IR 05000456/2016007

NRC Problem Identification and Resolution Inspection Report 05000456/2016007; 05000457/2016007

ML16267A152
Person / Time
Site:	Braidwood
Issue date:	09/23/2016
From:	Eric Duncan Region 3 Branch 3
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
References
IR 2016007
Download: ML16267A152 (28)

Text

UNITED STATES ber 23, 2016

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2 - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000456/2016007; 05000457/2016007

Dear Mr. Hanson:

On August 11, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution (PI&R) Biennial Inspection at your Braidwood Station, Units 1 and 2. The NRC inspection team discussed the results of this inspection with Ms. M. Marchionda and other members of your staff. The inspection team documented the results of this inspection in the enclosed inspection report.

Based on the inspection samples selected for review, the inspection team determined that the Braidwood staffs implementation of the corrective action program (CAP) supported nuclear safety. In reviewing the CAP, the team assessed how well the staff identified problems at a low threshold, how well the stations process for prioritizing and evaluating these problems was implemented, and the effectiveness of corrective actions taken by the staff to resolve these problems. In each of these areas, the team determined that the stations performance was adequate to support nuclear safety.

The team also evaluated other processes used to identify issues for resolution. These included the use of audits and self-assessments to identify latent problems and incorporation of lessons learned from industry operating experience into station programs, processes, and procedures.

The team determined that the stations performance in each of these areas supported nuclear safety.

The team determined that the stations management maintained a safety conscious work environment adequate to support nuclear safety. Based on the teams interviews and observations, employees were willing to raise concerns related to nuclear safety through at least one of the several means available.

Based on the results of this inspection, the NRC identified one issue that was evaluated under the significance determination process as having very low safety significance (Green). The NRC also determined that the issue had an associated violation. Because this finding was of very low safety significance and was entered into the CAP to address the issue, this violation is being treated as a Non-Cited Violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. This NCV is described in the subject inspection report. If you contest the violation or significance of the NCV, 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: (1) the Regional Administrator, Region III; (2) the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector at Braidwood Station.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records System (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456 and 50-457 License Nos. NPF-72 and NPF-77

Enclosure:

IR 05000456/2016007; 05000457/2016007

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2016007; 05000457/2016007 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: Braceville, IL Dates: July 11 through August 11, 2016 Inspectors: D. Betancourt, Resident Inspector, Team Leader M. Holmberg, Senior Reactor Inspector J. Bozga, Reactor Inspector G. ODwyer, Reactor Inspector Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000456/2016007; 05000457/2016007; 07/11/2016 - 08/11/2016;

Braidwood Station, Units 1 and 2; Biennial Problem Identification and Resolution Inspection Report.

This team inspection was performed by three U.S. Nuclear Regulatory Commission (NRC)regional inspectors and the Braidwood resident inspector. One Green finding was identified by the team. This finding was considered a non-cited violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6, dated July 2016.

Problem Identification and Resolution On the basis of the samples selected for review, the team determined that implementation of the corrective action program (CAP) at Braidwood Station, Units 1 and 2, was generally good. The licensee demonstrated a low threshold for identifying problems and entering them into the CAP.

Items entered into the CAP were screened and prioritized in a timely manner using established criteria; were properly evaluated commensurate with their safety significance; and corrective actions were generally implemented in a timely manner, commensurate with the safety significance of the issue. The use of operating experience was integrated into daily activities.

Audits and self-assessments were performed at appropriate frequencies and at an appropriate level to identify issues. On the basis of the interviews conducted during the inspection, workers at the site expressed a willingness to raise safety concerns without the fear of retaliation. The team did not identify any impediment to the establishment of a safety conscious work environment at Braidwood Station. On the basis of the interviews conducted, workers at the site expressed a willingness to enter safety concerns directly into the CAP or make safety concerns known through their supervisors. Some non-supervisory personnel questioned the value of identifying concerns for what they perceived as low level issues.

