IR 05000315/2013004

IR 05000315-13-004, 05000316-13-004; 07/01/2013 - 09/30/2013; D. C. Cook Units 1 & 2; Maintenance Effectiveness, Operability Determinations and Functional Assessments, Outage Activities, Identification & Resolution of Problems

ML13330B788
Person / Time
Site:	Cook
Issue date:	11/26/2013
From:	Jamie Benjamin Division Reactor Projects III
To:	Weber L Indiana Michigan Power Co
References
IR-13-004
Download: ML13330B788 (52)

Text

vember 26, 2013

SUBJECT:

D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000315/2013004; 05000316/2013004

Dear Mr. Weber:

On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your D. C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on October 8, 2013, with Mr. J. Gebbie, 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.

Based on the results of this inspection, five self-revealed findings of very low safety significance were identified. Two of the findings involved a violation of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy. Additionally, two licensee-identified violations are listed in Section 4OA7 of this report.

If you contest the violations or significances of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copies to the Regional Administrator, Region III, the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the D. C. Cook Nuclear Power Plant. 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 III, and the NRC Senior Resident Inspector at the D. C. Cook Nuclear Power Plant. In accordance with 10 CFR 2.390 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs Rules of Practice, a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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/

Jamie Benjamin, Acting Chief Branch 4 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74

Enclosure:

Inspection Report 05000315/2013004; 05000316/2013004 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000315; 05000316 License Nos: DPR-58; DPR-74 Report No: 05000315/2013004; 05000316/2013004 Licensee: Indiana Michigan Power Company Facility: D. C. Cook Nuclear Power Plant, Units 1 and 2 Location: Bridgman, MI Dates: July 1 through September 30, 2013 Inspectors: J. Ellegood, Senior Resident Inspector P. LaFlamme, Resident Inspector M. Mitchell, Health Physicist D. Szwarc, Reactor Inspector J. Lennartz, Project Engineer Approved by: Jamie Benjamin, Acting Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000315/2013004, 05000316/2013004; 07/01/2013 - 09/30/2013;

D. C. Cook Nuclear Power Plant, Units 1 and 2; Maintenance Effectiveness, Operability Determinations and Functional Assessments, Outage Activities, Identification and Resolution of Problems This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Five Green findings were identified. Two findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings are 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, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance (Green) occurred because the licensee failed to adjust a key parameter, (KWINIT), in the turbine digital control system after replacing and calibrating the turbine control system linear variable differential transformers. Vendor documents for the generator recommended an initial load of 2 to 5 percent of full load when the turbine generator is synchronized to the grid.

For Cook Unit 1, this equates to 22 to 54 megawatts. However, the licensee did not adjust the KWINIT parameter, which is used to determine control valve position, after the turbine control system linear variable differential transformers were replaced and subsequently calibrated using a tighter tolerance than previously used. Consequently, when the turbine generator was synchronized to the grid the turbine control valves opened more than on previous synchronizations, which resulted in picking up excessive load. As a result, reactor cooling system (RCS) temperature momentarily lowered below the minimum temperature for criticality. As an immediate corrective action, the licensee stabilized the plant by taking manual control of the turbine generator. The licensee has entered the condition into the corrective action program (CAP) as AR 2013-7472.

Using IMC 0612 the inspectors concluded that this issue was more than minor because it is associated with the equipment performance attribute in the Initiating Events Cornerstone and it adversely impacted the cornerstone objective of limiting the likelihood of events that upset plant stability. Using IMC 0609, Appendix A, Exhibit 1, the inspectors concluded the finding was of very low safety significance (Green) because it did not cause both a reactor trip and a loss of mitigating equipment. The inspectors concluded the finding had an aspect in the Work Control component of the Human Performance cross-cutting area because the licensee did not coordinate work activities to address the impact of changes to work activities on plant performance, (H.3(b)).

(Section 1R20)

Green.

A self-revealed finding of very low safety significance occurred because the licensee failed to program the automatic controller for the condensate heater condensate bypass control valve, 2-CRV-224, with the correct setpoint. Specifically, the automatic controller (2-RU-2) setpoint was not set at the required 240 psig because licensee personnel incorrectly interpreted information in SD-ENG-05400, System Description Condensate System. Consequently, an incorrect set point of 188 psig was incorporated in procedure 2-OHP-4021-001-006, Power Escalation, which was used to program the automatic controller. As a result, 2-CRV-224 did not open as designed to mitigate the lowering main feedwater pump suction pressure, which resulted in the west main feedwater pump tripping on low suction pressure and a subsequent manual reactor trip.

For corrective actions, the licensee programmed the correct setpoint into the automatic controller; revised the associated procedures to ensure setpoint changes are accurately incorporated and reviewed prior to implementation; developed plans to communicate lessons learned to the site; and entered the condition into the CAP.

Using IMC 0612 the inspectors determined that this issue was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, failure to set the 2-CRV-224 automatic controller to the design setpoint of 240 psig resulted in the subsequent loss of the west main feedwater pump during a feedwater heater level transient, which caused steam generator water levels to lower and required the operators to manually trip the reactor. The inspectors determined the finding was of very low safety significance (Green) using Exhibit 1 of IMC 0609, Appendix A, because the finding did not cause both a reactor trip and a loss of mitigating equipment. The inspectors concluded that this finding was associated with an aspect in the Resources component of the Human Performance cross-cutting area.

Specifically, the procedure used to program the automatic controller for 2-CRV-224 was not accurate in that it did not contain the correct design setpoint, (H.2 (c)).

(Section 1R20)

Cornerstone: Mitigating Systems

Green.

A self-revealed finding of very low safety significance (Green) and associated NCV of Technical Specification (TS) 5.4.1 occurred because the licensee failed to establish, implement, and maintain procedures regarding proper steam generator stop valve dump valve preventative maintenance. Specifically, the licensee improperly packed Unit 2 steam generator #1 stop valve dump valve, 2-MRV-212, which resulted in three consecutive in-service test surveillance testing failures, (October 26, 2012,

January 26, 2013, and April 25, 2013). Each testing failure resulted in the valve being declared inoperable. The testing failures occurred because the maintenance procedure used during the valve packing activity, 12-MHP-5021-005-003, Valve Packing Removal,

Installation and Adjustment, did not provide instructions on the appropriate number of packing rings to be installed. Corrective action included repacking the valve with the correct number of packing rings and initiating corrective action document AR 2013-6243.

Using IMC 0612, the inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and it impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to events. Specifically, the performance deficiency resulted in an inoperable steam generator stop valve dump valve. The inspectors determined that this issue was of very low safety significance (Green) because the inspectors answered no to all the screening questions in IMC 0609,

Appendix A, Exhibit 2. The inspectors concluded that this issue had an aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area, because the licensee failed to correct the cause of the slow stroke time on two prior surveillance failures, (P.1(c)). (Section 1R12)

Green.

A finding of very low safety significance was self-revealed on April 24, 2013, because the licensee failed to comply with requirements contained in procedure PMI-7030, Corrective Action Program, prior to restoring power to the Unit 1 reserve auxiliary transformer CD-101. Specifically, following multiple trips of supply breaker 12 CD, the licensee failed to correct an issue, defined as a condition adverse to quality in their corrective action program, prior to restoring power to the transformer on April 21.

