IR 05000220/2014002

IR 05000220-14-002, 05000410-14-002; 01/01/2014 - 03/31/2014; Nine Mile Point Nuclear Station, LLC, (NMPNS) Units 1 and 2; Plant Modifications, Follow-Up of Events and Notices of Enforcement Discretion

ML14119A104
Person / Time
Site:	Nine Mile Point
Issue date:	04/28/2014
From:	Daniel Schroeder Reactor Projects Branch 1
To:	Costanzo C Exelon Generation Co
Schroeder D
References
IR-14-002
Download: ML14119A104 (39)

Text

UNITED STATES April 28, 2014

SUBJECT:

NINE MILE POINT NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000220/2014002 AND 05000410/2014002

Dear Mr. Costanzo:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Nine Mile Point Nuclear Station, LLC (NMPNS), Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 10, 2014, with you and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. On April 1, 2014, the operating licenses for the NMPNS held by the Constellation Energy Nuclear Group, LLC (CENG) were transferred to Exelon Generation Company, LLC.

This report documents one NRC-identified and one self-revealing finding of very low safety significance (Green). Both of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs), consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest any of the NCVs in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at NMPNS. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 I, and the NRC Resident Inspector at NMPNS.

Additionally, as we informed you in the most recent NRC annual assessment letter, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region 1, and the NRC Resident Inspector at the NMPNS.

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

Sincerely,

/RA/

Daniel L. Schroeder, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos. 50-220 and 50-410 License Nos. DPR-63 and NPF-69

Enclosure:

Inspection Report 05000220/2014002 and 05000410/2014002 w/Attachment: Supplementary Information

REGION I==

Docket Nos. 50-220 and 50-410 License Nos. DPR-63 and NPF-69 Report Nos. 05000220/2014002 and 05000410/2014002 Licensee: Constellation Energy Nuclear Group, LLC (CENG)

Facility: Nine Mile Point Nuclear Station, LLC Units 1 and 2 Location: Oswego, NY Dates: January 1, 2014 through March 31, 2014 Inspectors: K. Kolaczyk, Senior Resident Inspector E. Miller, Resident Inspector S. Barr, Sr. Emergency Preparedness Inspector E. Burket, Emergency Preparedness Inspector D. Kern, Senior Reactor Inspector S. McCarver, Physical Security Inspector Approved by: Daniel L. Schroeder, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure

SUMMARY

IR 05000220/2014002, 05000410/2014002; 01/01/2014 - 03/31/2014; Nine Mile Point Nuclear

Station, LLC, (NMPNS) Units 1 and 2; Plant Modifications, Follow-Up of Events and Notices of Enforcement Discretion.

This report covered a 3-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified two Green findings, both of which were non-cited violations (NCVs). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011.

Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Initiating Events

Green.

Inspectors documented a self-revealing Green NCV of Technical Specification (TS)5.4, Procedures, for CENGs failure to ensure proper communication of a change in work scope prior to implementation. Specifically, on March 10, 2014, valve label replacements at Unit 2 commenced in a trip sensitive area while the plant was on-line, although the work was previously scheduled to be conducted when the reactor was shut down. This change in work scope was not properly reviewed and communicated to the supporting work group prior to implementation. As a result, a reactor scram occurred when an instrumentation and control (I&C) technician inadvertently contacted an instrument rack located in a trip sensitive area while performing a valve label replacement. CENG generated condition report (CR)-2014-001963 to document the Unit 2 reactor scram due to the technician contacting the instrument line while cutting the valve label. Immediate corrective actions included developing site communications to enhance awareness of trip sensitive equipment and to provide additional flagging barriers to ensure trip sensitive components are not inadvertently contacted.

This finding is more than minor because it is associated with the human performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, CENG staff did not properly ensure that the scope change was properly reviewed and communicated to the supporting work group prior to implementation. This resulted in work being performed while Unit 2 was online and a subsequent automatic reactor scram when an instrument rack was inadvertently contacted. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because while the performance deficiency caused a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, because CENG failed to use proper decision making-practices that emphasize prudent choices over those that are simply allowable [H.14].

(Section 4OA3)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because CENG did not implement adequate design controls to ensure piping in the Reactor Building Closed Loop Cooling (RBCLC) system remained operable while implementing a modification to the Unit 1 control room heating and ventilation system. Specifically, while implementing the modification, CENG personnel removed permanent plant supports and piping for the safety-related RBCLC system and did not fully assess how this change could impact the operability of the system with respect to a hydraulic shock or seismic acceleration event. In response to this observation, CENG initiated CR-2014-001676 and evaluated the condition for operability.

Existing temporary supports were enhanced to provide additional margin by bracing the structure for horizontal loads. An extent of condition walkdown was performed and no additional issues of concern were identified. Subsequently, CENGs operability review determined the RBCLC system had remained operable.

