IR 05000395/2014007

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IR 05000395/2014007; on 10/6/2014 - 11/7/2014 Virgil C. Summer Nuclear Station, Unit 1; Component Design Bases Inspection
ML14357A328
Person / Time
Site: Summer South Carolina Electric & Gas Company icon.png
Issue date: 12/22/2014
From: Nease R
NRC/RGN-III/DRS/EB1
To: Gatlin T
South Carolina Electric & Gas Co
References
IR 2014007
Download: ML14357A328 (31)
v • d • e


Text

UNITED STATES ember 22, 2014

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION UNIT 1 - U. S. NUCLEAR REGULATORY COMMISSION COMPONENT DESIGN BASES INSPECTION REPORT 05000395/2014007

Dear Mr. Gatlin:

On November 7, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station, Unit 1, and discussed the results of this inspection with yourself and members of your staff. In addition, on November 24, 2014, the inspectors conducted a final exit meeting via telephone with Mr. B. Thompson and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented four findings of very low safety significance (Green) in this report.

These findings involved violations of NRC requirements.

If you contest the violations or significance of these non-cited violations (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 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.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document 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/

Rebecca L. Nease, Branch Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-395 License Nos.: NPF-12

Enclosure:

Inspection Report 05000395/2014007 w/ Attachment: Supplementary Information

REGION II==

Docket No.: 50-395 License No.: NPF-12 Report No.: 05000395/2014007 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: October 6, 2014 - November 7, 2014 Inspectors: N. Coovert, Senior Reactor Inspector (Acting) (Lead)

J. Eargle, Senior Reactor Inspector (Lead)

R. Kopriva, Senior Reactor Inspector T.C. Su, Reactor Inspector A. Popova, General Engineer (NSPDP) (Trainee)

H. Campbell, Contractor (Mechanical)

N. Patel, Contractor (Electrical)

Approved by: Rebecca Nease, Branch Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY

IR 05000395/2014007; 10/6/2014 - 11/7/2014 Virgil C. Summer Nuclear Station, Unit 1;

Component Design Bases Inspection.

This inspection was conducted by a team of five Nuclear Regulatory Commission (NRC)inspectors from Regions II and IV, and two NRC contract personnel. Four Green non-cited violations (NCVs) were identified. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red) using the NRC Inspection Manual Chapter (IMC) 0609,

Significance Determination Process, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas dated January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 201

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Procedures and Programs, for the licensees failure to follow procedure requirements to perform 10CFR50.59 screenings/evaluations on scaffolding and special orders for approximately 97 scaffolds that existed in the plant for greater than 90 days at power operation and four special orders that provided guidance to the operations department outside normal routines. In response to this issue, the licensee initiated condition reports (CR) CR-14-05650, CR-14-05692, CR-14-05694, CR-14-05695, CR-14-05696, CR-14-05766, and CR-14-05446. The licensee performed an immediate operability determination in CR-14-05446 and determined potentially affected equipment remained operable.

The team determined that the performance deficiency was more than minor because it affected the Design Control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the team identified multiple examples where the licensee failed to evaluate temporary changes to the facility in accordance with station procedures, which could affect the availability, reliability, and capability of systems that respond to events. The team determined the finding to be of very low safety significance (Green) because it was not a design deficiency, did not represent the loss of system safety function, and did not represent a loss of function of TS or Non-TS equipment.

The team determined the finding was indicative of present licensee performance, and was associated with the cross-cutting aspect of Procedure Adherence, in the area of Human Performance. Specifically, the licensee failed to screen temporary plant changes as required by procedures. [H.8] (Section 1R21.2)

Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow station procedures to perform operability/functionality evaluations for condition reports (CRs)that affected structures, systems, and components (SSCs). Specifically, the licensee failed to properly screen, evaluate, and document operability or functionality determinations for six CRs that affected SSCs. Following identification by the team, the licensee generated CR-

14-05700 and CR-14-05676. The licensee subsequently evaluated the six CRs, determined there were no impacts on the operability of the affected SSCs, and updated the CRs to include operability determinations.

The team determined that the performance deficiency was more than minor, because if left uncorrected, it had the potential to lead to a more significant safety concern.

Specifically, the licensee failed to perform operability/functionality reviews for CRs with administrative issues of concern that affected SSCs and that could result in safety-related SSCs being inoperable and remain undetected for a period of time. The team determined the finding to be of very low safety significance (Green) because it was not a design deficiency, did not represent the loss of system safety function, and did not represent a loss of function of technical specification (TS) or Non-TS equipment. The team determined the finding was indicative of present licensee performance and was associated with the cross-cutting aspect of Identification, in the area of Problem Identification and Resolution.

Specifically, the licensee did not identify issues completely, accurately, and in a timely manner in accordance with the program. [PI.1] (Section 1R21.2)

Specifically, the licensee failed to consider instrument uncertainties associated with the control room annunciator RWST Empty alarm at 6% with respect to the critical vortex level and second, the RWST indicated level of 10% at which pumps would be secured in emergency operating procedures (EOPs). Following identification by the team, the licensee generated CR-14-05792, CR-14-05869, and CR-14-05868 to address the finding. The licensee also revised procedure EOP-2.2,ES-1.3, Transfer to Cold Leg Recirculation, to Rev. 17. The licensee performed an operability determination and concluded that the safety injection system was operable but degraded.