This ultimately led to the supply breaker to the Unit 1 and 2 reserve auxiliary transformers opening due to a faulted cable. No violations of NRC requirements were identified for this issue since the degraded cable was on a non-safety related portion of the electrical system. The licensee entered the issue into the corrective action program as AR 2013-6194. The corrective actions for this issue included replacing the faulted cables and testing the unaffected cables.

Using IMC 0612, the inspectors concluded that the issue was more than minor because it was associated with the equipment performance attribute of the Mitigating System Cornerstone and it adversely impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the degraded insulation failed causing a loss of the qualified circuit; a condition which lessened the likelihood of its availability for some events. Using IMC 0609, Appendix A, Section 6, a detailed risk evaluation, assuming inoperability of four days, determined the delta Core Damage Frequency was less than 1E-6; therefore the finding screens as very low safety significance (Green).

The inspectors concluded this finding was associated with an aspect in Operating Experience component of the Problem Identification and Resolution cross-cutting area because the licensee did not implement and institutionalize operating experience information from the Electric Power Research Institute (EPRI) and Institute of Electrical and Electronics Engineers (IEEE) into processes and procedures, (P.2(b)).

(Section 1R15)

Green.

A self-revealed finding of very low safety significance and associated non-citied violation of TS 5.4.1 occurred because the licensee failed to implement procedures for equipment control. Specifically, plant workers caused two unplanned Limiting Conditions for Operation (LCO) entries due to inadvertent equipment operation that resulted from inadequate implementation of procedures for equipment control. The first inadvertent equipment operation rendered the Unit 1 west motor driven auxiliary feedwater (AFW) pump inoperable for approximately 14 minutes; the second inadvertent equipment operation rendered one qualified offsite electrical circuit inoperable to both units for approximately 30 minutes. For corrective actions, in both cases, the licensee restored the equipment to an operable status and communicated the errors to site personnel to improve worker situational awareness.

Using IMC 0612, Appendix B, the inspectors concluded that the issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely impacted the cornerstone objective of ensuring the reliability of systems that respond to initiating events. The inspectors determined that the finding was of very low safety significance (Green) using IMC 0609,

Exhibit 2, because the finding: was not a deficiency affecting the design or qualification of a mitigating system; did not represent a loss of system or function; did not represent a loss of function for greater than the technical specification allowed outage time; and did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. The inspectors concluded that the finding included an aspect in the Work Control component of the Human Performance cross-cutting area because the licensee failed to appropriately plan work using risk insights, (H.3(a)). (Section 4OA2)

Licensee-Identified Violations

Violations of very low safety significance or Severity Level IV that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near 100 percent power for the entire inspection period.

Unit 2 operated at or near 100 percent power until July 28 when operators manually inserted a trip in response to a secondary transient. The licensee restarted Unit 2 on July 30 and ascended to 100 percent on August 1. Unit 2 operated at or near 100 percent until September 29 when the licensee reduced power prior to a refueling outage.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• 2CD emergency diesel generator (EDG);

• Unit 1 east residual heat removal; and

• Unit 1 turbine driven auxiliary feedwater (AFW) train.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), technical specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.

The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.

The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Fire Zone 19, Unit 2 AB EDG;

• Fire Zone 17B, Unit 2 west AFW pump room;

• Fire Zone 17D, Unit 1 east AFW pump room; and

• Fire Zone 17E, Unit 1 turbine driven AFW room.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

These activities constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. The inspectors verified that water tight covers were intact and not degraded and drainage of the area was available. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

• MH1PA, MH2PA, MH2CAB, and Unit 1/2 4 kilo volt (KV) settling pits.

Specific documents reviewed during this inspection are listed in the Attachment to this report. This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On August 27, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On July 30, 2013, the inspectors observed startup of Unit 2. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions.

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• containment; and

• steam generator stop valve/dump valves.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) and associated NCV of TS 5.4.1 occurred because the licensee failed to establish, implement, and maintain procedures regarding proper steam generator stop valve dump valve preventative maintenance. Specifically, the licensee improperly packed Unit 2 steam generator #1 stop valve dump valve, 2-MRV-212, which resulted in three consecutive in-service test (IST) surveillance testing failures (October 26, 2012, January 26, 2013, and April 25, 2013). Each testing failure resulted in the valve being declared inoperable.

Description:

On October 26, 2012, January 26, 2013, and April 25, 2013, the Unit 2 steam generator #1 stop valve dump valve 2-MRV-212 stroke times exceeded the established acceptance criteria. Although the licensee took corrective actions for the October and January failures, the corrective actions did not resolve the cause of the slow stroke time. In each case, the valve passed post-maintenance testing following the failed test and associated corrective action, however, with low margin.

On October 26, 2012, the valve failed its IST stroke time during surveillance testing (AR 2012-13465). Following the testing failure the licensee entered TS 3.7.2, Steam Generator Stop Valves, Condition A, because the licensee considered the valve to be inoperable. Based on prior experience, the licensee replaced a quick exhaust valve component to correct the issue and retested the valve with an acceptable stroke time.

On January 26, 2013, the valve, again, failed to stroke with an acceptable time during the next routine IST stroke time surveillance (AR 2012-13465). The licensee updated the Technical Data Book to treat the valve as a regular valve with an upper stroke time limit of 2.1 seconds vice a quick acting valve with an upper stroke time limit of 2.0 seconds. The valve stroked in 2.09 seconds, just below the new criteria of 2.1 seconds. The test failure again resulted in entry to TS LCO 3.7.2, Steam Generator Stop Valves, Condition A. On February 20, 2013, the licensee replaced the quick release valve and a solenoid valve in the system. Since these actions appeared to have improved valve stroke time, the licensee restored the acceptance criteria to that of a quick acting valve (i.e., 2.0 seconds). In addition, the licensee performed an equipment apparent cause evaluation. In this evaluation, the licensee concluded that a red sealant material in the quick exhaust valve caused the slower stroke time. The licensee subsequently refuted that conclusion based on the presence of the red sealant material in valves that operated within specification and confirmation from the vendor that the sealant is needed for the component.

On April 25, 2013, the licensee performed the routine valve stroke surveillance and, again, the valve failed to stroke within the required time. The licensee identified that the cause of the high stroke time was due to high packing resistance. The licensee corrected the issue by replacing the valve packing and restored the valve to an acceptable stroke time in line with historic norms. While replacing the packing, the licensee found seven rings of packing above the bushing. Although the work order, performed in 2010, documented five rings of packing, the licensee concluded that seven rings had been installed. Further investigation by the licensee revealed that the packing and bushing did not meet dimensional and quantity specifications recommended by the vendor. The licensee determined that the work instruction did not include a worksheet or work order evaluation request to identify the approved packing kit for the valve. Since replacing the packing, the licensee has successfully stroked the valve multiple times.

Analysis:

The inspectors determined that the licensees failure to properly pack Unit 2 steam generator #1 stop valve dump valve 2-MRV-212 was a performance deficiency that required an evaluation using the SDP. Specifically, the licensees associated maintenance procedure 12-MHP-5021-005-003, Valve Packing Removal, Installation and Adjustment, did not provide instructions on the appropriate number of packing rings to be installed, the required height of the carbon bushing, or the associated torque values to be used. The inadequate procedure resulted in maintenance personnel installing seven rings of packing instead of the required five rings. This error was attributed to the reason that 2-MRV-212 failed its IST stroke time surveillance the three times discussed in this finding and the resultant unplanned TS LCO 3.7.2, Steam Generator Stop Valves, Condition A, entries.