This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, while implementing the modification, CENG removed permanent plant supports and piping for the safety-related RBCLC system and did not fully assess how this change could impact the operability of the system if a hydraulic shock or seismic acceleration occurred. This finding is also similar to examples 3.j and 4.k in IMC 0612, Appendix E, Examples of Minor Issues, where a temporary modification was installed without adequate design information and adequate design controls were not implemented leading to a reasonable doubt of operability of plant components. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding is of very low safety significance (Green) because the performance deficiency was a design or qualification deficiency that did not result in the inoperability of the RBCLC system. The finding has a cross-cutting aspect in the area of Human Performance, Work Management, because CENG failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, CENG failed to ensure that the installed temporary supports were adequate to ensure the RBCLC piping would not be stressed above code allowable values in the event of a seismic acceleration or hydraulic shock event prior to removing the permanently installed seismic supports [H.5]. (Section 1R14)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On January 18, 2014, Unit 1 operators reduced power to 85 percent to restore reactor recirculation pump (RRP) 15 to service; and returned to full power the same day. On February 2, operators reduced power to 94 percent to remove reactor recirculation motor generator set (RRMG) 12 for planned refurbishment. Unit 1 was restored to 100 percent power the same day. On March 1, operators reduced power to 85 percent to return RRMG 12 to service. However, due to an unexpected issue with the motor generator exciter, operators were unable to return RRMG 12 to service. Accordingly, RRMG was left out of service and operators returned Unit 1 to 100 percent power the same day. On March 14, operators reduced power to 85 percent to place RRMG 12 back in service and perform turbine stop valve testing. Power was restored to 100 percent the same day. Unit 1 remained at or near 100 percent power the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. On January 18, 2014, Unit 2 operators reduced power to 65 percent to perform a feedwater pump swap, waterbox repairs, and a rod pattern adjustment. Unit 2 was returned to 100 percent power on January 19. On February 1, operators reduced power to 80 percent to perform a rod pattern adjustment and waterbox repairs.

Unit 2 was returned to 100 percent power the same day. On February 15, operators reduced power to 80 percent to perform a rod pattern adjustment and to continue repairs to the waterbox.

Operators returned Unit 2 to 100 percent the same day. On February 22, operators reduced power to 80 percent to perform a rod pattern adjustment. Unit 2 was returned to 100 percent power on the same day. On March 2, operators reduced power to 80 percent to perform a rod pattern adjustment. Operators returned Unit 2 to 100 percent power the same day. On March 4, operators manually scrammed Unit 2 when cooling water was lost to the RRPs due to a failure of the uninterruptible power supply (UPS) 3B. On March 6, the reactor was taken critical and synchronized to the grid on March 7. Full power was reached on March 8. On March 9, power was reduced to 80 percent for a rod line adjustment. Following the rod line adjustment, power was returned to 100 percent later that day. On March 10, Unit 2 automatically scrammed when an invalid alternate rod insertion signal (ARI) was received when an I&C technician contacted an instrument rack. The reactor was restarted on March 12, and synchronized to the grid on March 13. Full power was reached on March 14. On March 14, operators reduced power to 80 percent to perform a rod pattern adjustment and returned to 100 percent the same day. On March 15, operators reduced power to 80 percent to perform a rod pattern adjustment and returned to 100 percent the same day. On March 23, reactor power was reduced to 92 percent when a level control valve failed closed in the feed water heater drain system. The valve was subsequently repaired, and reactor power was returned to 100 percent later that day. On March 23, operators began to reduce reactor power to commence refueling outage 14 (RFO14). The turbine was removed from the grid on March 24, and the reactor was shutdown and placed into Mode 4 later that day. Cold shutdown was reached on March 25. Core refueling activities began on March 28 and continued through the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of CENGs readiness for the onset of seasonal low temperatures for Unit 1 during the week of January 1, 2014. The review focused on the Unit 1 intake structure and service water (SW) pump area, battery rooms 11 and 12, and the emergency diesel generator (EDG) rooms. The inspectors reviewed the updated final safety analysis report (UFSAR), TSs, control room logs, and the corrective action program (CAP) to determine what temperatures or other seasonal weather could challenge the systems, and to ensure CENG personnel had adequately prepared for these challenges.

The inspectors reviewed station procedures, including CENGs procedure NAI-PSH-11, "Seasonal Readiness Program," Revision 00800. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during cold weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed CENGs readiness for the onset of impending adverse weather conditions at NMPNS that involved unseasonably cold temperatures and snow during the week of February 24, 2014. The review focused on the preparations and response to the adverse weather conditions. As part of the review, the inspectors walked down the Unit 1 EDGs 102 and 103; and battery rooms 11, 12, and 14. The inspectors verified that operator actions defined in CENGs adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 2, the reactor core isolation cooling (RCIC) system during high pressure core spray (HPCS) surveillance testing on January 23, 2014 Unit 1, liquid poison (LP) system 11 following the completion of surveillance activities on February 10, 2014 Unit 1, EDG 102 when EDG 103 was out of service for planned maintenance on March 12, 2014 Unit 1, control room heating, ventilation, and air conditioning (HVAC) following the completion of modification testing on March 13, 2014 Unit 2, Division I EDG during Division II EDG maintenance on March 17, 2014 Unit 1, the 115kv offsite power system following the completion of planned testing of EDG 102 on March 24, 2014 Unit 1, LP system 12 following completion of surveillance activities on March 31, 2014 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders (WOs),

CRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies.