The team determined that the performance deficiency was more than minor because it affected the Design Control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to consider uncertainties associated with the level alarms and level indicators for the RWST, and as a result, impacted the availability, reliability, and capability of the ECCS to respond to initiating events. The team determined the finding to be of very low safety significance (Green)because it was a deficiency affecting the design or qualification of a mitigating structures, systems, and components (SSC), and the SSC maintained its operability or functionality.

The team determined that no cross-cutting aspect was applicable because the finding was not indicative of present licensee performance. (Section 1R21.2)

Cornerstone: Barrier Integrity

Criterion III, Design Control, for the licensees failure to account for instrument uncertainty on the containment bulk average temperature instrumentation used in calculation DC00020-005, Steam Generator Replacement Reactor Building Temperature/Pressure - LOCA,

Rev. 6, Status A. Specifically, the licensee (1) failed to consider instrument uncertainty when verifying compliance with technical specification (TS) containment operability and design basis accident analysis; and (2) failed to consider instrument drift for reactor building resistance temperatures devices when calibration was not performed for 21 years.

Following identification by the team, the licensee generated CR-14-05864, CR-14-05897, and CR-14-05888. The licensee performed an operability determination and determined the temperature monitoring system was operable with interim actions. The licensee revised procedure OAP-106.1, Operating Rounds, Rev. 16e to incorporate the instrument uncertainty identified in the operability determination.

The team determined that the performance deficiency was more than minor because it was associated with the Configuration Control attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to ensure that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, by not accounting for the instrument uncertainty on the containment bulk average temperature instrumentation, the containment temperature could unknowingly exceed the design basis and TS operability limit. The team determined the finding to be of very low safety significance (Green) because it did not result in an open pathway in containment and did not involve hydrogen igniters. The team determined that no cross-cutting aspect was applicable because the finding was not indicative of present licensee performance. (Section 1R21.2)

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

Main article: IP 71111.21

.1 Inspection Sample Selection Process

The team selected risk-significant components and related operator actions for review using information contained in the licensees probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1E-6. The sample included 15 components, 2 of which were associated with containment large early release frequency (LERF), and 6 operating experience (OE) items.

The team performed a margin assessment and a detailed review of the selected risk-significant components and associated operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR). This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Manual Chapter 0326 conditions, NRC resident inspector input regarding problem equipment, system health reports, industry OE, and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, OE, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.

.2 Component Reviews

a. Inspection Scope

Components

  • Alternate Seal Injection Pump - [XPP0230]
  • Alternate Seal Injection Diesel Generator - [XEG0101]
  • Component Cooling Water Surge Tank - [XTK0003]
  • Turbine Driven Emergency Feedwater Pump - [XPP-8]

[XVC01009A/B/C]

  • 7.2 Kilovolt (KV) ESF Switchgear - [XSW1DX]
  • Class 1E 125 Volts (V) Direct Current (DC) Battery Chargers - [XBC-1A/B]
  • Class 1E 125 VDC Batteries - [XBA-1A/B]
  • EDG Room Cooling Fans - [XFN0075A/B, XFN0045A/B]
  • Transformer - [XTF5052]

Components with LERF Implications

  • Pressurizer Power-Operated Relief Valves (PORVs) - [PCV00444B, PCV00445A/B]

For the 15 components listed above, the team reviewed the plant technical specifications (TS), UFSAR, design bases documents, and drawings to establish an overall understanding of the design bases of the components. Design calculations and procedures were reviewed to verify that the design and licensing bases had been appropriately translated into these documents. Test procedures and recent test results were reviewed against design bases documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents, and that individual tests and analyses served to validate component operation under accident conditions. Maintenance procedures were reviewed to ensure components were appropriately included in the licensees preventive maintenance program. System modifications, vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action program documents were reviewed (as applicable) in order to verify that the performance capability of the component was not negatively impacted, and that potential degradation was monitored or prevented.

Maintenance Rule information was reviewed to verify that the component was properly scoped, and that appropriate preventive maintenance was being performed to justify current Maintenance Rule status. Component walkdowns and interviews were conducted to verify that the installed configurations would support their design and licensing bases functions under accident conditions, and had been maintained to be consistent with design assumptions.