In accordance with IMC 0612, Appendix B, Issue Screening, issue date September 7, 2012, the inspectors concluded that traditional enforcement did not apply. The inspectors concluded that the issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. Specifically, the performance deficiency resulted in additional time that the Unit 2 steam generator #1 stop valve dump valve was not available to perform its prescribed safety function. Because the finding was associated with a mitigating system at power, the inspectors assessed the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, issued June 19, 2012. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012, the inspectors determined it was of very low safety significance (Green) because all the screening questions were answered no. The inspectors determined that this issue had an aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because the licensee failed to correct the cause of the slow stroke time on two prior surveillance failures. (P.1(c)).

Enforcement:

Technical Specification 5.4.1 requires, in part, that written procedures be established, implemented and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Section 9a of RG 1.33, Revision 2, Appendix A, February 1978, requires maintenance that can affect the performance of safety-related equipment be properly pre-planned and performed in accordance with written procedures, documented instructions or drawings as appropriate to the circumstances.

Contrary to the above, on August 25, 2010, the licensee failed to establish, implement and maintain procedure 12-MHP-5021-005-003, Valve Packing Removal, Installation and Adjustment, Revision 5. Specifically, procedure 12-MHP-5021-005-003, Valve Packing Removal, Installation and Adjustment, did not provide instructions on the appropriate number of packing rings to be installed, the required height of the carbon bushing, or torque values that aligned with the approved packing kit for the maintenance performed on the Unit 2 steam generator #1 stop valve dump valve 2-MRV-212. This allowed maintenance personnel to install seven rings of packing instead of the correct number of five rings. The excessive packing rings caused 2-MRV-212 to fail its IST stroke time on three separate occasions, resulting in the valve being declared inoperable for a slow stroke time, and the unplanned entry into Technical Specification LCO 3.7.2, Steam Generator Stop Valves, Condition A. Because this violation was of very low safety significance (Green) and it was entered into the CAP as AR 2013-6243, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000316/2013004-01: Unit 2 Steam Generator #1 Stop Valve Dump Valve 2-MRV-212 Stroke Time Failure due to Operation of Dump Valve Outside its Packing Design). Corrective actions for this issue included repacking the valve and revising affected procedures.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Unit 1 AB EDG planned maintenance; and

• Unit 2 east component cooling water heat exchanger essential service water outlet valve maintenance and Unit 1 motor driven AFW valve maintenance week of July 1, 2013.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Specific documents reviewed during this inspection are listed in the Attachment to this report. These maintenance risk assessments and emergent work control activities constituted two samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• auxiliary building pre-action sprinkler system clogging;

• loss of Unit 1 and Unit 2 reserve feed train B with Unit 1 east containment spray train A inoperable evaluation;

• safety-related ventilation for Unit 2 4KV room damper failure; and

• past operability of Unit 2 qualified circuit.

This operability inspection constituted four samples as defined in IP 71111.15-05.

b. Findings

Introduction:

A finding of very low safety significance was self-revealed on April 24, 2013, due to station personnel failing to comply with requirements contained in procedure PMI-7030, Corrective Action Program, prior to restoring power to the Unit 1 reserve auxiliary transformer CD-101. Specifically, the licensee restored power on April 21, 2013, without correcting an issue, as defined in the licensees corrective action procedures as a condition adverse to quality, as required by the CAP. This ultimately led the supply breaker to the Units 1 and 2 reserve auxiliary transformers opening due to a faulted cable.

Discussion: On April 16, 2013, the licensee re-energized the Unit 1 reserve auxiliary transformer CD-101 following work on the transformer. Seconds later, 34.5KV breaker 12CD, which supplies power to both Unit 1 and 2 reserve auxiliary transformers, opened on neutral-ground over current. The licensee entered LCO 3.8.1, AC [Alternate Current]

Sources - Operating, Condition A, for Unit 2 and restored power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. No LCO entry was required for Unit 1 because the unit was de-fueled at the time. After restoring power to Unit 2, the licensee performed troubleshooting on the Unit 1 transformer and associated cabling and switchgear. This troubleshooting did not reveal the cause of breaker 12CD opening. On April 21, 2013, the licensee re-energized the transformer after their troubleshooting efforts did not reveal why supply breaker 12CD opened.

On April 24, 2013, the breaker opened again. Unit 2 again entered the TS 3.8.1 LCO.

Personnel in the area of an overhead raceway containing cables from transformer CD-101 to safety-related switchgear reported sparks. The licensee disconnected CD-101, restored power to Unit 2, and exited the LCO. The licensee began troubleshooting the opening of the breaker and initial testing failed to identify a grounded cable. The licensee performed walkdowns of the elevated raceway and located indications on the raceway of an electrical fault. These indications were in the area where workers reported sparks. Further investigation revealed a cable with significant damage to the insulation. The faulted cable powered the Unit 1 safeguards bus 1C.

The licensee performed additional research on methods to detect cable insulation degradation. Information provided by a vendor included application of recommendations from EPRI documents and IEEE 400.2-2004, Guide for Field Testing of Shielded Power Cable Systems, for testing at higher voltages. Application of a higher voltage, as recommended by IEEE and a vendor, may have revealed the faulted cable following the first trip. The licensee noted in the apparent cause evaluation that use of the test method during the previous outage, 1U24, was a missed opportunity to find the defect.

Therefore, failing to use this technique following the breaker trip on April 16, 2013, also represented a missed opportunity to find the defect prior to re-energizing the line. The inspectors also noted that a physical walkdown of the cable could reasonably have occurred because the cable, including the section with the fault, was located outside.

A walkdown may also have located the fault. Licensee procedure PMI-7030 identifies, as an objective, the identification and correction of conditions adverse to quality.

Licensee procedure PMP-7030-MOP-001, Corrective Action Management Oversight Process, identifies, as an example of a condition adverse to quality, any unexpected loss of function for the 4KV electrical distribution system. The licensee correctly identified this issue as a condition adverse to quality in accordance with the CAP.

However, the licensee failed to correct the condition prior to restoring power to transformer CD-101. Since the degraded insulation was on a nonsafety-related portion of electrical distribution, 10 CFR 50 Appendix B did not apply; therefore, no violation of regulatory requirements occurred. For corrective actions the licensee replaced the degraded cable and restored the off-site circuit to operable status.

Analysis:

The inspectors determined the licensees failure to correct the cause of the breaker tripping multiple times, a condition adverse to quality, prior to returning the system to service was a performance deficiency that warranted a significance determination. The inspectors determined that traditional enforcement did not apply.

The inspectors determined that the issue was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone; and it adversely impacted the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the degraded insulation failed causing a loss of the qualified circuit; a condition which lessened the likelihood of its availability for some events.

Since Unit 2 was at power the inspectors used IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issue June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, issue date June 19, 2012. The inspectors determined that the finding was bounded by a loss of a single train in excess of the technical specification allowed outage time. Therefore, a detailed risk evaluation using IMC 0609, Appendix A, Section 6, was required.

