IR 05000440/2014002

IR 05000440-14-002, 01/01/2014 - 03/31/2014, Perry, Unit 1, Integrated Inspection

ML14132A192
Person / Time
Site:	Perry
Issue date:	05/12/2014
From:	NRC/RGN-III/DRP/B5
To:	Harkness E FirstEnergy Nuclear Operating Co
References
IR-14-002
Download: ML14132A192 (35)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE RD. SUITE 210 LISLE, IL 60532-4352 May 12, 2014

Mr. Ernest Harkness Site Vice President FirstEnergy Nuclear Operating Company Perry Nuclear Power Plant P. O. Box 97, 10 Center Road, A-PY-A290 Perry, OH 44081-0097

SUBJECT: PERRY NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000440/2014002

Dear Mr. Harkness:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Perry Nuclear Power Plant. On April 8, the NRC inspectors discuss ed the results of this inspection with you and members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report. The NRC inspectors documented 2 findings of very low safety significance (Green) in this report. These findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs), consistent with Section 2.3.2.a of the Enforcement Policy. Further, the inspectors documented a licensee-identified violation that was determined to be of very low safety significance. The NRC is treating this violation as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. If you contest the violations or significance 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 copy to the Regional Administrator; the Director, Office of Enforcement, U.S. Nuclear

Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector. 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 Resident Inspector at the Perry Nuclear Power Plant. Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last 6 months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III and the NRC Resident Inspector at the Perry Nuclear Power

Plant.

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

Michael Kunowski, Chief Branch 5 Division of Reactor Projects Docket No. 50-440 License No. NPF-58

Enclosure:

Inspection Report 05000440/2014002

w/Attachment:

Supplemental Information cc w/encl: Distribution via LISTSERV

Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION III Docket No: 50-440 License No: NPF-58 Report No: 05000440/2014002 Licensee: FirstEnergy Nuclear Operating Company (FENOC) Facility: Perry Nuclear Power Plant, Unit 1 Location: North Perry, Ohio Dates: January 1, 2014, through March 31, 2014 Inspectors: M. Marshfield, Senior Resident Inspector J. Nance, Resident Inspector T. Bilik, Senior Reactor Inspector

Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects

SUMMARY OF FINDINGS

Inspection Report (IR) 05000440/2014002, 01/01/2014 - 03/31/2014, Perry Nuclear Power Plant; Adverse Weather Protection; Fire Protection This report covers a 3-month period of inspection by resident and regional inspectors. One Green finding was identified by the inspectors and one finding was self-revealing. The findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross-Cutting Areas," effective January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy dated July 9, 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.

A. NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A self-revealed finding of very low safety significance (Green) and associated non-cited violation of Technical Specification 5.4.1.a was identified for the licensee's failure to maintain adequate procedures to respond to acts of nature as required by Regulatory Guide 1.33, "Quality Assurance Program Requirements." Specifically, the cold weather procedure did not adequately direct equipment walkdowns and subsequent actions to protect equipment important to sa fety from severe weather risks, directly resulting in freezing and breaking of fire protection piping in Unit 2 turbine power complex, elevation 593' level. The piping provides fire protection for Unit 2 startup transformer's deluge system and the three Unit 2 inter-bus transformer deluge systems.

The Unit 2 startup transformer is an integral part of one of the two qualified circuits specified in Technical Specification 3.8.1 between the offsite electrical transmission network and the onsite 4160-volt safety-related electrical system. Corrective actions included immediate posting of compensatory actions and warming of the space to prevent further damage to the system until repairs were completed.

The finding was determined to be more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the procedure did not direct the licensee to take proactive steps to limit the likelihood of extreme cold weather freezing and breaking the fire protection piping located on the Unit 2 turbine power complex elevation 593' level. In Step 1.2 of Inspection Manual Chapter 0609, Appendix F, Attachment 1, "Category of Fire Inspection Finding," the inspectors assigned Category 1.4.2, "Fixed Fire Protection Systems," to the finding and by answering "yes" in Step 1.3 A, "Is the reactor able to reach and maintain safe shutdown (either hot or cold) condition?" the inspectors determined that the finding was of very low safety significance. The finding was determined to have a cross-cutting aspect in the area of human performance, avoid complacency, where individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee did not identify that the fire protection deluge valves and piping in the Unit 2 turbine power complex were subject to freezing, even though extreme cold conditions had existed in prior weeks, allowing the licensee ample time for additional walkdowns to ensure that the plant was ready for the extreme cold weather event the first week of January 2014 (H.12). (Section 1R01)

Green.

The inspectors identified a finding of very low safety significance (Green) and associated non-cited violation of Perry Operating License Condition 2.C(6) for failure to establish a required 3-hour fire barrier as required by design. Specifically, on March 13, 2014, the inspectors identified four incomplete fire barrier seals in ceiling-level penetrations between the Division 1 and Division 2 battery rooms and the adjoining direct current (DC) switchgear rooms, and on March 14 identified the lack of a fire barrier seal in a ceiling-level penetration between the remote shutdown panel room and an adjoining alternating current (AC) switchgear room. The licensee implemented compensatory measures that included hourly fire watches and entered the issues into the corrective action program.

The finding was determined to be more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the lack of a barrier caused the required 3-hour barrier required by design to be non-functional. In Step 1.2 of Inspection Manual Chapter 0609, Appendix F, Attachment 1, "Category of Fire Inspection Finding," the inspectors assigned Category 1.4.3, "Fire Confinement," to the finding, which was determined to be of very low safety significance. For the battery room seals, the inspectors identified a cross-cutting aspect in the area of human performance, work management, where the organization implements a process for planning and controlling, and executing work activities such that nuclear safety is the overriding priority (H.5). Specifically, the licensee did not follow its procedures when the fire seal material was formed in the workshop and then installed in the openings instead of being formed in situ as required by the licensee's procedures (H.5). The inspectors determined there was no cross-cutting aspect associated with the lack of a fire seal in the remote shutdown panel room because it did not reflect current performance. (Section 1R05)

B. Licensee-Identified Violation

• A violation of very low safety significance was identified by the licensee and has been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program (CAP). This violation and corrective action tracking number are listed in Section 4OA7 of this report.

4

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period at 100 percent power. On February 7, 2014, at 6:00 a.m., the Perry Nuclear Power Plant began to lower power for a required Technical Specification (TS) Limiting Condition for Operation (LCO) Action Statement shutdown. At 9:43 a.m., the licensee exited the TS LCO Action Statement and commenced raising power.