The inspectors also reviewed whether CENG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

During the week of February 28, 2014, the inspectors performed a complete system walkdown of accessible portions of the Unit 1 safety-related 4160 volt electrical distribution system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, drawings, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors performed field walkdowns of accessible portions of the system to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related CRs to ensure CENG staff appropriately evaluated and resolved any deficiencies.

b. Findings

No findings were identified.

1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 6 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that CENG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 1, battery room 11 (fire area (FA)-17A) on January 7, 2014 Unit 1, battery room 12 (FA-17B) on January 7, 2014 Unit 2, SW pump room A (FA-61) on January 7, 2014 Unit 2, SW pump room B (FA-60) on January 7, 2014 Unit 2, diesel fire pump room (FA-62) on January 7, 2014 Unit 2, electric fire pump room (FA-63) on January 7, 2014

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP to determine if CENG staff identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on the Unit 2 Division I, II, and III EDG rooms to verify the adequacy of common drain lines and sumps, sump pumps, level alarms, and control circuits.

b. Findings

No findings were identified

1R11 Licensed Operator Requalification Program & Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Testing and Training (2 samples)

a. Inspection Scope

The inspectors observed:

Unit 1, licensed operator training simulator scenario which included a leaking electromagnetic relief valve, loss of power board 11, recirculation pump trip, and reactor water cleanup system leak on January 21, 2014 Unit 2, licensed operator training simulator scenario which included a single control rod scram, a feedwater level control malfunction, electro-hydraulic control pressure regulator oscillations, and a steam leak in primary containment on January 21, 2014 The inspectors evaluated operator performance during the simulated event and verified completion of risk-significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classifications made by the shift manager and the TS action statements entered by the control room supervisor.

Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room (2

samples)

a. Inspection Scope

The inspectors observed:

Unit 2, control room operations during troubleshooting of the HPCS instrumentation on January 27, 2014 Unit 1, control room operations during reactor building emergency ventilation system (RBEVS) surveillance testing and vacuum breaker 68-03 troubleshooting and post-maintenance testing on January 30, 2014 The inspectors reviewed CNG-OP-1.01-1000, Conduct of Operations, Revision 01000, and verified that procedure use, crew communications, and coordination of plant activities among work groups similarly met established expectations and standards. Additionally, the inspectors observed test performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule basis documents to ensure that CENG was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2)performance criteria established by CENG staff were reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that CENG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

Unit 1, Reactor Building and Turbine Building Blowout Panels on February, 27, 2014 Unit 1, Battery 14 on February 28, 2014

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that CENG performed the appropriate risk assessments prior to removing equipment from service. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that CENG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When CENG personnel performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Unit 1, unplanned maintenance on the emergency service water (ESW) pump 12 on January 9, 2014 Unit 2, planned maintenance on the Division I EDG on January 14, 2014 Unit 2, planned maintenance on the Division I residual heat removal pump on January 16, 2014 Unit 1, planned maintenance on EDG 103 on February 12, 2014 Unit 2, planned maintenance on the Division III EDG on February 25, 2014 Unit 1, planned testing of EDG 103 raw water system on March 11, 2014

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

Unit 1, while performing N1-ST-M3, Suppression Chamber Drywell Relief Valve Exercising, the indication for valve 68-02 did not actuate properly on January 15, 2014 Unit 2, 2MSS*PSV126 safety relief valve leak on January 27, 2014 Unit 1, ESW pump 12 on January 29, 2014 Unit 1, EDG 103 Raw Water System Flow on January 30, 2014 Unit 2, HPCS minimum flow valve 2CSH*MOV105 on January 30, 2014 Unit 2, 2C-ENSX04 Division I EDG Loading Sequence Relay associated with 2RHS*P1A on February 18, 2014 Unit 2, 2FWS-LV10A(B) lock up following loss of offsite power source line 5 on February 20, 2014 Unit 2, RRP A and B seal cavity temperatures on March 4, 2014 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to CENGs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by CENG. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Temporary Modification (1 sample)

a. Inspection Scope

The inspectors evaluated a temporary modification on February 10, 2014, which revised N2-OP-29, Reactor Recirculation, Revision 02000, to jumper a logic relay associated with transfer from high frequency motor-generator sets to low frequency motor-generator sets during Unit 2 reactor shutdown. The inspectors verified that the design bases, licensing bases, and performance capability of the affected system was not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change including the revision to the reactor recirculation operating procedure, the 10 CFR 50.59 screening form, and the procedure controlled temporary change process. The inspectors also reviewed plant operations review committee meeting package from December 6, 2013, which addressed the design issue and corrective actions.

b. Findings

No findings were identified.