Additionally, the team performed the following specific reviews:

  • The team reviewed calculation, DC00300-134, Human Reliability Analysis, Revision (Rev.) 8, Status A, for low margin time critical operator actions. The team reviewed the stations methodology, which included engineering, operations, probabilistic risk assessment, and licensing procedures, for developing time critical actions required for postulated UFSAR Chapter 15 events.
  • The team reviewed operator actions associated with the transfer of the emergency core cooling system and containment spray system to cold leg recirculation mode during a postulated loss of coolant accident event. This review included verification of the identified time critical actions listed in operations administrative procedure, OAP-101.3, Timeline Validation Requirements, Rev. 1, and the times assumed in design calculations. The team performed interviews with operations and engineering personnel to discuss plant modifications and resulting calculations that affected the refueling water storage tank swapover time critical action.
  • The team reviewed operator actions associated with boron dilution postulated events at various plant modes of operation. This review included verification of design basis calculations and the UFSAR revision associated with time critical actions in procedure OAP-101.3.
  • The team performed interviews and conducted walkdowns of selected procedures to assess if the time critical operator actions required could be successfully accomplished. The team also reviewed main control deficiencies and operator burden lists; rounds and turnover deficiencies; and long-term clearance orders, scaffolding, and temporary modifications to determine if existing plant issues or configurations may affect operators ability to complete required manual actions.
  • As part of the component review for service water booster pumps, the team reviewed service water cooling to containment and the associated resistance temperatures devices (RTDs) measuring containment temperatures, ITE07307H/I/M/O/Q/S/T/V/W.

The team also reviewed containment cooling calculations, RTD maintenance, containment temperature alarms, and operator procedures.

b. Findings

b.1 Failure to Follow Procedures for Scaffolding and Special Orders for 10CFR50.59 Screenings/Evaluations

Introduction:

The team identified a Green non-cited violation (NCV) of TS 6.8.1, Procedures and Programs, for the licensees failure to follow procedure requirements to perform 10CFR50.59 screenings/evaluations on scaffolding and special orders.

Specifically, the licensee failed to perform 10CFR50.59 screenings/evaluations as required by procedures for approximately 97 scaffolds that existed in the plant for greater than 90 days at power operation and four special orders that provided guidance to the operations department outside normal routines.

Description:

Step 2.2.2.C. of station administrative procedure, SAP-0107, 10CFR50.59 Review Process, Rev. 5, stated in part, the scope of the procedure applied to temporary facility changes resulting from activities in support of maintenance that were in effect at power greater than 90 days. Step 5.6.24 of maintenance procedure, CMP-100.009, Scaffold Request, Evaluation, and Erection, Rev. 8, Change A, and Step 6.1.12 of engineering services procedure, ES-0409, Engineering Evaluation of Scaffolding, Temporary Shielding and Designated Storage Area Change Requests, Rev. 5, stated in part, that if scaffolding or temporary shielding was to remain in the plant during power operations for more than 90 days, then completion of a 10CFR50.59 screening/evaluation was to be performed. The team identified approximately 97 scaffolds that existed in the plant for greater than 90 days at power operations that the licensee did not perform 10CFR50.59 screenings/evaluations as required by station procedures.

Because of the team's finding, the licensee performed scaffolding walkdowns to assess potential impact on structures, systems, and components (SSCs), including the assessment for fire and flooding impacts. Of the 97 scaffolds, the licensee identified four scaffolds that were in direct contact with plant equipment. The team noted that Step 7.5.6.A. of CMP 100.009, stated in part, that for scaffolds that have to be constructed where contact with plant equipment is required; an engineering evaluation shall be performed prior to building. The team determined that these four scaffolds did not have prior engineering evaluations performed. The licensee documented these issues in condition reports (CR) CR-14-05692, CR-14-05694, CR-14-05695, and CR-14-05696.

The four scaffolds were moved and were no longer in contact with equipment. In addition, the licensee identified one scaffold where National Fire Protection Association (NFPA) 13 (1975) Section 4-2.13 standards was not evaluated when originally built; specifically, that multiple scaffolds with a width greater than 5.5 feet and separated by less than 6 feet would be considered contiguous in regards to the 100 square feet criteria for sprinkler head coverage. At the time of discovery, the area had an NFPA 805 roving fire watch being performed and no additional compensatory action was required.

The licensee performed an immediate operability determination for the scaffolding CRs in CR-14-05446 and determined potentially affected equipment remained operable.

Under CR-14-05446, the licensee performed an apparent cause evaluation and identified that since 1994, the maintenance department had utilized REE-22714, Engineering Criteria for the Erection of Scaffolding in the Vicinity of Safety Related Equipment, which was documented in a 10CFR50.59 screening, but at the time, only considered seismic concerns. The licensee concluded that REE-22714 was adequate until 1999, when the NRC published the new 10CFR50.59 Rule. The licensee concluded that maintenance personnel believed that REE-22714 satisfied all of the 10CFR50.59 requirements for the scaffold program, which led to the failure to adhere to the CMP 100.009 requirements to conduct 10CFR50.59 reviews for scaffolding installed in the plant for greater than 90 days.

The team also identified four special orders that provided guidance to operations department outside normal routines and the license did not perform 10CFR50.59 screening/evaluations, as required by station procedures. Step 21.7.a. of operations administrative procedure, OAP-100.4, Communication, Rev. 2, stated in part, that special orders that provide guidance to operations outside normal routines require evaluation for 10CFR50.59 requirements.