The plant returned to 100 percent power at 10:53 p.m. With the exception of minor reductions in power to support routine surveillances and rod pattern adjustments, the plant remained at full power for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Extreme Cold Conditions

a. Inspection Scope

Since extreme cold conditions were forecast in the vicinity of the facility for January 6-7, 2014, the inspectors reviewed the licensee's overall preparations/protection for the expected weather conditions. On January 3 and 6, the inspectors walked down the balance of plant inverter and nearby exterior roll-up doors and interior doors that could cause unplanned plant transients, including reactor scrams, by allowing extremely cold air to negatively affect the performance of electrical components that provide power to nonsafety-related systems, such as the digital feed water control system. In the recent past, safety-related systems have been challenged after the digital feedwater control system's uninterruptable power supply was adversely affected by extreme cold conditions. The inspectors observed insulation, heat trace circuits, space heater operation, and weatherized enclosures to ensure operability of affected systems. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors focused on plant management's actions for implementing the station's procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

Inadequate Procedure for Extreme Cold Weather

Introduction:

A self-revealed finding of very low safety significance (Green) and associated NCV of TS 5.4.1, "Procedures," was identified when the licensee did not maintain adequate procedures to respond proactively to acts of nature. Specifically, the cold weather procedure did not adequately direct equipment walkdowns and subsequent actions to protect equipment important to sa fety from severe weather risks, directly resulting in freezing and breaking of fire protection piping in Unit 2 turbine power complex, elevation 593' level.

Description:

On January 8, 2014, at 5:20 p.m., a plant operator discovered damage to the fire protection pipe couplings in the Unit 2 turbine power complex, elevation 593' level, which had been caused by extreme cold weather. The damage was located because pressure indications to each downstream transformer were much higher than normal fire main pressure. Specifically, LH-2-B (one of three Unit 2 inter-bus transformers) transformer deluge pipe pressure was the highest at 300 pounds per square inch gauge (psig). Water in the fire protection piping had frozen and broken several fittings, causing water to leak out of the piping onto the floor and surrounding equipment. The leaking water was quickly isolated by the operators closing the upstream isolation valve which then isolated the deluge systems for the Unit 2 startup transformer and for all three Unit 2 inter-bus transformers. The Unit 2 startup transformer is an integral part of one of the two qualified circuits specified by Technical Specification (TS) 3.8.1 between the offsite electrical transmission network and onsite safety-related 4160-V system. The licensee entered this issue into the corrective action program (CAP) as Condition Report (CR) 2014-00309. The inspectors determined that the failure to have adequate procedures to respond proactively to acts of nature was a performance deficiency. Specifically, the inadequate procedure did not direct the licensee to take proactive steps to prevent the extreme cold weather from freezing the water in Unit 2 fire protection piping systems, and breaking fire protection piping couplings in the transformer deluge piping for the Unit 2 startup transformer and Unit 2 inter-bus transformers.

Analysis:

The inspectors determined that the licensee's failure to prevent the deluge piping in Unit 2 turbine power complex from freezing and breaking was a performance deficiency that warranted further evaluation. Using the guidance in IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the procedure did not have steps to prevent extreme cold weather freezing and breaking of fire protection piping located in Unit 2 turbine power complex elevation 593' level. Using Table 3 of Attachment 4 of IMC 0609, "The SDP for Findings at Power," dated June 19, 2012, the inspectors answered "yes" to the Fire Protection question, "Does the finding involve:

(2) Fixed fire protection systems?" By answering "yes," the inspectors were directed to evaluate the significance of the finding using IMC 0609, Appendix F, "Fire Protection Significance Determination Process," dated September 20, 2013. In Appendix F, Attachment 1, Step 1.2, "Category of Fire Inspection Finding," the inspectors assigned Category 1.4.2, "Fixed Fire Protection Systems," to the finding. By answering "yes" in Step 1.3 A, "Is the reactor able to reach and maintain safe shutdown (either hot or cold) condition?" the inspectors determined that the finding was of very low

safety significance (Green).

The finding was determined to have a cross-cutting aspect in the area of human performance, avoid complacency, where individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee did not identify that the fire protection deluge valves and piping in the Unit 2 turbine power complex were subject to freezing (H.12). (Section 1R01)

Enforcement:

Technical Specification 5.4.1.a, "Procedures," requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Revision 2, Appendix A. Regulatory Guide 1.33, Appendix A, lists activities that should be covered by written procedures. Section 6 identifies procedures for combating emergencies and other significant events among which is 6.w "Acts of Nature (e.g., tornado, flood, dam failure, earthquakes)." Contrary to the above, prior to January 8, 2014, the licensee did not maintain an adequate procedure to respond to extreme cold weather. Specifically, actions were not taken to prevent frozen, damaged pipes in the fire protection system associated with the Unit 2 startup transformer, an integral component of the offsite power source for the safety-related 4160-V electrical system. Since this issue was entered into the licensee's CAP (as CR 2014-00309), it is being treated as an NCV in accordance with Section 2.3.2.a of the NRC's Enforcement Policy (NCV 05000440/2014002-01, Inadequate Procedure for Extreme Cold Weather).

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• low-pressure core spray system;

• standby liquid control 'B' system;

• annulus exhaust gas system 'A' train; and

• 480 Volt (V) distribution system, Division 1. 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 Safety Analysis Report (USAR), TS requirements, outstanding work orders, CRs, 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 parameter s 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 four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection - Routine Resident Inspector Tours

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:

• Auxiliary Building 574'/568'-level;

• Division 1 Switchgear Room and Division 1 Emergency Diesel Generator (EDG) Room;

• Control Complex 679' level;

• Division 1 and Division 2 Battery Rooms, Control Complex 638' level; and

• Intermediate Building 620' level. 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 licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's CAP. Documents reviewed are listed in the Attachment to this report. These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

(1) Failure to Ensure Required 3-Hour Fire Barriers (Seals) Were In-place

Introduction:

The inspectors identified a finding of very low safety significance (Green) and associated NCV of License Condition 2.C(6) for failure to establish a required 3-hour fire barrier as required by design. Specifically, on March 13, 2014, the inspectors identified four incomplete fire barrier seals in ceiling-level penetrations between the Division 1 and Division 2 battery rooms and the adjoining direct current (DC) switchgear rooms, and on March 14 identified the lack of a fire barrier seal in a ceiling-level penetration between the remote shutdown panel room and an adjoining alternating current (AC) switchgear room.