.2 Permanent Modification (1 sample)

a. Inspection Scope

The inspectors evaluated Engineering Change Package (ECP-10-000504), Replace Control Room Air Conditioning Chillers, on March 27, 2014. The inspectors verified that the design bases, licensing bases, and performance capability of the affected system was not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change including the post-installation test procedure, the 10 CFR 50.59 screening form, and the operational impact assessment form.

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because CENG did not implement adequate design controls to ensure piping in the RBCLC system remained operable while implementing a modification to the Unit 1 control room heating and ventilation system. Specifically, while implementing the modification, CENG removed permanent plant supports and piping for the safety-related RBCLC system and did not fully assess how this change could impact the operability of the system with respect to a hydraulic shock or seismic acceleration event.

Description.

The control room atmosphere at Unit 1 is cooled by a chilled water system that circulates temperature conditioned water through two cooling coils located in the discharge plenum of the control room ventilation system. The chilled water system is a dual train, 100 percent capacity system. Each train is cooled by two reciprocating compressors that are 60 percent and 40 percent capacity units. The compressor system is cooled by water from the RBCLC system. The RBCLC system at Unit 1 is a safety-related system that provides cooling water to several systems and components including the instrument air compressors, drywell coolers, the feedwater coolant injection pumps, and the spent fuel pool cooling system. To ensure the system remains operable during a seismic acceleration or hydraulic shock event, pipe movement in the horizontal and vertical directions is restrained by plant structural supports.

Over the last several years, the reciprocating compressors have suffered a number of age-related failures. To improve the reliability of the chilled water system, CENG decided to replace the compressors, with new units under ECP-10-000504, Replace Control Room Air Conditioning Chillers. As part of the installation, portions of the RBCLC piping to the compressors would be removed and replaced, and several seismic structural supports for the chilled water and RBCLC systems would require modification.

On February 27, 2014, the inspectors performed a seismic walk down of the in-progress modification to the Unit 1 number 11 control room chilled water system. During the walkdown, the inspectors noted that as part of the modification, CENG personnel had removed portions of the RBCLC piping to the reciprocating compressors in the chilled water system, but did not provide adequate structural support to the remaining sections of RBCLC piping that were required to remain operable. Specifically, CENG personnel had installed floor jacks underneath the RBCLC pipe to support the deadweight vertical loads of the pipe; but did not install supports that would minimize lateral pipe movement. As a result, in the event of a seismic acceleration or hydraulic shock event, the RBCLC piping could have been stressed above code allowable values.

In response to this observation, CENG initiated CR-2014-001676, and evaluated the condition for operability. Existing temporary supports were enhanced to provide additional margin by bracing the structure for horizontal loads. An extent of condition walkdown was performed and no additional issues of concern were identified. CENG also performed additional structural analyses and concluded the unsupported RBCLC piping would remain operable during a hydraulic shock or seismic acceleration event, in part, because of the low pipe weight and low design basis seismic acceleration forces used at Unit 1.

The inspectors independently reviewed the structural analysis and determined that CENGs results appeared reasonable.

Analysis.

The inspectors determined that the failure to ensure the operable portions of the RBCLC piping were adequately supported during the modification was a performance deficiency that was reasonably within CENGs ability to foresee and correct and should have been prevented. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, while implementing the modification, CENG removed permanent plant supports and piping for the safety-related RBCLC system and did not fully assess how this change could impact the operability of the system with respect to a hydraulic shock or seismic acceleration event. This finding is also similar to examples 3.j and 4.k in IMC 0612, Appendix E, Examples of Minor Issues, where a temporary modification was installed without adequate design information and adequate design controls were not implemented leading to a reasonable doubt of operability of plant components.

In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding is of very low safety significance (Green) because the performance deficiency was a design or qualification deficiency that did not result in the inoperability of the RBCLC system.

The finding has a cross-cutting aspect in the area of Human Performance, Work Management, because CENG personnel failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority.

Specifically, CENG personnel failed to ensure that the installed temporary supports were adequate to ensure the RBCLC piping would not be stressed above code allowable values in the event of a seismic acceleration or hydraulic shock event prior to removing the permanently installed seismic supports [H.5].

Enforcement.

10 CFR 50, Appendix B, Criterion III, Design Control, states, 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. These measures shall include provisions to assure that deviations from such standards are controlled. Contrary to the above, from January 13 to February 27, 2014, while modifying the Unit 1 control room ventilation system, CENG did not implement adequate measures to ensure the regulatory requirements and design basis of the Unit 1 ventilation system were correctly translated into specifications, drawings, and instructions and assure that deviations from such standards were controlled. Specifically, CENG removed permanently installed seismic structural supports and piping from operable sections of the RBCLC system and installed temporary structural supports without first ensuring the temporary supports were adequate to ensure operability of the RBCLC system. Because this violation was of very low safety significance (Green) and has been entered into CENGs CAP as CR-2014-001676, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV

===05000220/2014002-01, Inadequate Design Control Measures Employed During Control Room HVAC Modification)