Of the four special orders, the licensee determined that two special orders required evaluation for 10CFR50.59 requirements because both special orders provided operator guidance that was not currently in plant operational procedures. Specifically, the two special orders were (14-03), calorimetric program used to monitor operation at the licensed limit may be impacted non-conservatively; and (14-07), potential water hammer for service water booster pump due to slow valve stroke. The licensee generated CR-14-05650 to evaluate procedure OAP-100.4, and created two corrective actions to perform 10CFR50.59 screenings/evaluations for special orders 14-03 and 14-07.

Analysis:

The licensees failure to follow procedure requirements to perform 10CFR50.59 screenings/evaluations on scaffolding and special orders was a performance deficiency. The performance deficiency was determined to be more than minor because it affected the Design Control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the team identified multiple examples where the licensee failed to evaluate temporary changes to the facility in accordance with station procedures, which could affect the availability, reliability, and capability of systems that respond to events. The team used IMC 0609, Att. 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0612, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because it was not a design deficiency, did not represent the loss of a system safety function, and did not represent a loss of function of TS or Non-TS equipment. The team determined the finding was indicative of present licensee performance, and was associated with the cross-cutting aspect of Procedure Adherence, in the area of Human Performance, per IMC 0310, Components Within the Cross-Cutting Areas. Specifically, the licensee failed to screen temporary plant changes as required by procedures. [H.8].

Enforcement:

Technical specification 6.8.1 required, in part, that written procedures shall be established, implemented and maintained covering the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978.

Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation) stated, in part, that typical safety-related activities that should be covered by written procedures include: 1. d.) Procedure Adherence and Temporary Change Method. Contrary to the above, since July 2, 2014, the licensee failed to implement station procedures for temporary changes. Specifically, the licensee failed to implement procedures CMP-100.009, ES-0409, OAP-100.4, and SAP-0107, in that they did not perform 10CFR50.59 screenings/evaluations for 97 scaffolds supporting maintenance activities that existed in the plant for greater than 90 days at power and four special orders that provided guidance to operations outside normal routines. The licensee documented the issue in a comprehensive CR-14-05446, in which an apparent cause evaluation was performed to evaluate the finding and determine the appropriate final corrective actions. This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 5000395/2014007-01, Failure to Follow Procedures for Scaffolding and Special Orders for 10CFR50.59 Screenings/Evaluations)b.2 Failure to Follow Corrective Action Program Procedures

Introduction:

The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow station procedures governing the performance of operability/functionality evaluations for CRs that affected SSCs. Specifically, the licensee failed to properly screen, evaluate, and document operability or functionality determinations for six CRs that affected SSCs.

Description:

The team identified multiple examples where the licensee failed to implement procedures SAP-0999, Corrective Action Program, Rev. 12 and SAP-209, Operability Determination Process, Rev. 1. These procedures provided instruction for processing identified station events or issues in the licensees corrective action program.

Step 4.1.30 of SAP-0999, stated in part, that a degraded condition occurred when the qualification of an SSC or its functional capability was reduced. Step 4.1.49 of SAP-0999, stated in part, that a nonconforming condition was a condition of an SSC that involved a failure to meet the current licensing basis or a situation in which quality had been reduced because of factors such as improper design, testing, construction, or modification. Step 4.1.65 of SAP-0999, stated in part, that a CR was SSC related if it addressed any plant structure, system, or component regardless of safety class. In addition, Step 6.1.1 of SAP-209, stated in part, any degraded or nonconforming condition, as defined in SAP-0999, affecting an SSC shall be corrected in a timely manner, no later than the next available opportunity to facilitate corrective actions commensurate with the safety significance; and Step 6.1.2 stated, the operability or functionality determination shall be documented and attached to the CR.

The team identified six CRs where the licensee failed to correctly identify the issues as degraded or nonconforming conditions affecting a SSC, as defined in SAP-0999, Steps 4.1.30. and 4.1.49. Through multiple interviews with station personnel regarding the corrective action program, the team identified that the licensee did not consistently consider administrative issues, coded Administrative Assets, as conditions that could affect SSCs. As a result, the licensee did not properly screen and evaluate SSC related CRs for operability or functionality determinations in accordance with station procedures.

The six examples were CR-14-05446, CR-14-05650, CR-14-05473, CR-14-05474, CR-14-01886, and CR-14-04040, which included scaffolding, special orders, time critical actions, and a configuration control event. The team reviewed the six CRs and concluded that in each case, the issue was a degraded or nonconforming condition affecting an SSC, which procedurally required an operability/functionality evaluation.

The licensee had documented the issue in the corrective action program but considered the CRs to be administrative issues and not issues that directly affected a SSC. As a result, the licensee failed to completely and accurately identify the issues, and subsequently failed to evaluate SSC related CRs for operability or functionality determinations, which included immediate, prompt, and/or past operability determinations. The licensee subsequently evaluated the six CRs, determined there were no impacts on the operability of the affected SSCs, and updated the CRs to include operability determinations.

Analysis:

The licensees failure to follow station procedures governing the performance of operability/functionality evaluations for CRs that affected SSCs was a performance deficiency. The performance deficiency was determined to be more than minor, because if left uncorrected, it had the potential to lead to a more significant safety concern.