Description:

On March 13, 2014, the inspectors performed a fire protection walkdown of the Division 1 and Division 2 battery rooms and their respective DC switchgear rooms. The inspectors identified small gaps in two fire seals of ceiling-level piping/conduit penetrations for each battery room. Licensee fire protection personnel subsequently determined that the four penetration seals did not meet the requirements of Fire Protection Instruction, (FPI)-A-I01, "Fire Rated Assemblies and Detector Inspection Guidelines," Revision 2, Section 6.4.3.3.b, which states that, "Seals will not pass light through to the other side or move under hand pressure," and consequently, the seals did not meet the acceptance criterion of a 3-hour fire rating. The licensee implemented compensatory measures that included hourly fire watches.

The licensee generated CR 2014-04886 and its investigation determined that in November 2011 during the performance of Periodic Test Instruction (PTI)-P54-P0054, "Fire Barrier Visual Inspection," Revision 2, for the Division 2 battery room there were several penetration fire seals missing. Work to install the seals was completed on June 17, 2012, and was inspected as satisfactory by the fire marshal on the same date.

However, the fire barrier material used to fill the penetrations in 2012 had been formed in the plant workshop and then installed. This was inconsistent with the licensee's Generic Mechanical Instruction (GMI)-0077, "Installation, Removal, and Repair of Foam Penetration Seals SF-20," which specified that the seal be formed in the penetration, and apparently resulted in improperly formed/incomplete seals.

On March 14, 2014, the inspectors identified what appeared to be the lack of any fire barrier material in a ceiling-level penetration of a wall between the remote shutdown panel room and the Division 1 4160-V and 480-V AC switchgear room. Upon closer examination by licensee fire protection personnel, it was confirmed that there was no fire seal installed in this penetration. The licensee found no record of a previous identification of this seal missing.

Analysis:

The inspectors determined that the failure to provide a 3-hour barrier as specified in the Updated Safety Analysis Report (USAR) and plant drawings was a performance deficiency that warranted further evaluation. Using guidance in IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, the inspectors determined that the issue was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using Table 3 of Attachment 4 of IMC 0609, "The SDP for Findings at Power," dated June 19, 2012, the inspectors answered "yes" to the Fire Protection question, "Does the finding involve:

(2) Fixed fire protection systems or the ability to confine a fire?" By

answering "yes," the inspectors were directed to evaluate the significance using IMC 0609, Appendix F, "Fire Protection Significance Determination Process," dated September 20, 2013. In Appendix F, Attachment 1, Step 1.2, "Category of Fire Inspection Finding," the inspectors assigned Category 1.4.3, "Fire Confinement," to the finding.

For the battery room incomplete seals, the inspectors then answered "yes" to question 1.4.3.D because the DC distribution rooms contained no potential damage targets that were unique from those in the exposing fire areas and determined the issue to be of very low safety significance (Green). For the remote shutdown panel room single missing fire seal, the inspectors answered "no" to question 1.4.3.F, "For a fire inspection finding pertaining to a wall fire barrier deficiency, is there equipment important to safety (i.e., from a different safe shutdown train) within 10 feet horizontally on the other side, or vertically above, in the adjoining compartment, that can be affected by cable fire spreading through an opening in the wall fire barrier (e.g., a cable that pass through multiple fire areas)?" Because 1.4.3.F was answered as a "no," the issue was determined to be of very low safety significance (Green).

For the battery room seals, the inspectors identified a cross-cutting aspect in the area of human performance, work management, where the organization implements a process for planning and controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, the licensee did not follow its procedures when the fire seal material was formed in the workshop and then installed in the openings instead of

being formed in situ as required by the licensee's procedures (H.5). The inspectors determined there was no cross-cutting aspect associated with the lack of a fire seal in the remote shutdown panel room because it did not reflect current performance.

Enforcement:

License condition 2.C(6) requires the licensee to "implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report, as amended, and as approved through Safety Evaluation Report (NUREG-0887) dated May 1982 and supplemental numbers 1 through 10." Section 9A of the USAR describes the approved fire protection program. In Section 9A.4.4.3.1.4 the USAR describes the fire protection for the remote shutdown room and requires in part for the walls, ceiling and floor penetrations, "All penetrations have 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire rated seals." Contrary to the above, the licensee failed to ensure that all penetrations had the required 3-hour fire rated seal in place. Specifically, one penetration between the

remote shutdown panel room and the Division 1 4160-V and 480-V AC switchgear room, two penetrations between the Division 1 battery room and its DC switchgear room, and two penetrations between the Division 2 battery room and its DC switchgear room did not have a 3-hour rated fire seal installed. Because this violation was of very low safety significance and was entered into the licensee's CAP (as CR 2014-05082 and CR 2014-04886) and the licensee initiated compensatory measures for the affected fire areas, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy (NCV 05000440/2014002-02, Failure to Ensure Required 3-Hour Fire Barriers (Seals) Were In-Place).

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On January 27, 2014, the inspectors observed a crew of licensed operators in the plant's 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;

• crew's 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 crew's 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 February 13 and 14, 2014, the inspectors observed licensed operation's personnel preparing for and switching reactor protection system bus 'B' power supply from normal to alternate. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crew's clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

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:

• G41 - Fuel Pool Cooling and Cleanup System and

• C41 - Standby Liquid Control System 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/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

No findings were identified.

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:

• Division 1 EDG Room supply fan 1A temperature controller repair;

• Division 1 EDG lube oil low pressure pneumatic trip system repair;

• Protected equipment and repairs for loss of inter-bus transformer LH-1-B;

• Control Rod Exercise and Stall Flow testing; and

• Diesel Fire Service Pump repair. 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. Documents reviewed are listed in the Attachment to this report. These maintenance risk assessments and emergent work control activities constituted one sample as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• Division 1 EDG thermal couple displacement;

• secondary containment bypass local leak rate test (LLRT) failure;

• continued operation with feedwater heater 6B normal drain closed;

• emergency core cooling system motor-operated valve motors and actuators, environmental qualifications, and operability determinations; and

• loss of power to emergency closed cooling 'B' heat exchanger temperature control valve. The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and USAR to the licensee's evaluations to determine

whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report. This operability inspection constituted five samples as defined in IP 71111.15-05.

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:

• Rosemount master trip unit replacement for control room heating, ventilation, and air-conditioning system;

• Division 1 EDG room supply fan 1A temperature controller repair;

• reactor water cleanup valve repairs;

• local leak rate testing and repairs to containment purge inboard isolation valve;

• repairs and retest of electrical functions on inter-bus transformer LH-1-B; and

• drywell area radiation monitor iodine readout module repair.