The D. C. Cook Standardized Plant Analysis Risk (SPAR) model version 8.20 and Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE)version 8.0.9.0 software was used to obtain the delta risk significance for the finding.

The D. C. Cook SPAR model is for Unit 1, and was used as a model for Unit 2 to evaluate the issue. Specifically, the failure to supply offsite power through transformer 101CD was modeled for an exposure time of 4 days.

The evaluation resulted in a delta core damage frequency of 9.6E-8/yr. The dominant sequence was a steam generator tube rupture initiating event with a failure to isolate a faulted steam generator, a failure to refill the refueling water storage tank, and a failure of decay heat removal. Therefore, based on the detailed risk evaluation, the inspectors determined that the finding was of very low safety-significance (Green).

The inspectors concluded that this finding was associated with an aspect in the Operating Experience component of the Problem Identification and Resolution cross-cutting area. Specifically, the licensee failed to implement and institutionalize operating experience information from the Electric Power Research Institute (EPRI) and Institute of Electrical and Electronics Engineers (IEEE) into processes and procedures, (P.2(b)).

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a Finding (FIN)

(FIN 05000315/316/2013004-02, Faulted 4KV Qualified Off-site Circuit). The licensee entered this condition into the corrective action program as AR 2013-6194.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

• 12-TM-13-35-R0, Temporary Modification to Provide Ventilation/Cooling to the Annunciator/Primary Plant Computer Servers Located in the Technical Support Center Computer Room The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

This inspection constituted one temporary modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Unit 1 east residual heat removal pump and valve maintenance;

• Unit 2 turbine driven AFW pump discharge to steam generator No. 2 control valve maintenance; and

• Unit 1 gamma metrics neutron flux monitor N-23, A2 and A3 card replacements.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage

a. Inspection Scope

As follow up, the inspectors reviewed resolution of problems identified during the Unit 1 refueling outage. In addition, the inspectors reviewed major work activities for the upcoming Unit 2 refueling outage. Documents reviewed are listed in the attachment to the report. This inspection did not constitute a refueling outage sample as defined in IP 71111.20-05.

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) occurred because the licensee failed to adjust a key parameter (KWINIT) in the turbine digital control system after replacing and calibrating the linear variable differential transformer associated with the turbine control system. Consequently, the turbine was loaded in excess of that specified by the turbine vendor when the turbine generator was synchronized to the grid. This resulted in momentarily lowering reactor coolant system (RCS) temperature below the minimum temperature for criticality.

Discussion: On May 19, 2013, after closing the turbine generator output breaker, the turbine generator immediately attempted to load 150 to 185 megawatts (MW), which was more load than recommended by the vendor. The load addition resulted in lowering RCS temperature below the minimum temperature for criticality for 90 seconds. Prompt action was taken by control room personnel to reduce the load demanded by the turbine digital control system (DCS), which mitigated the transient.

Licensee personnel determined that the KWINIT parameter, which is used by the DCS to load the generator when synchronized to the grid, was not adjusted to account for changes in calibration practices used on the linear variable differential transformers that position the control valves. The DCS uses the KWINIT parameter to position control valves to a defined position when the turbine is synchronized to the grid to ensure the turbine generator picks up vendor recommended load of 30 to 50 MW, which prevents reverse powering the generator. When the DCS was initially installed, the licensee determined empirically that a KWINIT setting of 185 would achieve an acceptable load increase on synchronization. This setting provided the desired load following several outages. However, during refueling outage 25, the licensee replaced the linear variable differential transformers used to position the turbine generator control valves. In addition, the licensee calibrated the linear variable differential transformers using a tighter tolerance than previously used and included a null current offset. This offset resulted in shifting the position sensed by the linear variable differential transformer such that the control valve was more open for a given sensed position than prior to calibration.

Consequently, when the turbine generator was synchronized to the grid, the DCS opened the control valve more than on previous synchronizations, which resulted in picking up the excess load. The licensees root cause determined that they failed to anticipate the effect of the linear variable differential transformer calibration on the control valve response when synchronizing the turbine generator with the grid.

The vendor recommended load, as specified in VTD-GENE-0728, GE Normal Starting and Operating Instructions, when the turbine generator is synchronized to the grid is 2 to 5 percent, which equates to 22 to 54 MW for the Unit 1 turbine. Contrary to this vendor specification, the DCS attempted to load the turbine with 150 to 185 MW.

Analysis:

The inspectors concluded that the failure to adjust the KWINIT parameter in the turbine DCS to ensure the vendor recommended synchronization load was maintained after replacing and calibrating the linear variable differential transformers was a performance deficiency that warranted a significance determination. In accordance with IMC 0612 Appendix B, Issue Screening, issued September 7, 2012, the inspectors concluded that traditional enforcement did not apply. The inspectors concluded that the issue was more than minor because it is associated with the equipment performance attribute in the Initiating Event cornerstone and adversely impacted the cornerstone objective of limiting the likelihood of events that upset plant stability. Specifically, the performance deficiency impacted the reliable synchronization of the turbine generator such that the turbine picked up more than the recommended load, which caused RCS temperature to momentarily lower below the minimum temperature for criticality. The resulting transient could have resulted in a plant trip had operators not taken prompt corrective action to stabilize turbine load.

Because the finding was associated with the Initiating Event cornerstone at power, the inspectors assessed the finding using IMC 0609, Appendix A, The Significance Determination Process For Findings at Power, issued June 19, 2012, Exhibit 1, Initiating Events Screening Questions, issued June 19, 2012. The inspectors concluded that the finding was of very low safety significance (Green), because the finding did not cause both a reactor trip and a loss of mitigating equipment. The inspectors determined that the finding included an aspect in the Work Control component of the Human Performance cross-cutting area. Specifically, the licensee did not address the impact of changes made to work activities on plant performance, (H.3(b)).

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a Finding (FIN)

(FIN 05000315-2013004-03, Improper Setting in Digital Control System). The licensee entered this condition into the CAP as AR 2013-7472.

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled outage that began on July 28, 2013, when operators manually tripped Unit 2 reactor in response to lowering steam generator water levels resulting from a feedwater transient. After investigating the cause for the turbine trip and implementing corrective actions, Unit 2 reactor was started up and the main generator was synchronized to the grid on July 30, 2013, which ended the outage.

The inspectors reviewed activities to ensure that the licensee considered risk while implementing the outage; reviewed the post-trip report; and observed startup activities.

The inspectors also verified problems associated with the outage were entered in the CAP with the appropriate characterization and that appropriate corrective actions were completed. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one other outage sample as defined in IP 71111.20-05.

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) occurred because the licensee failed to program the condensate heater bypass control valve automatic controller with the correct setpoint. Specifically, the licensee programmed the setpoint to 188 psig (vice the correct 240 psig setpoint setting), consequently, the valve failed to open resulting in a loss of a main feedwater pump. Control room operators manually tripped the reactor when steam generator levels approached the low level trip value.