Specifically, the licensee failed to perform operability/functionality reviews for CRs with administrative issues of concern that affected SSCs and that could result in safety-related SSCs being inoperable and remain undetected for a period of time. The team used IMC 0609, Att. 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because it was not a design deficiency, did not represent the loss of a system safety function, and did not represent a loss of function of TS or Non-TS equipment. The team determined the finding was indicative of present licensee performance and was associated with the cross-cutting aspect of Identification, in the area of Problem Identification and Resolution, per IMC 0310, Components Within the Cross-Cutting Areas. Specifically, the licensee did not identify issues completely, accurately, and in a timely manner in accordance with the program. [PI.1]

Enforcement:

Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, required, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, since October 9, 2014, the licensee failed to ensure that activities affecting quality were accomplished in accordance with procedures. Specifically, the team identified multiple examples where the licensee failed to perform operability/functionality evaluations for CRs that affected SSCs in accordance with station procedures, SAP-0999 and SAP-209. This violation is being treated as an NCV consistent with section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as CR-14-05700 and CR-14-05676. (NCV 5000395/2014007-02, Failure to Follow Corrective Action Program Procedures)b.3 Instrument Uncertainties Result in Non-Conservative Values In EOP-2.2 & ARP-001-XCP-612; Refueling Water Storage Tank Swapover

Introduction:

The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to consider instrument uncertainties when determining refueling water storage tank (RWST) setpoints and associated time critical operator actions in procedures to perform RWST swapover. Specifically, the licensee failed to consider instrument uncertainties associated with the control room annunciator RWST Empty alarm at 6% with respect to the critical vortex level and second, the RWST indicated level of 10% at which pumps would be secured in emergency operating procedures (EOPs).

Description:

During a postulated design basis loss of coolant accident (LOCA), reactor cooling water would be spilled onto the reactor building floor. The water loss in the reactor would be replaced by emergency core cooling system (ECCS) pumps, which would be initially taking suction from the RWST. When the RWST indicated level reached 18%, a control room annunciator would be received; 'RWST Lvl Lo-Lo Xfer To Sump.' The alarm response procedure, ARP-001-XCP-612, Annunciator Point 4-3, Rev.

6, directed operators to perform time critical actions required for EOP-2.2, ES-1.3, Transfer to Cold Leg Recirculation. At RWST indicated level of 6%, control room annunciator RWST Empty, would be received and ARP-001-XCP-612, Annunciator Point 2-3, Rev. 6, directed operators to secure any pumps taking suction from the RWST to prevent pump damage.

In 2004, under engineer change request (ECR) 50316, the licensee performed a modification that allowed for the automatic transfer of residual heat removal pump and reactor building spray pump suctions from the RWST to the recirculation sumps. Prior to the ECR, the plant design required significant operator action to swap from injection to recirculation after a LOCA. After the installation of the modification, the required operator action was to verify the automatic transfer occurred and then manually realign the charging pumps per EOP-2.2.

The team reviewed calculations, design basis documents, and procedures and determined the licensee failed to consider instrument uncertainties associated with the

'RWST Empty' alarm at 6% with respect to the critical vortex level. Specifically, calculation, DC09620-012, RWST Level Instruments (ILT00990, ILI00990A, ILT00991, ILT00992, ILT00993) Uncertainties, Rev.1, documented that the instrument uncertainties associated with RWST Empty alarm level of 6% would result in an actual level as low as 3.14%. In addition, calculation TR04620-001, Hydraulic Model Study of RWST for Vortex Evaluation, Rev. 0, documented that vortexing occurred between 5%

and 3% RWST actual level, depending on flow rate. Chapter 6.3.2.6, Coolant Quality, of the UFSAR, stated in part, that at maximum RWST outflow of 14,575 gallons per minute, the critical vortex level was 5% RWST. As a result, the team determined that the RWST Empty setpoint of 6% indicated RWST level combined with instrument uncertainties did not properly account for the design basis requirement in UFSAR 6.3.2.6, Coolant Quantity, and as a result, air entrainment could be potentially occurring in the RWST suction line resulting in pump damage prior to the alarm being received.

Additionally, as a result of the teams questioning, the licensee noted that the setpoint for 10% indicated RWST level, at which operators were directed by the EOPs to secure pumps taking suction from the RWST, was non-conservative. The team noted that in July 2006, calculation CN-PO-04-35, V.C. Summer EOP Setpoint Upgrade Project, Rev. 0, documented that due to instrument uncertainty with the RWST Empty alarm setpoint of 6% in relation to where vortexing could occur, Westinghouse Owners Group recommended U.03, RWST Empty setpoint, should be changed to 10%. The licensee kept the U.03, RWST Empty setpoint at the original 6% but added a caution statement in EOP-2.2, Rev. 16, which stated in part, if RWST level decreased to 10%, any pumps taking suction from the RWST should be stopped to prevent pump damage. This was documented in the licensees EOP Step Deviation Form for EOP-2.2, Rev. 16. The team also noted that Step 6.4.c.8) of procedure, OAP-103.5, EOP/AOP Writers Guide, Rev.0, stated in part, that the passive verb should denoted a mandatory requirement, though it may be conditional.