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Unit 2, Division I EDG following remote emergency auxiliary relay replacement (5RST-2EGSA14) on January 15, 2014 Unit 2, 2RDS*M1A following electrical breaker preventative maintenance on February 5, 2014 Unit 1, EDG 103 following raw water heat exchanger (HTX-79-06) maintenance on February 12, 2014 Unit 1, chilled water circulating pump 11 following discharge piping modification on February 13, 2014 Unit 1, RBCLC Pump 13 (70-03) following mounting pad repairs on February 14, 2014 Unit 2, 2EGS*EG2 Division III EDG following motor operated potentiometer maintenance on February 19, 2014

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the following Unit 2 outages:

Unit 2 forced outage (2F1401), which occurred from March 4, 2014 through March 7, 2014 Unit 2 forced outage (2F1402) which occurred from March 10, 2014 through March 13, 2014 Unit 2 planned refueling outage that commenced on March 23, 2014. (Partial sample)

The inspectors reviewed CENGs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outages, the inspectors observed portions of troubleshooting and plant startup processes and monitored controls associated with the following outage activities:

Assessment of post trip review Monitoring of decay heat removal operations Configuration management, including maintenance of defense-in-depth Identification and resolution of problems related to forced outage activities Power ascension activities Plant shutdown activities Equipment lineup Troubleshooting activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TS, the UFSAR, and CENG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

N1-ST-M9, Control Room Air Treatment System Operability Test, on January 2, 2014 N1-ST-Q15, Condensate Transfer System Operability Test, on January 15, 2014 N1-ST-M8, RBEVS Operability Test, on February 3, 2014 N1-ST-Q6B, Containment Spray System Loop 121 Quarterly Operability Test, on February 4, 2014 (In-Service Test)

N1-ST-M3, Suppression Chamber - Drywell Relief Valves Exercising, on February 12, 2014 N1-ST-M1B, LP Pump 12 Operability Test, on March 3, 2014 N1-ST-M8, RBEVS Operability Test, on March 10, 2014 N1-ST-Q26, Feedwater and Main Steam Line Power Operated Isolation Valves Partial Exercise Test and Associated Functional Testing of Reactor Protection System Trip Logic, on March 19, 2014

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

An onsite review was conducted to assess the performance, maintenance, and testing of the NMPNS alert and notification system (ANS). During this inspection, the inspectors conducted a review of the ANS testing and maintenance programs. The inspectors reviewed the associated ANS procedures and the Federal Emergency Management Agency approved ANS Design Report to ensure compliance with design report commitments for system maintenance and testing. The inspection was conducted with 10 CFR 50.47(b)(5) and the related requirements of 10 CFR Part 50, Appendix E, as reference criteria.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors conducted a review of the NMPNS Emergency Response Organization (ERO) augmentation staffing requirements and the process for notifying and augmenting the ERO. The review was performed to verify the readiness of key CENG staff to respond to an emergency event and to verify CENGs ability to activate their emergency response facilities (ERF) in a timely manner. The inspectors reviewed the NMPNS Emergency Plan for ERF activation and ERO staffing requirements, the ERO duty roster, applicable station procedures, augmentation test reports, the most recent drive-in drill reports, and corrective action reports related to this inspection area. The inspectors also reviewed a sample of ERO responder training records to verify training and qualifications were up to date. The inspection was conducted with 10 CFR 50.47(b)

(2) and related requirements of 10 CFR Part 50, Appendix E, as reference criteria.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

CENG implemented various changes to the NMPNS Emergency Action Levels (EALs),

Emergency Plan, and Implementing Procedures. CENG had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50 Appendix E.

The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by CENG as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria.

b. Findings

No findings of significance were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed a number of activities to evaluate the efficacy of NMPNSs efforts to maintain the emergency preparedness program. The inspectors reviewed: letters of agreement with offsite agencies; the 10 CFR 50.54(q) Emergency Plan change process and practice; NMPNSs maintenance of equipment important to emergency preparedness; records of evacuation time estimate population evaluation; and provisions for, and implementation of, primary and backup ERF maintenance. The inspectors also verified CENGs compliance at NMPNS with new NRC emergency preparedness regulations regarding: EALs for hostile action events; protective actions for on-site personnel during events; emergency declaration timeliness; ERO augmentation and alternate facility capability; evacuation time estimate updates; on-shift ERO staffing analysis; and ANS back-up means.

The inspectors further evaluated NMPNSs ability to maintain their emergency preparedness program through their identification and correction of emergency preparedness weaknesses, by reviewing a sample of drill reports, actual event reports, self-assessments, 10 CFR 50.54(t) reviews, and emergency preparedness-related CRs.

The inspectors reviewed a sample of emergency preparedness-related CRs initiated at NMPNS from July 2012 through February 2014. The inspection was conducted with 10 CFR 50.47(b) and the related requirements of 10 CFR Part 50, Appendix E, as reference criteria.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for Unit 1 and Unit 2 licensed operators on January 21, 2014, which required emergency plan implementation by an operations crew. CENG planned for this evolution to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that CENG evaluators noted the same issues and entered them into the CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with

Complications ===

a. Inspection Scope

The inspectors reviewed CENGs submittals for the following Initiating Events Cornerstone PIs for the period of January 1 through December 31, 2013.