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and an associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was self-revealed when the licensee failed to prescribe essential service water (SX) system operating and/or surveillance procedures appropriate to the circumstances. Specifically, the licensee failed to provide SX operating procedure guidance to limit the closure position of valves 1SX007, 2SX007 and 0SX007, such that cavitation-induced damage/failure of components did not occur or to establish a procedure to monitor and correct cavitation-induced damage prior to component failure associated with the operation of these valves. Consequently, a through-wall leak occurred downstream of valve 1SX007 that was caused by cavitation-induced wall loss at the neck of the pipe flange supporting this valve. The licensee replaced the damaged valve and piping and entered this issue into their CAP as Issue Report (IR) 02697962.

The team determined that the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, continued operation of the SX007 valves without monitoring or correcting cavitation-induced damage could result in a more significant failure resulting in the loss of an SX train and/or an internal flooding event. The team determined that this finding was of very low safety significance because although it was determined to be a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC), the operability or functionality of the component was not affected. The team did not identify a cross-cutting aspect for this finding because the finding did not reflect current licensee performance. (Section 4OA2.1(3))

REPORT DETAILS

4OA2 Problem Identification and Resolution

The activities documented in Sections

.1 through .4 constituted one biennial sample of

problem identification and resolution as defined in Inspection Procedure (IP) 71152.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The team reviewed the licensees corrective action implementing procedures and attended corrective action program (CAP) meetings to assess the implementation of the CAP by site personnel.

The team reviewed risk and safety significant issues in the licensees CAP since the last NRC PI&R inspection, completed in August 2014. The issues selected were represented in all of the NRCs Reactor Oversight Process (ROP) cornerstones. The team reviewed a sample of issues identified through NRC generic communications, department self-assessments, licensee audits, operating experience reports, and NRC documented findings. Additionally, the team reviewed issue reports (IRs) generated as a result of daily plant activities. The team also reviewed a sample of work orders (WOs),performance indicator reports, system health reports, and completed causal evaluations from the licensees various methods, which included root cause evaluations (RCEs) and apparent cause evaluations (ACEs).

A five year review related to leaks in the essential service water (SX) system was also performed to assess the licensees efforts in monitoring for system degradation due to aging. The team also performed a partial system walkdown of the SX system, auxiliary feedwater system, and equipment contained in the lake screenhouse to determine whether the condition of the equipment was appropriately represented in plant health reports, WOs, and the CAP.

During these reviews, the team evaluated whether the licensees actions were in compliance with the facilitys CAP and Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B requirements. Specifically, the team assessed whether licensee personnel were identifying station issues at the proper threshold, whether identified issues were being entered into the CAP in a timely manner with the appropriate significance characterization, and whether identified issues were appropriately prioritized for resolution. The team also assessed whether the licensee assigned the appropriate evaluation method to ensure the proper determination of root, apparent, and contributing causes. Finally, the team evaluated the timeliness and effectiveness of corrective actions (CAs) for selected IRs, completed causal evaluations, and previously identified NRC findings and NCVs.

Documents reviewed are listed in the Attachment.

b. Assessment

(1) Effectiveness of Problem Identification Based on the results of the inspection, the team concluded that problem identification was generally effective. Based on the information reviewed, including initiation rates of IRs and information from interviews, the team determined that the licensee had an appropriate and low threshold for initiating IRs and that all station departments were active in generating IRs. The team also determined that the station was generally effective at trending low level issues to prevent larger issues from developing. The team assessed the effectiveness of problem identification as adequate to support nuclear safety.

Findings No findings were identified.

(2) Effectiveness of Prioritization and Evaluation of Issues Based on the results of the inspection, the team concluded that the prioritization and evaluation of issues was generally appropriate. The team determined that station ownership committee (SOC) and management review committee (MRC) meetings were generally thorough and meeting participants were actively engaged and well-prepared.

The results of SOC and MRC meetings were also determined to accurately prioritize issues. Higher level evaluations, such as RCEs and ACEs, were generally technically accurate; of sufficient depth to effectively identify the cause(s); and generally considered extent of condition, generic implications, and previous occurrences in an adequate manner. However, the team found one example for which a contributing cause in a RCE did not include an assigned corrective action (CA). The licensee entered this issue in their CAP as IR 02696896, No Corrective Action Tracking Item (ATI) for Root Cause Identified for Contributing Cause, and provided a justification as to why a CA was not needed to address the contributing cause. The team reviewed the IR and associated justification and determined the actions were appropriate.