Calculation, DC000040-077, Design Basis Timelines for Completing Transition from Injection to Re-circulation Phase During a LOCA, Rev. 4, Status A, was used to develop the design basis timelines for actions that must be completed in order to successfully transition from injection to cold leg recirculation during a LOCA. The calculation was revised in 2007 to include a single failure of a solid state protection system (SSPS) logic train that would result in a single train of residual heat removal and reactor building spray pump containment sump isolation valves not opening on demand. The team reviewed the calculation and noted that the most limiting case for time that operators had to complete time critical actions was 11.6 minutes, which was for a LOCA with a single train of SSPS failure. However, due to instrument uncertainties with the annunciator at RWST indicated level of 18%, which was when the automatic transfer would start; combined with the instrument uncertainties with the control room RWST level indicators which operators used to verify 10% level and then manually secured the pumps; the team determined that the available time was approximately 2.5 minutes for operators to perform RWST swapover for a large break LOCA combined with an assumed SSPS single failure. Performance Criteria for Emergency Core Cooling System, contained in UFSAR 15.4.1.1, described the continued operation of the ECCS pumps that supply water during long-term cooling. Because of the reduced available time, the operators could potentially secure all ECCS pumps taking suction from the RWST prior to the completion of the swapover actions; lose continued operation of ECCS pumps to supply long-term cooling; and therefore not meet the design basis performance criteria for ECCS. The team noted that the EOP-2.2 caution step at 10% level to stop any pump taking suction from the RWST did not properly account for the design basis requirement in UFSAR 15.4.1.1. The team also reviewed simulator timed validation for the same operator actions that would be performed in the RWST swapover and determined that the licensee was able to perform the key operator actions within 2.5 minutes.

The licensee entered this issue into their corrective action program as CR-14-05792 and CR-14-05869. The licensee performed an immediate and prompt determinations of operability in which they concluded that the safety injection system was operable but degraded. The licensee revised EOP-2.2, Rev. 17, which removed the requirement to secure ECCS pumps at 10%. The licensee changed the caution note to alert operators to start monitoring for a loss of pump suction at 10% RWST level and secure any affected pump to prevent pump damage. In addition, corrective actions were developed to update the RWST Empty alarm setpoint. The licensee also generated CR-14-05868 to address the inadequate change management when Rev. 16 was performed but the design basis calculations and timelines were not evaluated for impact.

Analysis:

The licensees failure to consider instrument uncertainties when determining RWST setpoints and associated time critical operator actions in procedures to perform RWST swapover was a performance deficiency. This performance deficiency was considered more than minor because it affected the Design Control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to consider uncertainties associated with the level alarms and level indicators for the RWST, and as a result, impacted the availability, reliability, and capability of the ECCS to respond to initiating events. The team used IMC 0609, Att. 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0612, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because it was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its operability or functionality.

The team determined that no cross-cutting aspect was applicable because the finding was not indicative of present licensee performance.

Enforcement:

Title 10 CFR 50, Appendix B, Criterion III, Design Control, required in part, that measures shall be established to assure that the design bases are correctly translated into procedures. Contrary to the above, since May 24, 2011, the licensee failed to assure that the design bases were correctly translated into procedures.

Specifically, the licensee failed to consider instrument uncertainties when determining setpoints and associated time critical operator actions, and as a result, did not assure that the UFSAR design basis was correctly translated into procedures, EOP-2.2 and ARP-001-XCP-612. This violation is being treated as an NCV consistent with section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as CR-14-05869 and CR-14-05792. (NCV 5000395/2014007-03, Instrument Uncertainties Result in Non-Conservative Values In EOP-2.2 & ARP-001-XCP-612; RWST Swapover)b.4 Failure to Account for Containment Temperature Measurement Uncertainty

Introduction:

The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to account for instrument uncertainty on the containment bulk average temperature instrumentation used in calculation DC00020-005, Steam Generator Replacement Reactor Building Temperature/Pressure - LOCA, Rev. 6, Status A. Specifically, the licensee

(1) failed to consider instrument uncertainty when verifying compliance with TS containment operability and design basis accident analysis; and
(2) failed to consider instrument drift for reactor building resistance temperatures devices (RTDs) when calibration was not performed for 21 years.
Description:

The team identified two examples where the licensee failed to account for instrument uncertainty for the containment bulk temperature instrumentation, which was used in calculation DC00020-005. This safety-related calculation documented that 120ºF was the maximum allowed containment average temperature to ensure design basis assumptions in UFSAR Table 6.2-2, Initial conditions Used in Reactor Building Peak Pressure Analysis and TS 3.6.1.5, Primary containment average temperature shall not exceed 120ºF, for containment operability.