Unit 1 and 2 Unplanned Scrams (IE01)

Unit 1 and 2 Unplanned Power Changes (IE03)

Unit 1 and 2 Unplanned Scrams with Complications (IE04)

To determine the accuracy of the PI data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors reviewed CENGS operator narrative logs, maintenance planning schedules, CRs, event reports, and NRC integrated inspection reports to verify the accuracy of the reported PI data.

b. Findings

No findings were identified.

.2 Emergency Planning Performance Indicators (3 samples)

a. Inspection Scope

The inspectors reviewed data for the following three EP PIs:

Drill and exercise performance (EP01)

ERO drill participation (EP02)

ANS reliability (EP03)

The last NRC emergency preparedness inspection at NMPNS was conducted in the second calendar quarter of 2013. Therefore, the inspectors reviewed supporting documentation from emergency preparedness drills and equipment tests from the second calendar quarter of 2013 through the fourth calendar quarter of 2013 to verify the accuracy of the reported PI data. The acceptance criteria documented in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines, Revision 7, was used as reference criteria.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that CENG staff entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended CR screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Missed Surveillance Tests and Preventive Maintenance Tasks

a. Inspection Scope

The inspectors performed an in-depth review of CENG causal analysis, trend reviews, and corrective actions associated with a group of surveillance tests and preventive maintenance activities not performed within their required periodicities. Over the period April 2011 to October 2013, CENG staff identified that several TS required surveillance tests were not performed within their TS specified periodicities. Additionally, several non-TS surveillance tests and preventive maintenance tasks were not performed within the periodicity specified by station maintenance and testing programs. Each activity had been planned or scheduled, but had not been performed.

The inspectors selected a sample of 13 missed surveillance tests and/or preventive maintenance activities for review. The inspectors independently reviewed for Units 1 and 2, the associated CRs, collective apparent cause evaluations, TSs, UFSAR, In-service Test Program results, preventive maintenance program procedures, selected surveillance test procedures and scheduling documents, training lesson plans, and selected maintenance records. Additionally, the inspectors interviewed station personnel to assess current practices and programs to assure surveillance tests and preventive maintenance tasks were properly scheduled and completed. The inspectors assessed CENGs problem identification threshold, documentation of the issues, causal analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of corrective actions to evaluate whether CENG was appropriately identifying, characterizing, and correcting problems associated with this issue. The inspectors also assessed whether CENG had identified associated lessons learned and communicated the results to appropriate staff.

The inspectors compared the actions taken to the requirements of CENGs CAP and 10 CFR Part 50, Appendix B.

b. Findings and Observations

No findings were identified.

CENGs apparent cause evaluation documented in CR-2013-005433 determined that the primary cause of the missed surveillance test or preventive maintenance task was that NMPNS was not committed to successful preventive maintenance tasks and surveillance test program implementation, and that the governing procedures that track surveillance and preventive maintenance program implementation were not adequate. A contributing cause was that previous corrective action(s) developed to address missed preventive maintenance and surveillance tests were eliminated, which reduced organizational sensitivity and accountability to the preventive maintenance and surveillance test programs. As a result, preventive maintenance tasks and surveillance tests were missed due to a combination of: 1) human error; 2) lack of accountability; 3) personnel turnover and 4) frequently rescheduling tasks into their grace period (past due date by up to 25 percent of required periodicity). Additionally, CENGs extent of condition review identified 104 additional preventive maintenance tasks and surveillance tests were improperly scheduled, but not yet overdue.

The inspectors determined that CENG adequately evaluated the missed testing and preventive maintenance issues, identified reasonable primary and contributing causes, established and implemented adequate corrective actions, and effectively communicated the results to plant staff. Corrective actions included development of departmental preventive maintenance and surveillance test accountability models (Maintenance, Operations, Program Engineering, Work Management, System Engineering), development of better preventive maintenance/surveillance test late date look-ahead tools and reports, and development of a desktop guide for preventive maintenance change requests and deferral requests, because corporate level procedures did not provide enough detail for new staff to implement.

Corrective actions, implemented from September 2013 to October 2013, had not been in place for sufficient duration for the inspectors to fully assess their effectiveness. However, the inspectors noted the following preliminary indications of surveillance test and preventive maintenance scheduling improvement:

The five preventive maintenance/surveillance test issues identified during July 2013 to October 2013 were identified as near misses and not late. This provided opportunity to perform the tasks prior to becoming late.

The department preventive maintenance/surveillance test accountability models were formal, identified specific guidance and discipline measures, and were understood by the affected work groups.

The preventive maintenance/surveillance test look-ahead reports were easy to use and were widely disseminated.

Corrective actions were scheduled to perform six month and twelve month effectiveness reviews.