Description:

On July 28, 2013, with Unit 2 operating at approximately full power, the west bypass steam control valve to the right moisture separator reheater, 2 MRV-411, failed closed. This condition created a secondary system transient resulting in low water level in the 4A feedwater heater, which tripped the north heater drain pump. In response to the heater drain pump trip, control room operators reduced load by 25 MW. A second transient occurred about 30 minutes after 2-MRV-411 closed as the 4B feedwater heater level experienced full scale oscillations. The full scale oscillations resulted in low water level in the 4B feedwater heater and resultant south heater drain pump trip. In response, control room operators reduced load an additional 25 MW. Losing both the north and south heater drain pumps resulted in a decrease in main feedwater pump suction pressure and the west main feedwater pump subsequently tripped. A bypass valve designed to prevent the feedwater pump suction loss did not operate as intended.

Losing the west main feedwater pump caused a decrease in all four steam generator water levels to within a few percent of the automatic reactor trip setpoint and the control room operators preemptively manually tripped the reactor. The licensee entered this condition into their corrective action program as AR 2013-10851 and performed a root cause evaluation.

The inspectors noted that the root cause evaluation determined the most significant contributing condition leading to the trip was condensate heater bypass control valve, 2-CRV-224, failing to open. If the valve had opened as designed, bypass around the low pressure heaters would have alleviated the low suction pressure to the main feedwater pumps during the feedwater heater level oscillation transient. Specifically, 2-CRV-224 was designed to open and reduce differential pressure across the low pressure heaters to recover suction pressure to the main feedwater pump. If the system operated as designed, the west main feedwater pump would not have tripped. Subsequently, licensee personnel determined that the 2-CRV-224 automatic controller (2-RU-2)setpoint was not at the required 240 psig. Instead, a setpoint of 188 psig was programmed into the automatic controller as per 2-OHP-4021-001-006, Power Escalation, Revision 47. Licensee investigation determined that the procedure writer for the power escalation procedure based the 188 psig set point on an incorrect interpretation of information in SD-ENG-05400, System Description Condensate System, Revision 1. Consequently, 2-CRV-224 did not open as designed to mitigate the lowering main feedwater pump suction pressure, which resulted in the loss of the west main feedwater pump and subsequent manual reactor trip.

For corrective actions, the licensee programmed the correct setpoint into the automatic controller for 2-CRV-224; revised associated procedures to ensure setpoint changes are accurately incorporated and reviewed prior to implementation; and developed plans to communicate lessons learned to the site.

Analysis:

The inspectors determined that the licensees failure to set the automatic controller for bypass control valve 2-CRV-224 at the correct setpoint was a performance deficiency that warranted a significance determination. Using IMC 0612, Appendix B, Issue Screening, issued September 7, 2012, the inspectors concluded that traditional enforcement did not apply. The inspectors determined that this issue was more than minor because it was associated with the design control attribute in the Initiating Events cornerstone; and that the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations was adversely affected. Specifically, failure to set the 2-CRV-224 automatic controller to the design setpoint of 240 psig resulted in the subsequent loss of the west main feedwater pump during a feedwater heater level transient causing steam generator water levels to lower requiring operators to manual trip the reactor.

Because the finding was associated with an initiating event at power, the inspectors assessed the finding using IMC 0609, Appendix A, The Significance Determination Process For Findings at Power, Exhibit 1, Initiating Events Screening Questions, issued June 19, 2012. The inspectors concluded that the finding was of very low safety significance (Green) because the finding did not cause both a reactor trip and a loss of mitigating equipment. The inspectors concluded that this finding was associated with an aspect in the Resources Component of the Human Performance cross-cutting area.

Specifically, the procedure used to program the 2-CRV-224 automatic controller was not accurate in that it did not contain the correct design setpoint, (H.2 (c)).

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a Finding (FIN),

(FIN 05000316-2013004-04, Reactor Trip Due to Improper Control Valve Setpoint).

The licensee has entered this condition into the CAP as AR 2013-10851.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• 1-OHP-4030-112-015, Full Length Control Rod Operability Test (Routine); and

• 1-OHP-4030-102-016, Reactor Coolant System Leak Rate Test, (RCS).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• acceptance criteria were clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one routine surveillance testing sample and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on August 27, 2013 which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator 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 the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

.2 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on July 24, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator control room and the emergency offsite facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation (71124.08) This inspection constituted one complete sample as defined in IP 71124.08-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the UFSAR, the Process Control Program (PCP), and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

The inspectors reviewed the scope of any quality assurance audits in this area since the last inspection to gain insights into the licensees performance and inform the smart sampling inspection planning.

b. Findings

No findings were identified.

.2 Radioactive Material Storage (02.02)

a. Inspection Scope

The inspectors selected areas where containers of radioactive waste are stored and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements, as appropriate.

The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection against Radiation. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage, as appropriate.

The inspectors evaluated whether the licensee established a process for monitoring the impact of long term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.

The inspectors selected containers of stored radioactive material and assessed for signs of swelling, leakage, and deformation.

b. Findings

No findings were identified.

.3 Radioactive Waste System Walkdown (02.03)

a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the UFSAR, Offsite Dose Calculation Manual (ODCM), and PCP.

The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment, which is not in service or abandoned in place, would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.

The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.

The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate and to assess the impact on radiation doses to members of the public.

The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the PCP, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.

For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.

The inspectors assessed whether the licensees PCP correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).

b. Findings

No findings were identified.

.4 Waste Characterization and Classification (02.04)

a. Inspection Scope

The inspectors selected the following radioactive waste streams for review:

• Dry Active Waste;

• Primary Filters; and

• Depleted Resins For the waste streams listed above, the inspectors assessed whether the licensees radiochemical sample analysis results (i.e., 10 CFR Part 61" analysis) were sufficient to support radioactive waste characterization as required by 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste. The inspectors evaluated whether the licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analysis for the selected radioactive waste streams.

The inspectors evaluated whether changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and

(2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.

The inspectors evaluated whether the licensee had established and maintained an adequate quality assurance program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56, Waste Characteristics.

b. Findings

No findings were identified.

.5 Shipment Preparation (02.05)

a. Inspection Scope

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors current approved procedures.

Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

b. Findings

No findings were identified.

.6 Shipping Records (02.06)

a. Inspection Scope

The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:

• Shipment Number DCC12-062; Radioactive Material SCO-II, Contaminated Equipment; April 12, 2012;

• Shipment Number DCC12-108; Radioactive Material LSA-II Resin High Integrity Container; October 9, 2012; and

• Shipment Number DCC13-053; Radioactive Material Type A Shipment; May 20, 2013 Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.

b. Findings

No findings were identified.

.7 Identification and Resolution of Problems (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation, were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the licensees Corrective Action Program. Additionally, the inspectors evaluated whether the corrective actions were appropriate for a select sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation.