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 USAR, 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 six post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

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:

• Surveillance Instruction (SVI)-P45-T2001; Essential Service Water 'A' Pump and Valve (inservice testing);

• SVI-E12-T1182C; Residual Heat Removal 'C' Low-Pressure Core Injection Valve Lineup Verification and System Venting functional testing (routine);

• SVI-E31-T1405C; MSL High Flow Channel 'C' Response Time For 1E31-N686C, 1E31-N687C, 1E31-N688C, and 1E31-N689C (routine);

• SVI-E22-T1200; HPCS Pump Discharge Pressure - High (Bypass) Channel Functional for 1E22-N51 (routine); and

• SVI-B21-T0034D; RPV Level 3 and Level 8 RPS/RHR Shutdown Isolation Channel D Functional for 1B21-N680D (routine). 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 were 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 four routine surveillance testing samples and one inservice testing sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on January 27, 2014, 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 crew's performance and ensure that the licensee evaluators noted the same issues and entered them into the CAP. 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 licensee's training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator (PI) for the first quarter 2013 through the fourth quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's operator logs, issue reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors also reviewed the licensee's 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 one sample for unplanned scrams per 7000 critical hours (IE01) as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for the first quarter 2013 through the fourth quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline,"

Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's

operator narrative logs, issue reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and identified one instance where the licensee had failed to properly identify an unplanned scram as an unplanned scram with complications. Upon further review, the licensee determined that the original unplanned scram met the criteria for an unplanned scram with complications and corrected their PI data submission. Documents reviewed are listed in the Attachment to this report. This inspection constituted one sample for unplanned scrams with complications (IE04)as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Power Changes per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Power Changes per 7000 Critical Hours PI for the first quarter 2013 through the fourth quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance contained in NEI

Document 99-02, "Regulatory Assessment Performance Indicator Guideline,"

Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors also reviewed the licensee's 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 one sample for unplanned transients per 7000 critical hours (IE03) as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.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 licensee's 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 licensee's 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

To assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished through inspection of the station's 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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensee's CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors' review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors' review nominally considered the 6-month period of July 1, 2013, through December 31, 2013, although some exampl es expanded beyond those dates where the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensee's trending reports were reviewed for adequacy. This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection:

Failed Local Leak Rate Test on a Containment Purge Valve

a. Inspection Scope

During a review of items entered in the licensee's CAP, the inspectors recognized a corrective action item documenting the apparent failure of the containment vessel and drywell purge supply line inboard isolation valve to pass its LLRT as documented in CR 2014-02204. The licensee performed a root cause analysis of the failed leak rate test on SVI-M14-T9313, "Type C Local Leak Rate Test (LLRT) of 1M14 Penetration V313." The test was completed on February 6, 2014, and appeared to fail due to total secondary containment bypass leakage exceeding the acceptance criteria. The penetration was declared inoperable and entry into TS 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," LCO C and D.1 was made. The licensee eventually had to commence a plant shutdown to meet a 12-hour shutdown requirement in LCO E. To meet the action statements associated with condition C, one of two options was required to be met. The first option was to stop the leakage by installing a blind flange. The second option was to determine the minimum path leakage values, and if the minimum path leakage values were acceptable, then the valves could be closed and deactivated to meet the requirement. A blind flange was not available to be installed to meet condition C at the time the SVI was conducted. The SVI had been screened as a Green Risk activity, and consequently no contingency plan was developed prior to the maintenance. The Green Risk activity was determined based on a misunderstanding of TS applicability. The operators demonstrated confusion in their understanding of the wording of TS 3.6.1.3 condition C, which states in part, "except for purge valve leakage." Since the test which was being conducted involved purge valves, the operators were unsure of the applicability of the note. The purge valve leakage, however, is an input to the total secondary containment bypass leakage, thus the value obtained during the test has applicability to the conduct of SVI-M14-T9313. Additionally, the current minimum path leakage was not available at the time of the event, contributing further to the operator confusion. The total maximum and minimum pathway leakage values had not been kept up-to-date as required by Perry Administrative Procedure (PAP)-1120. The maximum and minimum pathway leakage totals were required for all secondary containment bypass leakage valves.

These values were obtained by reviewing the past performances of the on-line SVIs, which change with each performance, and the values obtained at the close out of the last refueling outage. The values were not kept up-to-date in the LLRT program as

required by 10 CFR 50, Appendix J.

Because of weaknesses in the licensee's LLRT Appendix J testing program, and operator misunderstanding of what was actually being tested and the impact on TSs, and the misidentification of the risk of the activity being conducted, the licensee needlessly maneuvered the plant from 100 percent power to 42 percent power and back again to 100 percent power. Although no performance deficiency by the operators throughout this event was considered to be more than minor and consequently no findings or violations were identified, the overall conduct of the evolution and unnecessary maneuvering of the plant were indicative of the need for additional licensee management attention.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152.05.

b. Findings

No findings were identified.

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

.1 Failure of Service Water Isolation Valve Due to Extremely Cold Weather

a. Inspection Scope

The inspectors reviewed the licensee's response to a failure of a service water isolation valve caused by extremely cold weather conditions from January 6 - 9, 2014. A 3-inch service water isolation valve located directly off the 42-inch (nonsafety-related) service water header was broken by freezing water in the valve body and was a single-point

vulnerability for the system. As a result of the extremely cold conditions which existed in the area of the broken valve, a natural ice barrier formed at the point where the valve failed mechanically. The natural ice plug and remnants of the valve prevented service water from flowing freely from the system onto the floor of the abandoned Unit 2 Turbine Power Complex building. The licensee took prompt action to replace the failed valve and entered the issue into the CAP as CR 2014-00322. This event and the event discussed in Section 1R01 involving the fire protection system for the Unit 2 startup transformer (an integral part of one of two qualified circuits between the offsite electrical transmission system and the safety-related 4160-V electrical system), highlight the need for additional licensee management attention to the preparation for winter weather. Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

.2 Tritiated Water Release to Plant Underground Area

a. Inspection Scope

The inspectors reviewed the licensee response to discovery of a leak in feed water piping which was uncontained and subsequently migrated from the leak site through a building rattle space and into the ground area under the plant's auxiliary building. The leak was initially identified on January 20, 2014 at 1:10 p.m. in the afternoon. The licensee identified a single sample with elevated tritium levels from a sampling point that is under the auxiliary building. Increased sampling was conducted to evaluate the extent of the leak and appropriate notifications were made by the licensee. Tritium water contamination was not identified in the outfall to the lake during this event. Essentially, it was confined to a single point source input into the ground and did not migrate away from that vicinity. Immediate actions were taken by the licensee to contain the leaking water and then seal up the leakage point on the feed water piping. The leaking point was resealed on January 21, 2014. The licensee's continuing actions were reviewed by the inspectors and the licensee entered the issue in the CAP as CR 2014-00950.

Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

Common Language Initiative Conversions The table below provides a cross-reference from the third and fourth quarter 2013 findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. Finding Old Cross-Cutting Aspect (Pre-2014)

New Cross-Cutting Aspect NCV 05000440/2013004-01 , Failure to Meet Fire Brigade Drill Training Requirements P.1(d) P.3 NCV 05000440/2013004-02 , Worker Access Into a High Radiation Area Contrary to the Requirements of the

Radiation Work Permit None N/A FIN 05000440/2013004-03 , Unprofessional Worker Conduct Inside a Locked High Radiation Area in the Turbine Building 620' Auxiliary Steam Tunnel H.4(c) H.2 NCV 0500440/2013004-04 , Failure to Perform Representative Sampling of Fish in Order to Accurately Assess Ingestion Radiation as Required

by the ODCM H.4(b) H.8 NCV 05000440/2013007-01 , Failure To Comply With Technical Specification 3.4.11 H.2(c) H.7 NCV 05000440/2013007-02 , Failure To Promptly Correct a Non-Conservative Technical Specification H.1(c) H.10 SLIV NCV 05000440/2013008-01 , 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB None N/A FIN 05000440/20132008-02 , 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB None N/A NCV 05000440/2013008-04 , Insufficient Controls to Prevent Common Mode Flooding of ECCS Rooms P.3(a) P.6

.

4OA6 Management Meeting

Exit Meeting Summary

On April 8, 2014, the inspectors presented the inspection results to Mr. Harkness, the Site Vice-President, 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.

4OA7 Licensee-Identified Violation

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV.

• Title 10 of the Code of Federal Regulations, Part 50.55a(b) states, in part, that "systems and components of boiling and pressurized water cooled nuclear power reactors must meet the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section III, Division 1."

The ASME Code 1979 Edition, Winter Addenda of Section III, ND-7311(b), states that "the total rated relieving capacity shall be sufficient to prevent a rise in pressure of more than 10 percent above the Design Pressure of any component within the pressure retaining boundary of the protected system under any system upset conditions." Contrary to the above, the licensee identified in 2002 that it had failed to provide over-pressurization protection for the affected portions of the emergency service water (ESW) system rated at 140 pounds per square inch gauge after upgrading the Division 1 (1998) and 2 ESW (1990) system pumps' impellers to support an increase in licensed reactor power. The licensee generated CR 2-00704 to address the issue.

The finding was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, because the finding was associated with the Mitigating Systems cornerstone attribute of Design Control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Additionally, if left uncorrected, the performance deficiency would become a more significant safety concern. The finding was evaluated

using IMC 0609, Significance Determination Process (SDP), Attachment 0609.4, "Initial Characterization of Findings," dated June 19, 2012. Exhibit 2 of Appendix A, the Mitigating Systems Screening Questions, Section A.1, Mitigating SSCs and Functionality, was checked as "yes" because "the finding is a deficiency affecting design or qualification." As a result the finding screens as very low safety significance (Green).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. Harkness, Site Vice-President

D. Hamilton, Site Operations Director

T. Brown, Performance Improvement Director

D. Reeves, Site Engineering Director

J. Veglia, Maintenance Director

LIST OF ITEMS

Opened and Closed

05000440/2014002-01 NCV Inadequate Procedure for Extreme Cold Weather (Section 1R01)

05000440/2014002-02 NCV Failure to Ensure Required 3-Hour Fire Barriers (Seals) Were In-place (Section 1R05)

Discussed

None

LIST OF DOCUMENTS REVIEWED

The following is a partial list of documents reviewed during the inspection.

Inclusion on this list does not imply that the NRC inspector reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort.

Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.

1R01 Adverse Weather Protection

-

IOI-15; Seasonal Variations; Revision 23 -

ONI-R36-2; Extreme Cold Weather; Revision 3

1R04 Equipment Alignment

-

VLI-E21; Low Pressure Core Spray System; Revision 9 -

SOI-E21; Low Pressure Core Spray System; Revision 28

-

VLI-C41; Standby Liquid Control System; Revision

-

SOI-C41; Standby Liquid Control System; Revision 19

- Drawing 302-0691-00000; Standby Liquid Control System; Revision X - Drawing 208-0030-00002; Standby Liquid Control System Power Distribution, Status Lights &

Instrumentation; Revision EE -

SOI-M15; Annulus Exhaust Gas Treatment System; Revision 11

-

DWG 912-0605-00000; Reactor Building Annulus Exhaust Gas Treatment; Revision W

-

SOI-R23; 480 Volt Load Centers; Revision 10 -

SOI-R22; Metal Clad Switchgear 5-15 KV; Revision 27 -

DWG 208-0207-00011; 480 Load Center EF1D; Revision J

-

DWG 208-206-44; Metal Clad Switchgear (15KV and 5KV) 4.16KV; Revision T

1R05 Fire Protection

-

ONI-P54; Fire; Revision 15 -

FPI-1AB; Auxiliary Building Unit 1; Revision 3 -

FPI-0CC; Control Complex; Revision 9 -

FPI-1DG; Diesel Generator Building; Revision 6

-

PAP-1910; Fire Protection Program; Revision 31

-

FPI-0IB; Intermediate Building; Revision 7

-

CR 2014-04886; NRC ID: Penetration Seals at

CC-638D Do Not Pass

FPI-A-I01 Inspections;

dated March 13, 2014 -

CR 2014-05039; Unplanned Fire Impairment for Division 2 Battery Room; dated November 7, 2011 -

GMI-0077; Installation, Removal, and Repair of Foam Penetration Seals

SF-20; Revision 2

-

FPI-A-I01; Fire Rated Assemblies and Detector Inspection Guidelines; Revision 2

-

PAP-1910; Fire Protection Program; Revision 31 - Drawing 105-0014-00000; Architectural Control Complex Floor Plan Elev. 638'-6"; Revision H -

WO 200485025; (18M) Fire Barrier Visual Inspection Functional Testing; dated July 5, 2013