The review included five missed TS surveillance tests. In each case, the inspectors determined the issue was minor because upon discovery station personnel promptly performed the required surveillance test successfully, which verified that equipment operability had not been affected. In accordance with IMC 0612, "Power Reactor Inspection Reports," the missed surveillance tests constituted violations of minor significance that are not subject to enforcement action in accordance with the NRCs Enforcement Policy. CENG entered the late surveillance test issues into their CAP (CR-2011-002022, CR-2011-004326, CR-2011-004527, and CR-2011-004623).

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 Plant Events

a. Inspection Scope

(3 samples)

For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that CENG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed CENGs follow-up actions related to the events to assure that CENG implemented appropriate corrective actions commensurate with their safety significance.

Unit 2, loss of offsite power line 5 and resultant automatic start of the Division l and III EDGs following an electrical fault in the Scriba substation on February 16, 2014 Unit 2, reactor scram due to failure of UPS 3B on March 4, 2014 Unit 2, reactor scram due to an inadvertent initiation of ARI on March 10, 2014

b. Findings

Introduction.

A self-revealing Green NCV of TS 5.4, Procedures, was documented for CENGs failure to ensure proper communication of a change in work scope prior to implementation. Specifically, on March 10, 2014, valve label replacements at Unit 2 commenced in a trip sensitive area while the plant was on-line, although the work was previously scheduled to be conducted when the reactor was shut down. This change in work scope was not properly reviewed and communicated to the supporting work group prior to implementation. As a result, a reactor scram occurred when an I&C technician inadvertently contacted an instrument rack located in a trip sensitive area while performing a valve label replacement.

Description.

The redundant reactivity control system at Unit 2 contains a function known as ARI, which is a backup to the normal reactor protection system. The system is designed to shutdown the reactor by depressurizing the scram header through diverse vent valves in the event that an anticipated transient without a scram event occurs. The ARI system is automatically initiated by high reactor vessel pressure or low reactor vessel water level signals. The sensing instruments for the ARI reactor vessel water level system are located on instrument rack 2CES*RAK004. The rack contains instruments that initiate other emergency core cooling systems and perform containment system isolations when specified water levels are reached.

On March 10, 2014, I&C technicians were replacing valve labels on 2CES*RAK004 as part of corrective actions associated with CR-2012-003778 Division 1 Diesel Generator Auto Started During Transmitter Venting. The corrective action was to replace the installed valve labels with new labels that were intended to improve worker awareness of the potential impact of a plant scram if the valves were manipulated or disturbed. While working on the third label replacement, the technician inadvertently contacted a component on the instrument rack associated with reactor vessel water level. This event caused an invalid low reactor water level 2 signal (108) to be generated in the instrument rack, which initiated the ARI and RCIC systems.

Plant systems responded as designed to the presence of a level 2 signal. Operators entered appropriate plant procedures and brought the plant to a stable hot shutdown condition with no complications. Control room operators were also promptly alerted to the cause of the invalid ARI signal by the technician who immediately informed the control room of the inadvertent instrument rack contact.

Following the scram, CENG conducted a human performance review board (HURB) to discuss the event and to develop immediate compensatory measures until a root cause assessment could be completed. During the HURB, CENG staff noted that WO C92589161, Install labels per CR-2012-003778, which was being used by the technician to re-label the valves, was originally coded to be performed during Mode 4 or Mode 5 (Cold Shutdown or Refueling). This WO was created on March 4, 2014, during a forced shutdown at Unit 2 when there was an opportunity to perform this work during a plant shutdown. However, this WO was not implemented during the outage. Following restart of the plant, during a general supervisor meeting, CENG personnel determined this work could be performed online.

The inspectors noted that CENG procedure CNG-MN-4.01-1001, Work Order Execution and Closure Process, Revision 00401, Section 5.8.D and 5.9, state, in part, that when a scope change is taking place for a work activity, that work shall not continue until the work package has been updated by the planning department and reviewed by either a planning supervisor or first line supervisor and approved by a senior reactor operator for plant impact.

CNG-MN-4.01-1001, states, in part, that performing a work activity in a different mode than what was originally planned constitutes a change in work scope. Despite these requirements in CNG-MN-4.01-1001, the work package was not reviewed to reflect how the change in work scope could impact the plant when the decision was made to perform WO C92589161 while the reactor was on-line vice shutdown. As a result, CENG missed an opportunity to risk assess how the plant may be impacted by performance of the work activity while the plant was on-line. CENG generated CR-2014-001963 to document the Unit 2 reactor scram due to the technician contacting the instrument line while cutting the valve label. CENGs immediate corrective actions included developing site communications to enhance awareness of trip sensitive equipment and to provide additional flagging barriers ensure trip sensitive components are not inadvertently contacted.

Analysis.

The inspectors determined that CENGs failure to correctly implement CNG-MN-4.01-1001, and ensure that the scope change of replacing the valve information labels while Unit 2 was online instead of during shutdown was properly reviewed, communicated, and assessed for plant impact prior to implementation was a performance deficiency that was reasonably within CENGs ability to foresee and correct and should have been prevented. This finding is more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, CENG did not properly ensure that the scope change was properly reviewed and communicated to the supporting work group prior to implementation as directed by station procedures. This resulted in work being performed while Unit 2 was online and a subsequent automatic reactor scram when an instrument rack was inadvertently contacted.

