:

The inspectors determined that the failure to promptly identify and correct the CAQ for the A CCW pumps inboard bearing oil leak was a PD. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, dated Sepetember 7, 2012, and determined the PD was more than minor and therefore a finding, because it affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of equipment performance. Specifically, an in-service train of CCW was declared inoperable due to a large oil leak that could have depleted all available oil for inboard bearing lubrication within a short time period. The inspectors reviewed IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and Appendix A - Exhibit 2, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance or Green because the finding was not a design deficiency or loss of function. The cause of the finding involved the cross-cutting area of problem identification and resolution and the aspect of resolution, P.3, because the licensee failed to take effective corrective actions commensurate with an issues safety significance in that they failed to promptly identify and correct an A CCW pump inboard bearing oil leak that was a CAQ.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI states, in part, that measures shall be established to assure that CAQs are promptly identified and corrected. Contrary to the above, on August 9, 2013, the licensee failed to promptly identify and correct a CAQ involving an inboard bearing active oil leak on the A CCW pump. Specifically, the licensee failed to identify the oil leak as a CAQ and their corrective actions were not effective for trending the active oil leak condition before the leak increased and challenged pump operability on September 9, 2013. Because the finding was of very low safety significance (Green) and was entered into the licensees CAP as CR-13-03733, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000395/2014002-02, Failure to Promptly Identify and Correct a Condition Adverse to Quality for an Inboard Bearing Oil Leak on the A CCW Pump.

1R19 Post Maintenance Testing

a. Inspection Scope

For the four maintenance activities listed below, the inspectors reviewed the associated post-maintenance testing (PMT) procedures and either witnessed the testing and/or reviewed test records to assess whether: 1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel; 2) testing was adequate for the maintenance performed; 3) test acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents; 4) test instrumentation had current calibrations, range, and accuracy consistent with the application; 5) tests were performed as written with applicable prerequisites satisfied; 6) jumpers installed or leads lifted were properly controlled; 7) test equipment was removed following testing; and, 8) equipment was returned to the status required to perform its safety function. The inspectors verified that these activities were performed in accordance with general test procedure (GTP)-214, Post Maintenance Testing Guideline, Rev. 5, Change B.

  • WO 1400405-01, perform SW pump performance test on B SW pump following pump and motor re-installation
  • WO 1206909-01, replace thermal overload and associated relay assembly for B SI pump room cooler

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed and/or reviewed six surveillance test procedures (STPs) listed below to verify that TS or risk significant surveillance requirements were followed and that test acceptance criteria were properly specified to ensure that the equipment could perform its intended safety function. The inspectors verified that proper test conditions were established as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria were met.

In-Service Tests:

  • STP- 205.004, RHR Pump and Valve Operability Test, Rev. 8A
  • STP-112.003, Reactor Building Spray System Valve Test, Rev. 9D Other:
  • STP-111.001, Seismic Instrumentation Channel Check, Rev. 7
  • STP-106.001, Moveable Rod Insertion Test, Rev. 6A
  • STP-506-001, Pressurizer Heater Capacity Test, Rev. 7D

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period January 1, 2013, through December 31, 2013. The inspectors used the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Rev. 7, Regulatory Assessment Performance Indicator Guideline, and licensee procedure SAP-1360, Rev. 2, NRC and INPO/WANO Performance Indicators, to check the reporting of each data element. The inspectors sampled licensee event reports (LERs), operator logs, tagout records, plant risk records, plant status reports, CRs, and performance indicator data sheets to verify that the licensee had properly reported the PI data. Also, the inspectors discussed the PI data with the licensee personnel associated with the performance indicator data collection and evaluation.

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

b. Findings

No findings were identified.

4OA3 Event Followup

.1 (Closed) LERs 05000395/2013-001-00 and 05000395/2013-001-01: Grid Disturbance

Results in an Engineered Safeguard Features Actuation of the A EDG On May 22, 2012, the licensee issued a licensee event report (LER) based on an undervoltage relay actuation on the A train 7200 Volt switchgear bus and a consequent start of the standby A EDG following a lightning induced grid disturbance approximately 17 to 19 miles from the site. On November 19, 2013, the licensee issued Revision 1 to this LER to better explain the details associated with the relay actuation and start of the A EDG. The licensee issued CR-13-01346 to document this event and determine appropriate corrective actions. The inspectors completed an extensive review of both LER revisions. The inspectors noted that the licensee continues to evaluate and develop actions for improved lightning protection for site structures, systems, and components. No findings or violations of NRC requirements were identified. The LERs are closed.