1R11

Licensed Operator Requalification Program

-

OTLC-3058201406

PY-SGC2; Cycle 6 2014 Evaluated Scenario C2; Revision 2 - eSOMS Narrative Logs; dated February 13, 2014

- eSOMS Narrative Logs; dated February 14, 2014

1R12 Maintenance Effectiveness

- Drawing 302-0691-00000; Standby Liquid Control System; Revision X - Drawing 208-0030-00002; Standby Liquid Control System Power Distribution, Status Lights &

Instrumentation; Revision EE -

CR 2013-00159; Boron Crystalline Formations Identified During

ISI-C41-T1100-2 on 1C41-D003 and 1C41-F0554; dated January 4, 2013 -

CR 2013-00172; Could Not Grease the Stem During

PMI-0030 on

PY-1C41F0001A SLC Pump Suction Valve 'A'; dated January 4, 2013 -

CR 2013-02407; SLC Storage Tank Has a Flange Leak; dated February 17, 2013 -

CR 2013-04572; During ISI Examination of Spring Support Slight Misalignment was Found;

dated March 27, 2013 -

CR 2013-04962; Clearance Issue on Pipe Support Next to Squib Valve 1C41F0004A; dated April 2, 2013 -

CR 2013-06278; Loose Electrical Connections on SLC Storage Tank Level Transmitters; dated April 21, 2013 -

CR 2014-02180; Transmitter 1C41N0010D is Drifting; dated February 5, 2014

-

CR 2013-19119; Standby Liquid Control Pump 'A' Leaking; dated December 2, 2013

-

CR 2013-00456; The Overall System and Material Condition for the Fuel Pool Cooling and Cleanup System Health Report for the Fourth Quarter of 2012 is Rated Yellow; dated January 11, 2013 -

CR 2013-02717; Fuel Pool Cooling and Cleanup System Isolation Boundary Could Not Be Established - Level 4 Clearance; dated February 23, 2013 -

CR 2013-03719; Valve Failed to Close When the Control Switch was Taken to Close; dated March 14, 2013 -

CR 2013-03782; Document Internal Inspection Results of FPCC Contromatics Butterfly Valve;

dated March 14, 2013 -

CR 2013-03015; Relief Valves Issued to the Plant That Were Not Verified to Meet All Procurement Requirements; dated February 28, 2013 -

CR 2013-10141; Dose Rates Elevated in IB5740607 - FPCC Recirc Pump Area; dated July 2, 2013 -

CR 2013-10035; The Containment Fuel Storage Pool High Level Alarm is Locked in With Normal Level Indication; dated June 29, 2013 -

CR 2013-11592; Failure of Fuel Pool Cooling Cleanup (FPCC) Filter Demin Train B Flow Controller (0G41N0161B); dated July 28, 2013 -

CR 2013-11943; Fuel Pool Cooling and Cleanup (G41) Surge Tanks are Requiring More Frequent Filling Following Refuel Outage; dated August 3, 2014 -

CR 2013-15174; FPCC Heat Exchanger Relief Valves Potentially Lifted; dated September 28, 20138 -

CR 2013-14948;

PA-PY-13-003 Some Fuel Pool Cooling and Clean-up (FPCC) Pumps 0G41C003A/B Preventative Maintenance (PM's) Are Not Aligned Properly,

PA-PY-2013-0055-008; dated September 25, 2013 -

CR 2014-17652; Work Order Intended to Close PFA Associated with FPCC System Filter Demin Isolation Valves Did Not Verify Seat Leakage as Part of PMT After Valves were Re-

Installed in the System; dated November 1, 2013 -

CR 2014-00883;

PY-1G41F0516 Has Developed a 20 dpm Leak; dated January 18, 2014

-

CR 2014-01233; The Overall System and Material Condition for the Fuel Pool Cooling and Cleanup System Health Report for 2

nd Half of 2013 is Rated Yellow; dated January 24, 2014 -

CR 2013-19037; Unable to Obtain Adequate Isolation on the Fuel Pool Cooling Cleanup Heat Exchanger; dated November 29, 2013 -

CR 2013-02744; Unable to Isolate Nuclear Closed Cooling to the "A" Fuel Pool Heat Exchanger; dated February 24, 2013 -

CR 2013-03841; Sight Glass on 0G41-D0001D Found Leaking During ISI Pressure Test;

dated March 15, 2013 -

CR 2013-19135; 0G41-F0548A Relief Valve is in Jeopardy of Not Meeting Its ASME Code Required Replacement Date; dated December 3, 2013 - Perry Nuclear Power Plant, Plant Health Report 2013-01; Fuel Pool Cooling and Cleanup

- Perry Nuclear Power Plant, Plant Health Report 2013-02; Fuel Pool Cooling and Cleanup - Perry Nuclear Power Plant, Plant Health Report 2013-01; Standby Liquid Control - Perry Nuclear Power Plant, Plant Health Report 2013-02; Standby Liquid Control

1R13

Maintenance Risk Assessments and Emergent Work Control

-

NOP-OP-1007; Risk Management; Revision 18 -

CR 2014-01022; 1M43R0010A Temperature Controller Indicates High; dated January 22, 2014 - Notification No.

600875939; Temp Controller Indicates High /

CR 2014-01022; dated January 22, 2014 -

WO 200590616; Division 1 DG Rm Fan 1A Temp Cont; Dated January 22, 2014

-

CR 2014-01802; Division 1 Diesel Engine Trip Low Lube Oil Pressure; dated February 2, 2014

- eSOMS Narrative Logs, dated February 2, 2014 -

WO 200591963; Division 1 Diesel Engine Trip; dated February 2, 2014 -

PYBP-POS-2-2; Protected Equipment Posting Checklist for

EH-1-C; dated March 14, 2014

-

CR 2014-03997; Wiring Discrepancy in

LH-1-B Lockout Relay Logic; dated February 27, 2014

-

WO 200556033; Control Rod Exercise and Stall Flow Testing for All Rods Associated with

SVI-C11-T1003A Which Are At Position 48; dated March 22, 2014 -

WO 200556001; Control Rod Exercise and Stall Flow Testing for All Rods Associated with

SVI-C11-T1003B Which Are At Position 48; dated March 22, 2014 -

SVI-C11-T1003A; Control Rod Exercise (Part 1); dated March 22, 2014

-

SVI-C11-T1003B; Control Rod Exercise (Part 2); dated March 22, 2014

-

WO 20596265; Diesel Fire Service Pump; dated March 13, 2014

-

NOP-WM-9001; FIN, Minor Tool Pouch, Immediate, Urgent Maintenance; Revision 7

1R15 Operability Determinations and Functionality Assessments

-

CR 2014-01719; Abnormal Noise From Division 1 D/G

RB-8 Cylinder; dated February 1, 2014 -

WO 200591962; Minor Maintenance, Unit 1 - Division 1 and 2 Standby Diesels; dated February 1, 2014 - eSOMS Narrative Logs; dated February 1, 2014