Unresolved Item (URI): Identification of Significant Conditions Adverse to Quality in Accordance with the Quality Assurance Topical Report

Introduction:

The team identified an Unresolved Item (URI) regarding the identification of significant conditions adverse to quality (SCAQs) in the CAP. Specifically, the team determined that the CAP, as implemented by PI-AA-125,Corrective Action Program, and PI-AA-120, Issue Identification and Resolution, appeared to not ensure that SCAQs were appropriately identified and corrected to prevent recurrence.

Description:

Chapter 16 of the Braidwood Quality Assurance Topical Report (QATR)describes the licensees program to identify and correct conditions adverse to quality.

Procedure PI-AA-125 implemented the requirements established in the QATR. During this inspection, the team reviewed the CAP procedure to determine how it ensured that SCAQs were identified and resolved. As part of this review, the team requested a copy of identified SCAQs over the last two years and were subsequently informed that none had been identified.

Issue #1 The team reviewed the QATR and noted that the following requirements applied:

• Section 2.1 stated that measures are required to assure that the cause of any significant condition adverse to quality is determined and that corrective actions to prevent recurrence [CAPRs] are implemented.

• Section 2.2.1, Significant Conditions Adverse to Quality, stated that in cases of significant conditions adverse to quality the cause of the condition must be determined and documented, the resolution determined and documented, and the corrective actions taken and documented to prevent recurrence.

• Step 2.116 of Appendix D of the QATR defined a significant condition adverse to quality as, a condition, which if left uncorrected, could have a serious effect on safety or operability.

The team reviewed procedure PI-AA-125 and PI-AA-120, which delineated the process for the identification and screening of issues, and identified that these procedures did not include a provision to classify an identified issue as a SCAQ. The team also noted that the definition of a SCAQ was not being used to determine whether a RCE was needed; therefore, a CAPR did not appear to be directly associated with a SCAQ.

Based on the above, the team questioned whether CAP procedure PI-AA-125 prescribed a process through which SCAQs were identified and documented, and corrective actions taken and documented to prevent recurrence as required by the QATR. The team discussed this issue with the licensee. The licensee stated that since the terms SCAQ and condition adverse to quality (CAQ) were not explicitly defined in NRC regulations, that they had created a graded approach of significance level and likelihood (which included risk and uncertainty) to ensure that items were properly dispositioned and the level of resources and rigor applied appropriately followed the CAP governance. The licensee further stated that the graded approach, along with a well-trained management team that has nuclear safety and conservative decision-making as their primary focus, provided for an effective CAP. Finally, the licensee stated that even if a CAPR was not issued, that CAs would prevent recurrence of the events entered into the CAP.

The team questioned whether a CAPR and a CA would be equally effective as corrective actions to prevent the recurrence of issues dispositioned in the CAP. The licensee agreed that the two types of CAs were treated differently. For example, 1) the MRC was required to assess changes to the intent of a CAPR, which was not required for a CA, 2) an effectiveness review may not necessarily be assigned if an issue was corrected using only a CA, and 3) if there was a desire to suspend or modify a previously implemented CAPR, then a risk analysis and MRC concurrence was necessary; which was not the case for a CA.

At the end of the inspection it was not clear how procedures PI-AA-120 and PI-AA-125 ensured that SCAQs were identified and documented, and corrective actions taken and documented to prevent recurrence. Additionally, it was not clear if the licensees process implemented the requirements in the QATR.

Resolution of this issue will be based on additional NRC review to determine if a violation of NRC requirements occurred.

Issue #2 The team identified an example of a potential SCAQ for which the licensee implemented CAs that failed to prevent the issue from recurring. Specifically, for a December 30, 2013 oil leak on the inboard bearing housing of the Unit 1 Train B (1B) SX pump, the licensees CAs restored operability, but were not adequate to prevent recurrence and consequently an oil leak recurred on November 18, 2014. Both of these oil leaks resulted in the licensee declaring the 1B SX pump inoperable and required entry into Technical Specification (TS) Limited Condition for Operation (LCO) 3.7.8 (reference Non-Cited Violation (NCV)05000456/2014005-02; Failure to Correct Undersized Essential Service Water Pump Bearing Casing Drain Line Resulted in System Inoperability).