.2 (Closed) LER 50-395/2013006-00: Securing Control Room Ventilation Emergency

Recirculation While Associated Radiation Monitor Was Out Of Service On December 4, 2013, the B train control room ventilation was in the emergency mode of operation as required by TS since the control room supply air radiation monitor was out of service for calibration. However, when the calibration could not be completed, an operator mistakenly returned the CR ventilation to normal operation using the wrong step in the system operating procedure which secured control room emergency ventilation for approximately 30 seconds in violation of TS 3.3.3.1, Table 3.3-6, Action 29. The licensee entered this problem into the CAP as CR-13-05083 and performed an apparent cause evaluation (ACE). The inspectors reviewed the CR and related ACE and determined that the failure to adequately implement the procedure was contrary to TS 6.8.1 and therefore a PD. The inspectors reviewed the NRC Enforcement Policy and determined the PD was of minor significance because the error was an isolated occurrence and there were no safety consequences during the short duration of ventilation misalignment. This failure to comply with TS 3.3.3.1 and 6.8.1 constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. This LER is closed.

.3 Earthquake

On February 14, 2014, at approximately 10:23 p.m. Eastern Standard Time (EST), the site experienced an earthquake with a magnitude of 4.1 on the Richter scale and an epicenter located near Edgefield, SC, or approximately 54 miles south and west from Unit 1. The control room received no alarms and the seismic instrumentation was not initiated from this event. The licensee entered their abnormal operating procedure, AOP-610.1, Seismic Event Response, Rev. 0, at 10:35 p.m., confirmed an earthquake had occurred via the United States Geographical Survey (USGS) website by 10:40 p.m.,

and declared a Notification of Unusual Event (NOUE) at 10:45 p.m., based on a seismic event felt in the control room and confirmation by the USGS National Earthquake Information Center. The licensee subsequently completed site walk-downs and an engineering evaluation neither of which identified any problems or damage. The inspectors responded to the event, monitored licensee actions and performed a follow-up review of applicable documents with plant walk-downs to verify the licensees conclusion of no impact to the site. Documents reviewed are listed in the Attachment.

4OA5 Other Activities

.1 (Closed) Temporary Instruction 2515/182 - Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks, Phase 2

a. Inspection Scope

The inspectors reviewed records and procedures related to the licensees program for buried piping and underground piping and tanks in accordance with Phase II of Temporary Instruction (TI) 2515/182 to confirm that the licensees program contained attributes consistent with Sections 3.3.A and 3.3.B of Nuclear Energy Institute (NEI)09-14, Guideline for the Management of Buried Piping Integrity, Rev. 3, and to confirm that these attributes were scheduled and/or completed by the NEI 09-14 deadlines.

The inspectors interviewed licensee staff responsible for the buried piping program and reviewed program related activities to determine if the program attributes were accomplished in a manner which reflected acceptable practices in program management.

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the TI, and the inspectors confirmed completion of the program activities which occurred following the previous Phase I inspection. The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff. Additionally, the inspectors reviewed the licensees risk ranking process and implementation of the inspection plan using the guidance of paragraph 03.04 and 03.05 of the TI.

b. Findings

No findings were identified. Based upon the scope of the review described above, Phase II of TI-2515/182 was completed.

.2 Annual ECCS Evaluation Model Revisions Report

The licensee submitted an annual emergency core cooling system (ECCS) model revisions report on June 13, 2013 and the supplemental report was submitted to NRC on January 13, 2014. The NRC staff determined that the licensees report dated June 13, 2013, addressed the requirements contained in 10 CFR 50.46 related to estimating the effects of changes to the application that the licensee failed to submit a 30-day report as required by 10 CFR 50.46(a)(3)(ii).

The NRC staff issued a closure letter dated March 5, 2014, concerning the licensees 2012 annual emergency ECCS evaluation model revisions report and determined that the estimate satisfied the intent of the 10 CFR 50.46 reporting requirements because the estimate effect of the upflow conversion did not cause the results of the ECCS evaluation to exceed 10 CFR 50.46(b) acceptance criteria, and because the estimate was calculated using the NARC-approved NOTRUMP evaluation model. In addition, since the licensee performed a sufficient break spectrum to demonstrate that the limiting break size had been identified, the inspectors determined that the licensee had inherently satisfied the analysis requirement contained in 10 CFR 50.46(a)(3)(ii).