- eSOMS Narrative Logs; dated February 5, 2014 - eSOMS Narrative Logs; dated February 6, 2014 -

NOP-OP-1009; Operability Determinations and Functionality Assessments; Revision 3

-

CR 2014-02523;

PY-PA-14-013 - Potential Missed Technical Specification 3.6.1.3 Entry;

dated February 10, 2014 -

CR 2014-04038; Continued Operation with Feedwater Heater 6B Normal Drain Closed Operational Decision Making Issue; dated March 3, 2014 - eSOMS Narrative Logs; dated March 5, 2014 - eSOMS Narrative Logs; dated March 6, 2014

-

CR 2014-04402; 1E22F0001 Motor on Limitorque Operator Qualification; dated March 5, 2014

- Prompt Operability Determination for

CR 2014-04402; dated March 14, 2014

-

NOP-CC-3002-01, Revision 1; Calculation - EQ

-012, Qualified Life of Limitorque Valve Operators; Revision 3; dated February 15, 2005 -

NOP-CC-3002-01, Revision 4; Calculation -

EQ-202, Qualified Life of Valve Operators in Zone

AB-4 With Removed Margin, Revision 0; dated March 6, 2014 - eSOMS Narrative Logs; dated March 13, 2014

-

CR 2014-04856; Control Power Fuse for EF1C09-S Blown While Replacing Light Bulb; dated March 13, 2014

1R19 Post-Maintenance Testing

-

WO 200513715; Replace Rosemount Master Trip Unit OM25N0732 Based on

CR 2012-10238; dated January 10, 2014 -

IMI-E2-10; Rosemount Trip Unit Meter Scale Replacement; Revision 2

-

ICI-B21-1; Rosemount Master Trip Unit (510DU) and (710DU); Revision 9

-

WO 200590616; Division 1 DG RM Fan 1A Temp Cont; dated January 22, 2014

-

WO 200321148;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Outlet Shutoff Valve; dated January 27, 2014 -

WO 200581174;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Second Inlet Valve; dated January 27, 2014 -

WO 200581684;

PY-1G36 RWCU Filter and Demineralizer F/D Supp from CNDS STRG & XFER Relief; dated January 24, 2014 -

WO 200581169;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Firest Inlet Valve; dated January 24, 2014 -

WO 200579159;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Out Strainer B/W Flush First ISO; dated January 23, 2014 -

WO 200579161;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Out Strainer B/W Flush Second IS; dated January 23, 2014 -

WO 200321149;

PY-1G36 RWCU Filter and Demineralizer F/D 'A' Outlet Flow Control Valve; dated January 24, 2014 -

WO 200561047; Repair Valve Seat Leakage /

CR 2014-02204 and

CR 2013-06691 Valve has Exhibited Excessive Leakage During LLRT; dated February 13, 2014 - eSOMS Narrative Logs; dated February 8, 2014

-

WO 200595475; Troubleshoot and Repair

LH-1-B Transformer Wiring Error in Protection Relay Control Logic; dated March 6, 2014 -

CR 2014-05125; Terminal Blocks on

LH-1-B Transformer Found Severely Corroded; dated March 18, 2014 -

WO 200539426; Iodine Readout Module (K670); dated March 20, 2014

-

PTI-D17-P1670; Drywell Atmospheric Radiation Monitor 1D17-K677 Calibration; Revision 5

-

CR 2013-12917; Wiring Was Hanging Inside of Control Panel 1H13-P0864; dated August 21, 2013 -

ICI-C-D17-19; Calibration of Victoreen Gamma Channels; Revision 7

1R22 Surveillance Testing

-

SVI-P45-T2001; ESW Pump A and Valve Operability Test; dated January 4, 2014 -

SOI-P45/P49; Emergency Service Water and Screen Wash Systems; Revision 2

-

SVI-E12-T1182C; RHR 'C' LPCI Valve Lineup Verification and System Venting; dated January 10, 201 -

SVI-E31-T1405C; MSL High Flow Channel 'C' Response Time for 1E31-N686C, 1E31, N687C, 1E31-N688C, and 1E31-N689C; dated January 16, 2014 -

WO 200514109; Replace Master Trip Unit 1E31N0688C Based on

CR 2012-10238;

dated January 16, 2014 -

SVI-E31-T0074C; MSL High Flow Channel 'C' Functional for 1E31-N68C and 1E31-N688C (full); dated January 16, 2014 -

WO 20088991; MSL High Flow Channel 'C' Response Time for 1E31-N686C, 1E31-687C, 1E31-N688C, and 1E31-N689C; dated January 16, 2014 -

SVI-E31-T0074C; MSL High Flow Channel 'C' Functional for 1E31-N68C and 1E31-N688C (Partial); dated January 16, 2014 -

SVI-E22-T1200; HPCS Pump Discharge Pressure - High (Bypass) Channel Functional for

1E22-N651; dated February 13, 2014 -

SVI-B21-T0034D; RPV Level 3 and Level 8 RPS/RHR Shutdown Isolation Channel D Functional for 1B21-N680D; dated February 14, 2014 1EP6 Drill Evaluation

-

OTLC-3058201406

PY-SGC2; CYCLE 6 2014 Evaluated Scenario C2; Revision 2

4OA1 Performance Indicator Verification

-

NOBP-LP-4012-01, Revision 2; Unplanned Scrams per 7,000 Critical Hours; January 2013

through December 2013 -

NOBP-LP-4012-02, Revision 3; Unplanned Scrams with Complications (USwC); January 2013

through December 2013 -

NOBP-LP-4012-02, Revision 3; Unplanned Scrams with Complications (USwC); January 2013; Change File, dated July 18, 2013 -

NOBP-LP-4012-03, Revision 2; Unplanned Power Changes per 7,000 Critical Hours; January

2013 through December 2013

4OA2 Identification and Resolution of Problems

-

CR 2014-02204; Failed Leak Rate Test on

SVI-M14-T9313; dated February 5, 2014 - eSOMS Narrative Logs; dated February 5, 6, 7, and 8, 2014 - Root Cause Analysis Report; Failed Leak Rate Test on