The inspectors reviewed results of select audits performed since the last inspection of this program and evaluated the adequacy of the licensees corrective actions for issues identified during those audits.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System (MS06) performance indicator (PI) for D. C. Cook Unit 1 and Unit 2 for the period from the 2nd quarter 2012 through the 2nd quarter 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period of April 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted two MSPI emergency AC power system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection Systems (MS07) PI for D. C. Cook Unit 1 and Unit 2 for the period from the 2nd quarter 2012 through the 2nd quarter 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of April 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI high pressure injection system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal System (MS08) PI for D.C. Cook Units 1 and 2 for the period from the second quarter 2011 through the second quarter 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, MSPI derivation reports, and NRC Integrated Inspection Reports for the period of the second quarter 2011 through the second quarter 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted two MSPI heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal System (MS09) PI for D.C. Cook Units 1 and 2 for the period from the second quarter 2011 through the second quarter 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of the second quarter 2011 through the second quarter 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted two MSPI residual heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems (MS10) PI for D.C. Cook Units 1 and 2 for the period from the second quarter 2011 through the second quarter 2013. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of the second quarter 2011 through the second quarter 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted two MSPI cooling water system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for followup, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Selected Issue Followup Inspection: Vacuum Fill During Unit 1 Refueling Outage 25

a. Inspection Scope

During the Unit 1 refueling outage, the inspectors noted numerous issues associated with the evolution that resulted in additional time spent in mid-loop conditions and five unscheduled entries into mid loop prior to successfully complete the evolution. The inspectors also recognized that the vacuum fill on Unit 2 during its refueling outage required multiple entries and included a loss of level indication. Following the Unit 1 outage, the licensee performed a root cause analysis to understand the factors that complicated the vacuum fill evolution.

The licensee identified the issue as a result of problems associated with the RCS level monitoring instrumentation. In the root cause, the licensee included a monitor failure during refueling outage U1C24 as part the root cause. This failure occurred well in advance of the vacuum fill evolution and had negligible safety implications.

During refueling outage U2C20, the licensee started the drain down to vacuum fill at 1500 on April 18, 2012. At 1519, the camera for level indicator NGG-100, which monitors the site glass, failed. The licensee replaced the camera and recommenced the drain down at 1906. At 2010, operations noted level anomalies with level indicator NLI-122 and broke vacuum established in the RCS. The licensee could not readily determine the cause for the anomalies. The licensee determined that level indicator NLI-112 was a suitable substitute for NLI-122 and made procedural changes to allow the use of NLI-112. On April 19, at 1636, the licensee restarted the evolution. At 22 inches of vacuum, level anomalies occurred on both NLI-112 and 122. The licensee decided to continue the evolution while monitoring RCS level on multiple indications. The licensee successfully completed the evolution. The apparent cause evaluation performed by the licensee concluded that the length of instrument tubing runs caused the level anomalies.

During refueling outage U1C25, the licensee commenced an RCS vacuum fill at 1238 on May 7, 2013. The licensee began drawing vacuum at 1550. As vacuum increased, the licensee noted that level indicator NLI-1000 was drifting high while level indicators NLI-122 and NLI-132 drifted low. Because of the anomalies, the licensee broke RCS vacuum. At 1815, the licensee again attempted to draw vacuum. Similar anomalies occurred and the licensee broke vacuum at 1945. Maintenance personnel tightened fittings associated with the vacuum fill equipment in order to correct any potential vacuum leaks. The licensee started a third attempt at vacuum fill on May 8, 2013, at 0220. Operations broke RCS vacuum at 0303 due to level deltas between instruments. Trouble shooting by maintenance identified a loose connection internal to the box for level indicator NLI-122A. The licensee replaced the transducer and commenced drain down at 1837. During this attempt, at 1947, NLI-1000 and NLI-122 exceeded the maximum level deviation and the licensee refilled the RCS to above the reduced inventory level. In consultation with the vendor, the licensee performed a zero adjustment to bring the level indications into agreement. After the adjustment, the licensee performed the drain down and vacuum fill evolution successfully.

The licensee used commonalty review, event and causal factor charts, and barrier analysis to determine the root cause. The licensee concluded that the root cause of the issues with vacuum fill was lack of station ownership of the instrumentation associated with vacuum fill. Based on review of the root cause, the inspectors concluded that the licensee used a structured process to determine the root cause. In support of this conclusion, the licensee noted that condensation in one of the transducers, loose fittings in another and a broken wiring harness all pointed to mishandling of the equipment.

As contributing causes, the licensee noted the following:

• poor station understanding of the sensitivity of the transducers; and

• acceptance of minor level deviations during stable RCS conditions Corrective actions included:

• a plan to take ownership of calibration and preventive maintenance of the transducers;

• establishing a troubleshooting guide for the transducers; and

• obtain transport cases for the transducers This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Introduction:

The inspectors identified an Unresolved Item (URI) regarding the requirements pertaining to establishing and maintaining procedures to ensure reliable indication of reactor vessel level during reduced RCS inventory and vacuum fill operations.

Discussion: During the recent refueling outages, the licensee experienced numerous issues monitoring the RCS water level during the vacuum fill activities. Each of the issues described below resulted in additional entries into RCS mid-loop operations with an associated increase in plant risk during each entry. Specific issues include:

• During Unit 2 refueling outage 20, the licensee made three vacuum fill attempts.

The licensee terminated the first attempt due to a failed camera. The licensee terminated the second attempt due to level variations on NLI-122. The third attempt succeeded.

• During the Unit 1 refueling outage 25, the licensee made five attempts to vacuum fill the RCS before succeeding:

o Attempt 1: A divergence between RCS level indications caused the licensee to terminate the evolution; o Attempt 2: Licensee terminated the vacuum fill attempt due to similar level indication issues observed in Attempt 1; o Attempt 3: Licensee checked level instrumentation fittings for tightness and then made a drain down attempt; instrument deltas again resulted in terminating the attempt; o Attempt 4: The licensee found a leak in a level instrument transducer box; the licensee replaced the transducer and tightened the fittings; the licensee terminated the attempt due to deviations between level indications; Attempt 5: The licensee performed a zero adjust on the level indications instruments; the attempt succeeded.

The licensee performed a root cause analysis on the vacuum fill attempts described above and determined the root cause to be that the site did not have ownership of the level indicators. Based on review of the root cause analysis and observation of the licensees performance during the vacuum fill evolution, the inspectors concluded that the licensee identified the root cause. The inspectors also noted that the root cause analysis included several examples where procedures were not appropriate to the circumstances. For example, procedures did not:

• provide direction for a vacuum leak test;

• provide detailed direction calibration/protection of transducers from shock, or;

• include requirements to normalize readings between level indications.

The inspectors noted that including the above items into procedures would have reduced the time the licensee spent in a mid-loop condition as well as the number of drain downs needed to complete the RCS vacuum fills. At the conclusion of this inspection, the inspectors had not completed their review to determine if a performance deficiency or violations of regulatory requirements occurred. The URI will remain open pending this review. (URI 05000315/316/2013004-05, Unreliable Level Indications)

.4 Selected Issues for Followup: Inadvertent Operation of Plant Equipment

a. Inspection Scope

The Inspectors reviewed the root cause analysis for inadvertent operation of a breaker for an auxiliary feedwater system motor operated valve and the root cause performed to evaluate the inadvertent operation of a relay that resulted in loss of a qualified circuit to both Units. In the root cause for auxiliary feed, the licensee concluded that implementation of a procedure PMP-4043-SCA-001, Status Control Areas, had ineffective change management. The licensee specifically noted that the status control area near the switchgear containing the breaker for 1-FMO-212, Unit 1 West Motor Driven Auxiliary Feedwater Pump to Steam Generator Number 1, did not have markings in the area where scaffold was erected. In addition, workers on the scaffold assembly were not familiar with differences between keep clear areas and status control areas.