  • Example 1 - Failure to Consider Instrument Uncertainty When Verifying Compliance with TS Containment Operability and Design Basis Accident Analysis In UFSAR Table 6.2-2, and calculations DC00020-005; DC00110-140, Equipment Qualification Zone Data, Rev. 8; and DC07010-004, R.B. Cooling Unit Cooling Load, Rev. 5, the initial reactor building temperature assumed in accident analysis was a maximum of 120ºF. The team noted that the maximum reactor building average temperature as specified in TS 3.6.1.5, Air Temperature, was also 120ºF, and as a result, there was no margin available between the design basis accident calculations that used 120ºF and the TS temperature limitation.

To verify compliance with TS, the licensee performed TS surveillance 4.6.1.5., using nine RTDs, ITE07307H/I/M/O/Q/S/T/V/W, located on three elevations of containment. These nine RTDs were utilized through averaging to demonstrate that the bulk reactor building average temperature did not exceed the TS limit of 120ºF.

The nine temperature signals were grouped together arithmetically to yield computer point ID PI001481 in OAP-106.1, Operating Rounds, Rev. 16e. Point PI001481 also had a computer alarm [U7307], which was used by the operations department to monitor the containment temperature. The alarm point [U7307] had a HI alarm setpoint of 118ºF and procedure OAP-106.1 directed the operators to notify the control room if the reading was greater than 118ºF alarm. Point [U7307] also had a HIHI alarm setpoint at the TS limit of 120ºF, at which the operations department would enter TS 3.6.1.5. action statement, which stated With the containment average air temperature greater than 120ºF, reduce the average air temperature to within the limit within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 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 cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

The team noted that calculation DC09640-033, Reactor Building Temperature Element, (ITE073707H/I/M/O/Q/S/T/V/W) Loop Uncertainties, Rev. 0, dated February 3, 2000, documented that indicated containment bulk average temperature had an instrument uncertainty of +/-1.18ºF. Although the licensee had considered the instrument uncertainty by creating a HI alarm at 118ºF, the team determined that the licensee did not consider the instrument uncertainty associated with the TS action statement entry condition of 120ºF. As a result, with an indicated temperature of 120ºF, the actual temperature could be as high as 121.18ºF, thereby exceeding the TS limit and potentially exceeding assumptions in the design basis accident analysis.

The licensee generated CR-14-05888, which documented that the guidance in OAP-106.1 for the operations department to respond to high containment temperature was insufficient to ensure the appropriate operator response was taken to prevent entering TS 3.6.1.5. limiting condition of operability. The licensee also revised OAP-106.1, Rev. 16h, which incorporated the temperature uncertainty values derived in the operability determination in CR-14-05864.

  • Example 2 - Failure to Consider Instrument Drift for RB RTDs When Calibration Was Not Performed for 21 Years Procedure ICP-240.055, RTD Calibration Generic Procedure, Rev. 4, was performed to ensure that the calibration of specific RTDs was maintained within specified tolerances. This procedure had previously been completed for the nine RTDs, ITE07307H/I/M/O/Q/S/T/V/W, however, the team identified that the reactor building RTDs had not been tested since 1993.

The team noted that the RTDs were originally checked for resistance-temperature conformance to the vendor-supplied calibrations, using procedure ICP-240.055, on a frequency of every other refueling outage (36-month interval). The team identified that in 1996, the periodicity changed to on demand when the licensee incorrectly concluded that theses RTDs were only needed to support an infrequently performed integrated leak rate test. However, this change in frequency did not account for the RTDs still being used to monitor TS 3.6.1.5. limits or to verify the design basis assumption of an initial reactor building temperature condition of 120ºF.

Calculation DC09640-033 documented that the uncertainty in measurement of the reactor building temperature was +/- 1.18ºF. Inherent in this calculation was the assumption that vendor specification of drift was +/- 0.05 ohm/year and judged negligible when compared to other uncertainties. However, since the reactor building RTDs had not been calibrated in 21 years, the licensee determined that the RTDs could have potentially experienced a temperature drift uncertainty of +/-5.31ºF.

Factoring the other uncertainties, the total associated instrument uncertainty was determined to be as high as +8.82ºF. As a result, with an indicated temperature of 120ºF, the actual temperature could be as high as 128.82 ºF, thereby exceeding the TS limit and potentially exceeding the assumptions in the design basis accident analysis.

The licensee generated CR-14-05864 to document the failure to perform calibration testing of the RTDs for 21 years. The licensee performed an operability determination in CR-14-05864 and concluded that the temperature monitoring system was operable with interim actions. The licensee also generated CR-14-05897, which documented the change in RTD testing periodicity. The licensee revised OAP-106.1, which incorporated the temperature uncertainty values derived in the operability determination in CR-14-05864. The licensee also created work order 1416624, to perform RTDs calibration during the next available plant outage.

Analysis:

The licensees failure to account for instrument uncertainty on the containment bulk average temperature instrumentation used in calculation DC00020-005 was a performance deficiency. The performance deficiency was more than minor because it was associated with the Configuration Control attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to ensure that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, by not accounting for the instrument uncertainty on the containment bulk average temperature instrumentation, the containment temperature could unknowingly exceed the design basis and TS operability limit. The team used IMC 0609, Att. 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because it did not result in an open pathway in containment and did not involve hydrogen igniters. The team determined that no cross-cutting aspect was applicable because the finding was not indicative of present licensee performance.