The team questioned whether the oil leaks on the inboard pump bearing housing of the 1B SX pump should have been categorized as a SCAQ as defined in the licensees QATR. Specifically, QATR Section 2.116, Definitions, defined a SCAQ as, A condition, which if left uncorrected, could have a serious effect on safety or operability.

In this case, although the oil leakage at the inboard pump bearing housing first identified in 2013 was specifically addressed through repairs, the CAs were not adequate to prevent recurrence and a second oil leak occurred in 2014 that caused a serious effect on the operability of the 1B SX pump (i.e. rendered the 1B SX pump inoperable).

Additionally, the team considered this issue to have a potentially serious effect on operability, because if left uncorrected the oil leakage would have depleted the oil supply reservoir resulting in a loss of lubrication to the pump shaft bearings that could damage the pump shaft and require substantial repairs to return the pump to operation.

The team discussed this issue with the licensee. The licensees response was that because there was no potential for common cause failure, and there was no significant change to plant risk after removing the 1B SX pump from service, the events discussed above were appropriately screened as Significance Level 3 issues. The licensee also stated that a SCAQ would typically be assigned for a Significance Level 1 or 2 issue, but even if an issue was assigned this level of significance, it would not necessarily be categorized as a SCAQ.

At the end of the inspection it was not clear how the definition of SCAQ in the QATR was utilized in the CAP. Resolution of this issue will be based upon additional NRC review and a determination of whether the failure of the 1B SX pump constituted a SCAQ as defined in the QATR. (URI 05000456/2016007-01; 05000457/2016007-01, Identification of SCAQs in Accordance with the QATR)

(3) Effectiveness of Corrective Actions Based on the results of the inspection, the team concluded that the CAs appeared generally appropriate for the identified issues. The CAs associated with selected NRC documented findings and violations, as well as licensee-identified violations, were generally appropriate to correct the problem and were implemented in a timely manner.

Problems identified through RCEs or ACEs were generally resolved in accordance with CAP procedures.

Observations Five Year Review of Essential Service Water System Issues That May be Age-Related (IP 71152 Section 03.05.m)

The team performed a walkdown of accessible portions of the Unit 1 and Unit 2 SX system in the lake screenhouse (including the chemical addition system) and the accessible SX system piping in the auxiliary building, focusing on areas that had been subject to through-wall leakage and/or repair activities, to identify issues related to potential aging of structures, systems, and components (SSCs).

The exterior of SX system piping was found to be generally clean and painted with no visual evidence of through-wall leakage. There was also no oil leakage observed at any of the SX pump bearings.

Additionally, the team reviewed photographs of a component cooling water (CC) system heat exchanger (HX) and an emergency diesel generator jacket water cooler with the end-bells removed to assess aging degradation mechanisms that affected the internal condition of the SX piping supply at these locations.

From those photographs, it was visually discernible that the interior surface of these HXs and the SX supply piping were covered with a relatively uniform corrosion layer intermixed with irregular formations (tubercles). The team considered this condition typical and acceptable for an SX system in commercial service for over 30 years.

The team performed a review of CAP records, focusing on SX system performance over the past five years, to evaluate the CAs following leakage events. Specifically, the team focused on aging issues related to leakage events to ensure CAs were complete, accurate, and timely; considering extent of condition; were appropriately classified and prioritized; correctly identified root and contributing causes; were appropriately focused on actions that resulted in the correction of the identified problem; identified negative trends; adequately evaluated operating experience for applicability; and communicated applicable lessons learned to appropriate organizations.

In general, the licensee implemented effective CAs for the issues reviewed. However, an issue of concern was identified that indicated opportunities existed to improve CAP effectiveness. This example was associated with cavitation-induced degradation and leakage that occurred downstream of the 1SX007 valve in May of 2015.