This confusion contributed to placing a ladder within the status control area for the switchgear. The licensee used barrier analysis, event and causal factor analysis and a why stair case to analyze this event. The inspectors concluded the licensee used a formal process for the root cause analysis.

For the inadvertent loss of the qualified circuit, the licensee evaluated the condition using common cause analysis that also assessed a condition where licensee personnel cut into an incorrect section of pipe that was outside of a clearance boundary. The licensee concluded that these events were caused by station personnel not recognizing hazards due to behaviors not being reinforced. The licensee used event and causal factor charts, barrier analysis and the why staircase for the common cause.

The inspectors noted all three events share common causes in that they all involved poor implementation of procedures, lack of hazard recognition and lack of reinforcement of behaviors to recognize and mitigate hazards.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05

b. Findings

Introduction:

A self-revealed finding of very low safety significance and associated NCV of TS 5.4.1 occurred because the licensee failed to implement procedures for equipment control. Specifically, plant workers caused two unplanned LCO entries due to equipment being inadvertently operated because equipment control procedures were inadequately implemented.

Discussion: On June 10, 2013, and on August 1, 2013, workers rendered TS required equipment inoperable by inadvertent contact with switchgear. In both instances, workers failed to implement requirements of site procedures that govern risk and status control.

On June 10, 2013, Unit 1 control room operators noted that the open indication for motor operated control valve 1-FMO-212 was not illuminated. Operations investigated the condition and discovered that the breaker for 1-FMO-212 was open, which rendered 1-FMO-212 inoperable and the appropriate TS LCO was entered for approximately 14 minutes until the breaker was reclosed. The licensee determined that a scaffold built in front of the switchgear created a condition where workers would be in close the proximity to the breaker and led to an inadvertent operation of the breaker. While scaffold construction was in progress on June 10, 2013, none of the scaffold workers recalled contacting the breaker. The root cause evaluation conducted by the licensee concluded that the event occurred due to ineffective change management when the licensee created PMP-4043-SCP-001, Status Control Program. Specifically, the status control areas were not all painted in accordance with the procedure and some workers were not aware of the procedure requirements.

On August 1, 2013, while pulling cable in the 345KV switch house, a worker inadvertently contacted a trip push button on a relay that caused loss of train B reserve feed to both units. This inadvertent equipment operation occurred when a worker was climbing a ladder and relying on situational awareness to avoid contact with plant equipment. When reserve feed was lost, both units entered the appropriate TS LCO, which was exited approximately 30 minutes later when the reserve feed circuit was restored. The worker that contacted the trip push button notified plant personnel. The licensees root cause concluded that personnel not recognizing hazards was the most significant factor. This switchyard work occurred under PMP-3100-IOA-001, Inter-Organizational Agreement Between the American Electric Power Transmission and the American Electric Power Nuclear Generation Group for Assistance to Cook Nuclear Plant. This document specifies that procedure PMP-2291-WAR-001, Work Management Process Flow Chart, will be used for work in the switchyard. Procedure PMP-2291-WAR-001 required the licensee to identify work that involves relay work without assurance to prevent inadvertent relay actuation as high risk. In this case, the license failed to recognize that this work, on a ladder, should be considered high risk work due to the proximity of the relays.

In both instances, the licensee failed to implement the requirements to control and minimize risk of inadvertently operating plant equipment. For the event in the switch house, although the actions impacted TS required equipment, the activity occurred outside the bounds of safety-related equipment and does not represent a non-compliance of 10 CFR Part 50, Appendix B, regulatory requirements.

For corrective actions, in both cases, the licensee restored the equipment to an operable status and communicated the errors to site personnel to improve worker situational awareness.

Analysis:

The inspectors concluded that the inadvertent operation of plant equipment rendering the equipment inoperable was a performance deficiency that warranted a significance evaluation. In accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued September 7, 2012, the inspectors concluded that traditional enforcement did not apply; and that the issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective of ensuring the reliability of systems that respond to initiating events. Specifically, the issues resulted in inoperable equipment. Because the finding was associated with a mitigating system at power, the inspectors assessed the finding using IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings at Power, issued June 19, 2012. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the inspectors determined the finding was of very low safety significance (Green)because all the screening questions were answered no.

The inspectors concluded that the finding was associated with an aspect in the Work Control component of the Human Performance cross cutting area because the licensee failed to appropriately plan work using risk insights, (H.3(a)).

Enforcement:

Technical Specification Section 5.4.1 states, in part, that 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, Appendix A, Section 1, Administrative Procedures, addresses equipment control under item c. Procedure PMP-4043-SCP-001, Status Control Program, Step 2, defines a status control area as the area surrounding a positional component that extends outward in all directions from the component for 2 feet. Step 3.2.1 requires that all high and medium status control areas will be designated by paint stenciled with Status Control Area.

Contrary to the above, on June 10, 2013, the designated status control area at motor control center 1-AVZ-A, which contained the breaker for auxiliary feedwater motor operated valve 1-FMO-212, extended only 4 inches to the east. The licensee determined that workers were unaware of the status control area and the lack of awareness led to the inadvertent actuation of the breaker. Consequently, valve 1-FMO-212 was rendered inoperable. For corrective actions, the breaker was immediately reclosed, which restored the valve to an operable status and this issue was communicated to site personnel to improve worker situational awareness. The licensee has entered this condition into the CAP as AR 2013-6243. Because this violation was of very low safety significance and it was entered into the CAP this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000316/2013004-06; Inadvertent Operation of Plant Equipment).

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Withdrawal of Licensee Event Report 05000315/2012-002-00: Unit 1 Exceeded

Technical Specification Allowed Outage Time This Licensee Event Report (LER) was discussed in NRC Inspection Report 05000315/2013003; 05000316/2013003, Section 4OA3.3. The inspectors did not identify any issues of significance in the LER. However, because the licensee withdrew the LER on July 25, 2013, the LER was kept open pending review of the licensees retraction.

The inspectors reviewed the licensees cause evaluation in AR 2013-3730, which formed the basis for retracting the LER. The evaluation clarified the separation between the engineered safety feature actuation system instrumentation (TS 3.3.2) function and the steam generator dump valves (TS 3.7.2) component function necessary to close the steam generator stop valves (SGSV). This separation was not fully understood during the event, which resulted in the incorrect LCO being entered. The incorrect LCO was more time restrictive and resulted in the LER being generated.

Specifically, after the two fuses for the Unit 1 steam generator stop valve dump valves blew, the valves would not open as required to close the associated SGSV. During the event, the licensee determined that the blown fuses rendered one train of engineered safety feature actuation system instrumentation inoperable and the licensee entered LCO 3.3.2, Condition C, which required the train of actuation circuitry to be restored to operable within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. However, the licensees evaluation subsequently identified that the actuation circuitry was not affected by the blown fuses and therefore LCO 3.3.2 was not applicable. Instead, LCO 3.0.3 would be applicable because the fuse failures resulted in two SGSVs being inoperable, which required initiating actions within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the plant in Mode 3 (Hot Standby) within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. After the licensee returned one SGSV to operable, LCO 3.0.3 could be exited and LCO 3.7.2, Condition A, would be applicable for one inoperable SGSV. Condition A of LCO 3.7.2 required the inoperable SGSV to be returned to operable within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. If Condition A could not be met then LCO 3.7.2 Condition B would be entered, which required the plant to be placed in Mode 2 (Startup) within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Because the SGSVs were returned to service before the allowed outage times specified in LCO 3.7.2 expired, there would not have been a violation of TS as was initially reported in the LER. Consequently, the LER was not necessary and could be withdrawn.