SVI-M14-T9313; dated March 18, 2014 -

CR 2013-10866; Re-Evaluation of Accreditation Objective 2 Related Training Gaps Indicate a Potential Objective Level Finding; dated July 16, 2013 -

CR 2013-14011; Documentation, Decision Making and Implementation of the Current Radiation Protection Initial Training Program Not at the Desired Level; dated September 9, 2013 -

CR 2013-16381; Training Program Self-Evaluation and Oversight Were Not Effectively Used to Provide Early Identification and Correction of Potential Training Program Vulnerabilities; dated

October 14, 2013 -

CR 2013-10627; NRC Cross-Cutting Theme in Problem Identification and Resolution (PI&R)

Aspect P.1(c); dated July 11, 2013 -

CR 2013-10680; Possible Tolerance of Equipment Issues at Perry; dated July 12, 2013 -

CR 2013-11688;

PY-PA-13-02, The Impact of Increased Corrosion Rates Within Nuclear Closed Cooling and the Failure to Maintain Chemistry Parameters Within Required Limits Has Not Been Evaluated for Relationship to System Failures that Have Been Experienced; dated

July 30, 2013 -

CR 2013-11728; Annulus Not Verified Prior to Posting as a LHRA; dated July 30, 2014 -

CR 2013-12077; Individual Received Dose Rate Alarm While Removing Chain Fall; dated August 6, 2013 -

CR 2013-13040;

MN-ID: Adverse Trend in Material Handling; dated August 23, 2013

-

CR 2013-13521; Elevated Voltage on V1A; dated August 30, 2013 -

CR 2013-13912; Degraded Component Received from Warehouse; dated September 7, 2013

-

CR 2013-13977;

FO-SA-2013-0025, Pre-PI&R Self-Assessment Identified Issue with Effectiveness Reviews on

CA 2011-01593-25; dated September 9, 2013 -

CR 2013-14368; Five CR Evaluations Have Been Rejected at CARB in August and September; dated September 16, 2013 -

CR 2013-09891 Evaluation Was Rejected for a Second Time in September; dated September 16, 2013 -

CR 2013-15109;

PA-PY-13-02 - Outage Management Rated Ineffective (Red) for Second Trimester 2013; dated September 27, 2013 -

CR 2013-15110:

PA-PY-13-02 - Radiation Protection Rated Ineffective (Red) for Second Trimester 2013; dated September 27, 2013 -

CR 2013-15111;

PA-PY-13-02 - Corrective Action Program (CAP) Was Rated Marginally Effective (Yellow) Declined for Second Trimester of 2013; dated September 27, 2013 -

CR 2013-16295; An Individual Was Observed Exiting a Posted RCA Area Into a Non-RCA

Area; dated October 11, 2013 -

CR 2013-16533; NRC Cross-Cutting Theme in Human Performance Aspect H.4(b); dated October 16, 2014 -

CR 2013-17076;

MS-C-13-10-08:

FINDING Continued M&TE Program Non-Compliance;

dated October 24, 2013 -

CR 2013-17308; During the 3rd Quarter Safety Culture Meeting the Nuclear Safety Monitoring Panel Requested That Four Issues Involving W

illful Acts Be Evaluated Together To Evaluate for Organizational and Safety Culture Issues; dated October 28, 2013 -

CR 2013-17760; AFI

MA.2-1, Supplemental Work Performance; dated November 2013

-

CR 2013-19186; Leaks Developing in Components Cooled by the Nuclear Closed Cooling (NCC) System Higher Than Expected; dated December 3, 2013

4OA3

Follow-Up of Events and Notices of Enforcement Discretion

-

CR 2014-00322; Service Water Valve Burst; dated January 9, 2014 -

WO 200587992; Service Water Header Annubar Isolation Valve

PY-1P41F0056; dated January 10, 2014 -

CR 2014-00950; Entered

ONI-ZZZ-5, Radioactive Spill Due to Feedwater Venturi Leakage; dated January 20, 2014

LIST OF ACRONYMS

USED [[]]

ADAMS Agencywide Document Access Management System

ASME American Society of Mechanical Engineers

CAP Corrective Action Program

CFR Code of Federal Regulations

CR Condition Report

DC Direct Current

DG Diesel Generator

EDG Emergency Diesel Generator

ESW Emergency Service Water

FPI Fire Protection Instruction

GMI Generic Mechanical Instruction

IMC Inspection Manual Chapter

IP Inspection Procedure

IR Inspection Report

LCO Limiting Condition for Operation

LLRT Local Leak Rate Test

NCV Non-Cited Violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

PI Performance Indicator

PSIG Pound Per Square Inch Gauge

PTI Periodic Test Instruction

SVI Surveillance Instruction

TS Technical Specification

USAR Updated Safety Analysis Report

V Volts WO Work Order

E. Harkness -2-

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last 6 months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter

(IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these

cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment

review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region

III and the

NRC Resident Inspector at the Perry Nuclear Power

Plant.

In accordance with Title 10 of the Code of Federal Regulations 2.390, "Public Inspections, Exemptions, Requests for Withholding," of the NRC's "R

ules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in

the

NRC Public Document Room or from the Publicly Available Records System (

PARS) component of NRC's Agencywide Documents Access and Management Sy

stem (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/

Michael Kunowski, Chief

Branch 5 Division of Reactor Projects

Docket No. 50-440

License No. NPF-58

Enclosure:

Inspection Report 05000440/2014002 w/Attachment: Supplemental Information cc w/encl: Distribution via LISTSERV

DISTRI BUTION

See next page DOCUMENT NAME: Perry IR 2014002 Publicly Available Non-Publicly Available

Sensitive Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE [[]]

RIII [[]]

RIII [[]]

RIII [[]]

RIII [[]]

NAME MKunowski:rj

DATE 05/12/14

OFFICI AL

RECORD [[]]

COPY

Letter to Ernest Harkness from Michael Kunowski dated May 12, 2014

SUBJEC T:

PERRY [[]]

NUCLEA R

POWER [[]]

PLANT -

NRC [[]]

INTEGR ATED INSPECTION

REPORT 05000440/2014002

DISTRI BUTION w/encl

Joseph Nick

RidsNrrPMPerry Resource

RidsNrrDorlLpl3-2 Resource

RidsNrrDirsIrib Resource Cynthia Pederson

Darrell Roberts

Steven Orth

Allan Barker

Carole Ariano

Linda Linn

DRPIII [[]]

DRSIII

Patricia Buckley

Carmen Olteanu

ROP reports.Resource@nrc.gov