Findings Operation of SX System Valves Results in Cavitation Damage and Pipe Leakage

Introduction:

A self-revealed finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to prescribe SX system operating and/or surveillance procedures appropriate to the circumstances. Specifically, the licensee failed to provide SX system operating procedure guidance to limit the position of valves 1SX007, 2SX007 and 0SX007 to preclude the cavitation-induced damage/failure of components or to establish a procedure to monitor and correct cavitation-induced damage prior to component failure associated with the operation of these valves.

Description:

During cold weather conditions, the overall flow requirements for the SX system is very low and, as a consequence, the licensee reduces SX system flow through the CC HXs by throttling closed SX system valves 1SX007, 2SX007 and 0SX007 at the outlet of the CC HX. The throttling of these butterfly-type valves has resulted in cavitation-induced damaged (e.g. wall loss and through-wall leakage) at the 2SX007 valve body and 1SX007 downstream piping flange in the past. The team was concerned that continued operation of the SX007 valves in this manner could result in a more significant event; including the loss of an SX system train and/or internal flooding.

Cavitation is the sudden vaporization and condensation of a liquid downstream of a valve due to localized low pressure zones. When flow passes through a throttled valve, a localized low pressure zone forms immediately downstream of the valve. If the localized pressure falls below the vapor pressure of the fluid, the liquid vaporizes (boils)and forms a vapor pocket. As the vapor bubbles flow downstream, the pressure recovers, and the bubbles violently implode causing localized stresses in the piping walls and valve body that can result in severe pitting of the surrounding material. For example, valve vendor guidance document, Flowserve Cavitation Control, stated, Cavitation damage destroys both piping and control valves, often resulting in catastrophic failure. It causes valves to leak by eroding seat surfaces. It can drill holes through pressure vessel walls. Even low levels of cavitation will cause cumulative damage, steadily eroding parts until the part is either repaired, or it fails. The team noted that many valve vendors provide guidance to properly size and select flow control valves to avoid operation that results in cavitation.

On April 22, 2003, the licensee replaced valve 1SX007 due to seat leakage using WO 00452527. During this valve replacement, the licensee documented the identification of major corrosion damage on the east side flange (downstream side of valve) in the closure section of the WO.

On April 15, 2008, the licensee identified that the as-found seating torque for motor-operated butterfly valve 2SX007 exceeded the acceptance criteria. The licensee removed the valve and identified portions of the carbon steel valve body that had eroded away as a result of cavitation-induced erosion (IR 00763398). Specifically, the licensee concluded that the flow of water around the valve disc during the months when the valve was nearly closed during cold weather conditions created a low pressure region resulting in the formation and collapse of bubbles (cavitation) and resultant damage.

On May 17, 2015, the licensee identified a 0.125 gallon per minute (gpm) leak from a through-wall hole downstream of valve 1SX007 at the neck of the 24-inch diameter pipe flange supporting this valve. The licensee replaced the pipe and sent the removed pipe section to a vendor for examination. The vendor identified a patch of localized internal thinning that measured 18 inches in circumferential extent and 2 inches in axial extent.

The vendor report stated, The sponge-like jagged appearance is typical of cavitation damage. The vendor did not attempt to determine the extent of material lost in the through-wall direction, but took a photograph of a cross-section through the damaged area. Based upon this photograph, which included an overlay, the team observed that the loss of material reached 0.75 inches in the 1.25 inch thick pipe-wall for this cross-section of flange/pipe wall.

The damage to the piping and valves in these examples was the result of operation with the SX007 valves in a significantly throttled position, which created cavitation conditions.

During cold weather conditions with colder supply water, the licensee reduced SX flow through the CC HX by throttling closed on the outlet valves. Specifically, Steps F.1.i and F.2.d of procedure BwOP CC-1, Component Cooling Water System Startup, directed operators to adjust the position of SX007 valves as required to maintain CC HX outlet temperature between 70-100 degrees Fahrenheit without restrictions. Although the licensee was aware of this problem, procedure BwOP CC-1 was not revised to limit closure (throttling) of these butterfly valves to prevent cavitation.