The inspectors did not identify any issues of concern regarding the licensees evaluation and basis for withdrawing LER 05000315/2012-002-00. The inspectors also concluded that based on the information available during the event, the licensees decision to enter LCO 3.3.2 instead of LCO 3.0.3 and then LCO 3.7.2, while incorrect, would not have delayed a required plant shutdown for inoperable equipment. Therefore the incorrect LCO entry was determined to be an issue of minor significance. For corrective actions, the licensee planned to review and revise the applicable TS bases to include a discussion on what constitutes the engineered safety features actuation system instrumentation boundary, which would highlight the components that would be applicable to LCO 3.3.2.

Based on being withdrawn, LER 05000315/2012-002-00 is closed.

This event followup constituted one sample as defined in IP 71153-05.

.2 Unit 2 Manual Reactor Trip

a. Inspection Scope

The inspectors reviewed control room operator response to a secondary feedwater transient and manual reactor trip on July 28, 2013. The inspectors verified that control room operators responded in accordance with plant procedures; walked down control panels to verify that plant equipment responded as designed; and verified that the event was accurately described and that the NRC was notified in a timely manner. The inspectors also reviewed action requests to verify that identified problems pertaining to the trip were entered into the CAP with the appropriate significance characterization.

Documents reviewed in this inspection are listed in the Attachment.

This event followup review constituted one sample as defined in IP 71153-05. One Finding was identified and was documented in section 1R20.

b. Findings

No additional findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 8, 2013, the inspectors presented the inspection results to Mr. J. Gebbie and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits conducted:

• The inspection results for the area of radioactive solid waste processing and radioactive material handling, storage, and transportation were discussed with Mr. J. Gebbie, Site Vice President, on July 19, 2013.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as NCVs.

.1 Failure to Ensure that Sprinkler System Piping Could be Drained

The licensee identified a finding of very low safety significance (Green) and associated NCV of License Condition 2.C(4) for Unit 1 and 2.C(3)(o) for Unit 2 through a planned work order for the failure to implement and maintain in effect all provisions of their approved fire protection program. Specifically, the installation of the pre-action sprinkler system on the 587-foot, 609-foot, and 633-foot elevations of the auxiliary building did not comply with National Fire Protection Association Standard 13, Standard for the Installation of Sprinkler System, (1971) section 3211 and (1983) section 3-11.1.1, both of which require that all sprinkler pipe and fittings shall be so installed that the system may be drained. This resulted in the plugging of portions of the pre-action sprinkler system, which could have resulted in portions of the system being non-functional during a fire.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors (fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The Region III Senior Risk Analyst used the risk assessment tools of IMC 0609, Appendix F, Fire Protection SDP, and performed bounding analyses using the DC Cook SPAR model, Version 8.22 and Systems Analysis Programs for Hands-on Integrated Reliability Evaluations version 8.0.9.0 software. The finding was determined to be of very low safety significance (Green) because the risk increase using bounding assumptions was below 1E-6 per year. The licensee entered this issue into their CAP as AR 2013-7845, Fire Protection Piping Plugged, dated May 28, 2013, and restored the functionality of the sprinkler system by flushing the affected piping and replacing piping and sprinkler heads as required. The licensee planned on evaluating additional corrective actions to reduce the amount of corrosion in the pre-action sprinkler system.

.2 Untimely Prompt NRC Notifications

Contrary to 10 CFR 50.72(b)(2)(xi) requirements to report, within four hours, any event related to the health and safety of the public for which notification to other government agencies has been made, on April 19, the licensee failed to make the required notification within the four hour requirement. At 2350 on April 18, 2013, the Berrien County 911 Dispatcher notified the licensee that an emergency siren in the nearby Warren Dunes State Park was alarming. Four local citizens had called the dispatcher regarding the siren. The licensee confirmed that the siren should not be activated and took action to silence the siren. Initially, the licensee concluded that the siren actuation was not reportable because the site did not plan to issues a press release and believed the single siren would have minimal impact to the local population. The following day, the licensee reviewed the circumstances surrounding the siren and concluded that 10 CFR 50.72(b)(2)(xi) applied and a four hour report should have been made.

NUREG-1022 includes as an example that an Emergency Notification System notification is needed if county governments are informed of an actuation by concerned members of the public. The licensee made the notification at 1230 on April 19, 2013.

The inspectors concluded that the failure to make the required four hour notification was a performance deficiency. Because the violation impacted the regulatory process, in that the licensee failed to make a required report on time, the inspectors assessed the performance deficiency using traditional enforcement. The inspectors concluded that the finding was a Severity Level IV violation in accordance with the Enforcement Policy, which includes a failure to make a report required by 10 CFR 50.72 as an example of a SL IV violation. The licensee entered the condition into the CAP as AR 2013-5949.

Corrective actions included clarifications to licensee procedures to prevent similar occurrences. On September 19, a similar event occurred and the licensee made the report on time. Because the licensee self-identified the condition, entered the condition in the corrective action program and took action to address the causes, the inspectors concluded that the issue could be addressed as a licensee identified non-cited violation.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Hite, Radiation Protection Manager

K. Housh, System Engineer

J. Long, Environmental Specialist

R. Pletz, Design Engineering Fire Protection Specialist

Nuclear Regulatory Commission

T. Wengert, Project Manager

N. Valos, Senior Risk Analyst

L. Kozak, Senior Risk Analyst

LIST OF ITEMS

Opened

05000316/2013004-01 NCV Unit 2 Steam Generator #1 Stop Valve Dump Valve 2-MRV-

2 Stroke Time Failure due to Operation of Dump Valve Outside its Packing Design (1R12)

05000315/2013004-02 FIN Faulted 4KV Qualified Off-site Circuit (1R15)

05000316/2013004-02

05000315/2013004-03 FIN Improper Setting in Digital Control System (1R20.1)

05000316/2013004-04 FIN Reactor Trip Due to Improper Control Valve Setpoint (1R20.2)

05000315/2013004-05 URI Unreliable Level Indications (4OA2.3)

05000316/2013004-05

05000316/2013004-06 NCV Inadvertent Operation of Plant Equipment (4OA2.4)

Closed

05000316/2013004-01 NCV Unit 2 Steam Generator #1 Stop Valve Dump Valve 2-MRV-

2 Stroke Time Failure due to Operation of Dump Valve Outside its Packing Design (1R12)

05000315/2013004-02 FIN Faulted 4KV Qualified Off-site Circuit (1R15)

05000316/2013004-02

05000315/2013004-03 FIN Improper Setting in Digital Control System (1R20.1)

05000316/2013004-04 FIN Reactor Trip Due to Improper Control Valve Setpoint (1R20.2)

05000316/2013004-05 NCV Inadvertent Operation of Plant Equipment (4OA2.4)

Attachment

05000315/2012-002-00 LER Unit 1 Exceeded Technical Specification Time Limit to Shutdown (4OA3.1)

Discussed

None Attachment