The inspectors evaluated this finding against the reactor oversight process (ROP) and determined that violation was a minor violation. The failure to make a report was an administrative nature and it had no adverse impact to the cornerstone objective.

Therefore, this failure to comply with a 30-day report as required by 10 CFR 50.46(a)(3)

(ii) constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. The licensee entered it into the CAP as CR-14-00719.

.3 (Closed) Severity Level IV Violation 05000395/2013-09-01, Installation of Modification

Using Superseded version of Procedure The NRC issued the Notice of Violation (NOV) to South Carolina Electric & Gas Company (SCE&G) dated August 6, 2013, for a Severity Level IV violation concerning deliberate misconduct by contract employees, failure to follow plant procedural requirements by contract employees, lack of oversight of contract workers, and inadequate corrective actions. The inspectors reviewed the licensees response letter to the NOV dated September 5, 2013, and determined that the response meets the requirements of 10 CFR 2.201. The inspectors also determined that the corrective actions listed in the response which have been taken or will be taken to prevent recurrence are adequate. These corrective actions were documented in the licensees corrective action program as CR-13-03241. Therefore, this violation is considered closed.

.4 Cross-Cutting Aspects

The table below provides a cross-reference from the 2013 and earlier findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014, will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting New Cross-Cutting Aspect Aspect 05000395/2013008-01 H.4(c) H.2 05000395/2013010-01 H.2(b) H.9 05000395/2013010-02 H.2(b) H.9 05000395/2013010-03 H.4(b) H.8 05000395/2013004-01 H.3(a) H.5 05000395/2013004-02 P.1(d) P.3 05000395/2013004-03 H.2(d) H.1

4OA6 Meetings, Including Exit

On April 23, 2014, the resident inspectors presented the integrated inspection report results to Mr. T. Gatlin and other members of the licensee staff. The licensee acknowledged the results of these inspections. The inspectors confirmed that inspection activities discussed in this report did not contain proprietary material.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Archie, Senior Vice President, Nuclear Operations
A. Barbee, Director, Nuclear Training
M. Browne, Manager, Quality Systems
M. Coleman, Manager, Health Physics and Safety Services
G. Douglass, Manager, Nuclear Protection Services
T. Gatlin, Vice President, Nuclear Operations
M. Harmon, Manager, Chemistry Services
R. Haselden, General Manager, Organizational / Development Effectiveness
R. Justice, Manager, Nuclear Operations
G. Lippard, General Manager, Nuclear Plant Operations
M. Mosley, Manager, Nuclear Training
D. Perez, Supervisor, Health Physics - Technical Support
S. Reese, Specialist, Nuclear Licensing
D. Shue, Manager, Maintenance Services
W. Stuart, General Manager, Engineering Services
B. Thompson, Manager, Nuclear Licensing
J. Wasieczko, Manager, Organization Development and Performance
D. Weir, Manager, Plant Support Engineering
B. Wetmore, Design Engineering
R. Williamson, Manager, Emergency Planning
S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000395/2014002-01 NCV Failure to Declare the A Safety Injection Pump Inoperable and Enter TS 3.5.2 Action a (Section 1R12)
05000395/2014002-02 NCV Failure to Promptly Identify and Correct a Condition Adverse to Quality for an Inboard Bearing Oil Leak on the A CCW Pump (Section 1R15)

Closed

05000395/2013001-00 LER Grid Disturbance Results in an Engineered Safeguard Features Actuation of the A EDG (Section 4OA3.1)
05000395/2013001-01 LER Grid Disturbance Results in an Engineered Safeguard Features Actuation of the A EDG (Section 4OA3.1)
05000395/2013006-00 LER Securing Control Room Ventilation Emergency Recirculation While Associated Radiation Monitor was Out of Service (Section 4OA3.2)

TI 2515/182 TI Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase II (Section 4OA5.1)

05000395/2013009-01 VIO
05000395/2013-09-01, Installation of Modification Using Superseded version of Procedure (Section 4OA5.3)

LIST OF DOCUMENTS REVIEWED

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