The team was concerned that without additional guidance, procedure BwOP CC-1 was inadequate because continued operation of these valves in this manner would result in cavitation-induced damage to the valves and downstream piping. The licensee entered this issue into their CAP as AR 02697962.

The licensee stated that the cavitation-induced damage associated with the SX007 valves was a long-standing issue and various options to address this concern had been considered. Specifically, the licensee considered revising the operating procedure to allow lower temperature SX operation and avoid throttling these valves to the point that cavitation occurred; however, this option was not selected.

Additionally, the licensee considered implementation of a design change to install a bypass valve to avoid throttling SX007 valves into the cavitation range, but again this option was not selected.

Instead, the licensee stated that they relied on the Raw Water Program to monitor cavitation damage. Specifically, in IR 02701110, the licensee stated that WO 00452527 closure comments should have been entered into the CAP and because of this error a formal evaluation of the observed condition and potential extent of condition were not completed as required by the Generic Letter 89-13 Program and Raw Water Program.

The licensee also identified 23 other SX system locations potentially susceptible to cavitation-induced damage and had actions planned to perform visual inspections or replacements of these components. However, as of August 9, 2016, the licensee had not updated the Raw Water Program to monitor these areas. Instead, the licensee was relying on engineering judgment to schedule visual inspections of the SX007 downstream piping and this inspection did not include the SX007 valve body areas subject to cavitation damage. Specifically, the licensee determined that it was not possible to perform ultrasonic examinations of the areas affected by cavitation on the SX007 valves or downstream flange/pipe and instead assigned an Action Tracking Item to perform internal visual inspections of the SX007 segments of pipe in February and September of 2017. Further, these visual inspections had been deferred from the original planned inspection interval of one year based upon engineering judgment. The team could not independently confirm that engineering judgment would support the increased inspection interval to ensure that additional SX component leakage or failures would not occur. The licensee entered this issue into their CAP as IR 02697529 and concluded that the SX piping segments subject to cavitation damage were operable because currently there was no leakage at these locations. The licensee also assigned a CA to develop an evaluation for the material condition of these piping segments.

Analysis:

The team determined that the licensees failure to prescribe SX system operating procedures appropriate to the circumstances and limit the position of valves 1SX007, 2SX007 and 0SX007 to avoid cavitation damage and/or implement a procedure to monitor and correct this damage prior to component failure was contrary to 10 CFR Part 50, Appendix B, Criterion V, and was a performance deficiency.

This finding was determined to be of more than minor because it was associated with Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, continued operation of the SX007 valves with an inadequate operating procedure could result in continued cavitation-induced damage resulting in a more significant failure such as the loss of an SX system train and/or an internal flooding event which would adversely affected the capability of the SX system to respond to initiating events to prevent undesirable consequences.

The team determined the finding could be evaluated using the Significance Determination Process in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, Exhibit 2 - Mitigating Events Screening Questions, dated June 19, 2012. The team answered Yes to Question A.1 of Exhibit 2 of Appendix A of IMC 609 because the finding was a deficiency affecting the design or qualification of a mitigating SSC, but the affected SSC maintained operability or functionality. Therefore, the team determined that this finding was of very low safety significance (Green). The team did not identify a cross-cutting aspect associated with this finding because the issue did not reflect current performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, 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, prior to May 17, 2015, the licensee failed to prescribe SX system operating and/or surveillance procedures appropriate to the circumstances for SX system operation, which was an activity affecting quality. Specifically, the licensee failed to provide SX system operating procedure guidance to limit the position of valves 1SX007, 2SX007 and 0SX007 such that cavitation-induced damage/failure of components did not occur and/or the licensee failed to establish a procedure to monitor and correct cavitation-induced damage prior to component failure associated with operation of these valves. Consequently, on May 17, 2015, a through-wall leak occurred downstream of valve 1SX007 that was caused by cavitation-induced wall loss at the neck of the pipe flange supporting this valve. Because this finding was of very low safety significance and was entered into the licensees CAP as IR 02697962, the associated violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2016007-02; NCV 05000457/2016007-02; Operation of SX System Valves Results in Cavitation Damage and Pipe Leakage)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The team reviewed the licensees implementation of their Operating Experience (OE)program. Specifically, the team reviewed OE program procedures; attended CAP meetings to observe the use of OE information, completed evaluations of OE-related issues and events; and selected monthly assessments of the OE composite performance indicators. The objective of this review was to determine whether the licensee was effectively integrating OE into the performance of daily activities, whether evaluations of issues were appropriate and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The team also assessed if corrective actions, as a result of OE, were identified and implemented in an effective and timely manner.