Enforcement:

Title 10 CFR 50, Appendix B, Criterion III, Design Control, required, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, since February 3, 2000, the licensee failed to correctly translate the applicable regulatory requirements and the design basis into instructions, and failed to check the adequacy of design. Specifically, the licensee did not have adequate controls in place to ensure that the bulk average containment temperature used in calculation DC00020-005, would not exceed the design basis limit and TS limit of 120°F. The licensee

(1) failed to consider instrument uncertainty when verifying compliance with TS containment operability and design basis accident analysis; and
(2) failed to consider instrument drift for reactor building RTDs because calibration was not performed for 21 years. This violation is being treated as an NCV consistent with section 2.3.2 of the Enforcement Policy. The licensee entered the issues into their corrective action program as CR-14-06864, CR-14-05888, and CR-14-05897. (NCV 5000395/2014007-04, Failure to Account for Containment Temperature Measurement Uncertainty)

.3 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues for applicability at the Virgil C.

Summer Nuclear Station, Unit 1. The team performed an independent review of these issues and, where applicable, assessed the licensees evaluation and dispositioning of each item. The issues that received a detailed review by the team included:

  • NRC IN 2003-19, Unanalyzed Condition Of Reactor Coolant Pump Seal Leakoff Line During Postulated Fire Scenarios Or Station Blackout (Refer to Westinghouse Technical Bulletin, NSD-TB-91-07-R1, "Over pressurization of RCP #1 Seal Leakoff Line)
  • NRC IN 2012-06, Ineffective Use of Vendor Technical Recommendations
  • NRC IN 97-90, Use of Nonconservative Acceptance Criteria in Safety-Related Pump Surveillance Tests

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On November 7, 2014, the team presented the inspection results to Mr. T. Gatlin and other members of the licensees staff. Additional inspection results were discussed with Mr. B. Thompson and other members of the licensees staff on November 24, 2014. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Barth, Plant Support Engineering, Engineer II
R. Beckham, Operations Supervisor, Control Room
A. Bencoe, - Probabilistic Risk Assessment, Assistant Engineer
S. Bender, Plant Support Engineering, Engineer III
L. Cartin, Design Engineering, Principal Engineer
N. Childs, Plant Support Engineering, Engineer II
B. Dalick, Nuclear Licensing
K. Dalick, Plant Support Engineering
M. Eads, Mechanical Maintenance
D. Edwards, Operations, Supervisor of Operations Support
T. Fanguy, Design Engineering, Engineer Sr.
W. Fargo, Plant Support Engineering, Engineer Sr.
D. Fulmer, Planning and Scheduling Supervisor
J. Garza, Nuclear Licensing, Supervisor
R. Haggard, Plant Support Engineering
C. Himel, Plant Support Engineering, Engineer IV
M. Johnson, Operations Supervisor, Control Room
R. Justice, Operations Manager
L. Kachnik, Probabilistic Risk Assessment
T. Keckeisen, Operations, Fire Protection
K. Leonelli, Design Engineering, Engineer Sr.
C. Rice, Design Engineering, Engineer Sr.
R. Rose, Plant Support Engineering, Engineering Specialist III
Z. Sharpe, Plant Support Engineering, Engineer II
F. Shealy, Mechanical Maintenance, Supervisor
D. Shue, Maintenance, Manager
B. Sumner, Plant Support Engineer, Engineer III
W. Taylor, Nuclear Licensing
R. Todd, Operations Supervisor, Control Room
B. Thompson, Nuclear Licensing, Manager
J. Wagner, Design Engineering, Engineer Sr.
B. Waldrop, Plant Support Engineering, Engineer Sr.
J. Ward, Design Engineering, Engineer Sr.
G. Williams, Plant Support Engineering, Supervisor
K. Wise, Design Engineering, Engineer III
W. Wood, Plant Support Engineer, Engineer III
N. Young, Plant Support Engineer, Engineer IV

NRC personnel

E. Coffman, Resident Inspector, Division of Reactor Projects
M. King, Chief, Projects Branch 5, Division of Reactor Projects
G. MacDonald, Senior Reactor Analyst, Division of Reactor Projects
J. Reece, Senior Resident Inspector, Division of Reactor Projects

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened and Closed

05000395/2014007-01 NCV Failure to Follow Procedures for Scaffolding and Special Orders for 10CFR50.59 Screenings/Evaluations [Section 1R21.2]
05000395/2014007-02 NCV Failure to Follow Failure to Follow Corrective Action Program Procedures [Section 1R21.2]

Instrument Uncertainties Result in Non-

05000395/2014007-03 NCV Conservative Values In EOP-2.2 & ARP-001-

XCP-612; RWST Swapover [Section 1R21.2]

Failure to Account for Containment Temperature Measurement Uncertainty

05000395/2014007-04 NCV [Section 1R21.2]

LIST OF DOCUMENTS REVIEWED

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