In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because while the performance deficiency caused a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

The finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, because CENG failed to use proper decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, when a scope change was made, proper reviews and communications were not completed; resulting in work being performed that unnecessarily caused a reactor scram [H.14].

Enforcement.

TS 5.4 Procedures, states, in part, "Written procedures shall be established, implemented, and maintained covering . . . the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978 . . ."

Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Section 9, "Procedures for Performing Maintenance," states, in part, "Maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with documented instructions . . . appropriate to the circumstances." Contrary to the above, on March 10, 2014, CENG failed to properly implement procedures designated for work execution. Specifically, the inspectors determined that CENG failed to ensure the scope change associated with a valve label replacement was properly reviewed and communicated to the supporting work group prior to implementation. This resulted in work being performed while Unit 2 was online and an automatic reactor scram when a component on an instrument rack associated with reactor water level was inadvertently contacted. Because the violation was of very low safety significance and was entered into CENGs CAP as CR-2014-001963, this violation is being treated as an NCV consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000410/2014002-02, Invalid Low Reactor Water Level Results in Unit 2 Automatic Reactor Scram)

Failure, HPCI Initiation and Reactor Scram (1 sample)

This LER was revised on November 5, 2013, to update the root cause of the event and follow-on corrective actions. In the original LER, CENG reported that the unexpected rise in reactor vessel water level and subsequent reactor scram was caused by a failure of two transistors in the reactor vessel water level control system. The failed transistors sent a maximum open demand signal to flow control valve (FCV)29-141, which led to an increase in reactor vessel water level, turbine trip, and subsequent reactor scram. In the revised LER, CENG reported that in addition to the transistor failures, FCV 29-141 operated slowly during the event, and as a result, reactor vessel water level could not be maintained within the normal operating band, resulting in a reactor scram on low reactor vessel water level. CENG determined that FCV 29-141 failed to operate properly because the valve preventive maintenance program was inadequate. Specifically, CENG was not verifying FCV 29-141 could stroke within design requirements. Further, CENG was not replacing components that were susceptible to age related degradation on a routine basis.

CENG corrective actions included performing the required preventive maintenance on FCV 29-141, and reviewing the preventive maintenance program for similar components to ensure the maintenance strategy met industry standards contained in the maintenance templates. The enforcement aspects of this issue regarding testing and maintenance of Unit 1 flow control valves are discussed in NRC Integrated Inspection Report 05000220/2013002. The inspectors did not identify any new issues during review of this revised LER. This LER is closed.

4OA5 Other Activities

The table below provides a cross-reference from the 2013 findings which will be considered in the 2014 mid-cycle assessment review and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative.

These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000220/2013005-01 P.1(a) P.1 05000410/2013005-02 P.1(c) P.2 05000410/2013007-01 H.2(a) H.6 05000410/2013010-01* H.2(c) H.7 05000410/2013010-02** H.4(a) H.12 (NOTE: list ALL 3Q13 and 4Q13 findings, including security related, above to have one master cross-reference)

• Finding 05000220/2013010-01 was dispositioned in 2Q13 and documented as TBD in IR 05000220/2013003. The finding was issued in 4Q13 following a regulatory conference.

This cross-cutting aspect will not count towards 3rd or 4th quarter mid-cycle assessment review.

• • Finding 05000220/2013010-02 was dispositioned in 4Q13 following a regulatory conference. This cross-cutting aspect will count towards mid-cycle assessment review.

4OA6 Meetings, Including Exit

On April 10, 2014, the inspectors presented the inspection results to Mr. Christopher Costanzo, Site Vice President, and other members of the NMPNS staff. The inspectors verified that no propriety information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Costanzo, Vice President

J. Stanley, Plant General Manager

P. Bartolini, Supervisor, Design Engineering

J. Bouck, Manager, Operations

M. Busch, Unit 1 General Supervisor, Operations

K. Clark, Director, Security

J. Dean, Supervisor, Quality Assurance

S. Dhar, Design Engineering

J. Holton, Supervisor, Systems Engineering

S. Homoki, System Engineer

M. Kunzwiler, Security Supervisor

J. Leonard, Supervisor Design Engineering

J. Manly, Unit 2 General Supervisor, Operations

E. Perkins, Director, Licensing

J. Prosachik, Supervisor, Systems Engineering

M. Shanbhag, Licensing Engineer

J. Snyder, Maintenance Rule Coordinator

J. Thompson, General Supervisor, Mechanical Maintenance

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000220/2014002-01 NCV Inadequate Design Control Measures Employed During Control Room HVAC Modification (Section 1R18)

05000410/2014002-02 NCV Invalid Low Reactor Water Level Results in Unit 2 Automatic Reactor Scram (Section 4OA3)

Closed

05000220/2012-005-01 LER Feedwater Level Control Failure, HPCI Initiation and Reactor Scram (Section 4OA3)

Discussed

05000220/2013002-02 FIN Test Conditions Not Properly Established (Section 4OA3)