b. Assessment In general, OE was appropriately utilized at Braidwood Station. Industry OE was disseminated across the various plant departments. No issues were identified during the teams review of licensee OE evaluations. The team also verified that the use of OE in formal CAP products, such as RCEs and ACEs, was appropriate and adequate.

Generally, OE that was applicable to the station was thoroughly evaluated and actions were implemented in a timely manner to address any issues that resulted from the evaluations.

Findings No findings were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The team assessed the licensees ability to identify and enter issues into the CAP, prioritize and evaluate those issues, and implement effective corrective actions, resulting from departmental self-assessments and audits.

b. Assessment Based on the results of the inspection, the team did not identify any issues of concern regarding Braidwood Stations ability to conduct self-assessments and audits.

Assessments were conducted in accordance with plant procedures, were generally thorough and intrusive, adequately covered the subject area, and were effective at identifying issues and enhancement opportunities at an appropriate threshold. Identified issues were entered into the CAP with the appropriate significance characterization and corrective actions were completed and/or scheduled to be completed in a timely manner commensurate with their safety significance.

Findings No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The team assessed the licensees safety conscious work environment through a review of the facilitys Employee Concerns Program (ECP) implementing procedures, discussions with coordinators of the ECP, interviews with personnel from various departments, and a review of IRs. Additionally, the sites most recent safety culture assessment was reviewed.

b. Assessment Based on the results of the inspection, the team did not identify any issues that suggested conditions were not conducive to the establishment and existence of a safety conscious work environment at Braidwood Station. Information obtained during the interviews indicated that an environment was established where employees felt free to raise nuclear safety issues without fear of retaliation; were aware of and generally familiar with the CAP and other processes, including the ECP and the NRC, through which concerns could also be raised; and safety significant issues could be freely communicated to supervision.

Observations All interviewees indicated that they could, and would, bring up safety issues with supervision, management, or through the CAP. None of the interviewed personnel stated that there was intimidation or retaliation, or a perception of such, when they raised issues. Those same interviewees predominantly stated that although they would utilize the ECP, they saw no need to use that program for issue reporting. Several of those interviewed questioned the value of identifying concerns for what they perceived as low level issues. For nearly all departments interviewed, there was a desire for better communication and feedback on issues entered into the CAP which were not addressed or were deferred.

Findings No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On August 11, 2016, the team presented the inspection results to the Site Vice President, Ms. M. Marchionda, and other members of the licensees staff. The licensee acknowledged the issues presented. The team confirmed that none of the potential report input discussed was considered proprietary and that all material considered proprietary by the licensee was returned.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Marchionda, Site Vice President

A. Ferko, Plant Manager

J. Bashor, Engineering Director

P. Rausch, Operations Director

S. Reynolds, Regulatory Assurance Manager

H. Rosenboom, CAP Manager

R. Schliessmann, NRC Coordinator

U.S. Nuclear Regulatory Commission

E. Duncan, Chief, Reactor Projects Branch 3

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000456/2016007-01 URI Identification of SCAQs in Accordance with the QATR (Section 4OA2.1(2))

05000456/2016007-02; NCV Operation of SX System Valves Results in Cavitation

05000457/2016007-02; Damage and Pipe Leakage (Section 4OA2.1(3))

Closed

05000456/2016007-02; NCV Operation of SX System Valves Results in Cavitation

05000457/2016007-02; Damage and Pipe Leakage (Section 4OA2.1(3))

Discussed

05000456/2014005-02 NCV Failure to Correct Undersized Essential Service Water Pump Bearing Casing Drain Line Resulted in System Inoperability (Section 4OA2.1(2))