IR 05000482/2012002

IR 05000482-12-002, on 01/01/2012 – 03/30/2012, Wolf Creek Generation Station, Integrated Resident and Regional Report; Refueling and Other Outage Activities, Surveillance Testing, Event Follow-up

ML12131A647
Person / Time
Site:	Wolf Creek
Issue date:	05/09/2012
From:	O'Keefe N NRC/RGN-IV/DRP/RPB-B
To:	Matthew Sunseri Wolf Creek
O'Keefe N
References
IR-12-002
Download: ML12131A647 (47)

Text

May 9, 2012

SUBJECT:

WOLF CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000482/2012002

Dear Mr. Sunseri:

On March 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek facility. The enclosed inspection report documents the inspection results which were discussed with you and other members of your staff on April 11, 2012.

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.

One self-revealing and two NRC identified findings of very low safety significance (Green) were identified during this inspection. All of these findings were determined to involve violations of NRC requirements. Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Wolf Creek Generating Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Wolf Creek Generating Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511 accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Neil OKeefe, Chief Project Branch B Division of Reactor Projects Docket No.: 05000482 License No: NPF-42

Enclosure:

Inspection Report 05000482/2012002 w/ Attachment: Supplemental Information

REGION IV==

Docket:

05000482 License:

NPF-042 Report:

05000482/2012002 Licensee:

Wolf Creek Nuclear Operating Corporation Facility:

Wolf Creek Generating Station Location:

1550 Oxen Lane NE, Burlington, Kansas Dates:

January 1 through March 30, 2012 Inspectors: C. Long, Senior Resident Inspector C. Peabody, Resident Inspector Z. Hollcraft, Callaway Resident Inspector J. Melfi, Project Engineer, Branch E G. Callaway, Senior Reactor Technology Instructor

Approved By:

Neil OKeefe, Chief, Project Branch B Division of Reactor Projects

- 2 -

Enclosure

SUMMARY OF FINDINGS

IR 05000482/2012002; 01/01/2012 - 03/30/2012, Wolf Creek Generation Station, Integrated

Resident and Regional Report; Refueling and Other Outage Activities, Surveillance Testing,

Event Follow-up.

The report covered a 3-month period of inspection by resident inspectors and by a region-based inspector. Three Green non-cited violations of significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. 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.

Cornerstone: Initiating Events

Green.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for a procedure that failed to restore the reactor coolant pump seal return flow path prior to raising reactor coolant system pressure, which caused the seal return relief valve to lift. During shutdown, reactor coolant pump seal return valve BGHV8100 was shut. On February 12, 2012, Wolf Creek was in Mode 5 with a water-filled (solid) pressurizer at 94 psig. After pressurizer power operated relief valve maintenance, Wolf Creek raised reactor coolant system pressure to 250 psig. With no return path, the relief valve lifted at 150 psig for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> before operators noted an unexplained steady increase in pressurizer relief tank level and re-established the return flow path. Wolf Creek procedures were written to transition straight to refueling, and did not include consideration for maneuvering the plant in Mode 5. This led to shutting valve BGHV8100 without instructions to reopen it before exceeding 150 psig. Wolf Creek subsequently added procedure steps and precautions to reopen the seal return path in Mode 5.

The inspectors calculated that approximately 760 gallons of reactor coolant were lost to the relief tank. This issue was placed in the corrective action program as condition report 49021.

Failure to align the reactor coolant pump seal return flow path prior to raising reactor coolant system pressure above the relief valve setpoint, creating a leak path, was a performance deficiency. The inspectors determined that this finding impacted the Initiating Events Cornerstone and its objective to limit the likelihood of events that upset plant stability and challenge safety functions during shutdown. Specifically, it impacted the configuration control attribute of shutdown equipment lineup which created an unmonitored intersystem leak. The inspectors used Inspection Manual Chapter 0609, Appendix G, Attachment 1, checklist 4 (cold shutdown, level in the pressurizer, time to boil >2 hours) to evaluate the significance of this finding. A Phase 2 analysis was not needed because the level of inventory was terminated when the normal path was opened and the relief valve reseated. The leak would have terminated itself if the reactor coolant system drained itself to below the pump seal. The finding did not affect reactor coolant system level indication, affect the ability to terminate the leak path, affect the ability to add inventory, or affect the ability to recover residual heat removal if it was lost. Therefore, the finding was determined to be of very low safety significance. The inspectors identified the cause of the finding had a human performance cross-cutting aspect in the area of resources. Specifically, complete and accurate procedures were not provided because Procedure GEN 00-006 did not contain guidance to establish the seal return flow path prior to raising reactor coolant system pressure above 150 psig H.2.c]. (Section 1R20)

Cornerstone: Mitigating Systems

Green.

Inspectors identified a non-cited violation of Technical Specification 5.4.1.a, Procedures, for implementation of an unauthorized modification by using a clearance order and a temporary procedure. This left the power source to a temporary protective relay unprotected. When another clearance order was being placed for main generator work, the temporary relay power source was lost when fuses were removed which supplied power to the temporary relay. This tripped the offsite power breaker to 13.8kV bus PA01 and tripped PA01 distribution breakers on January 24, 2012. Safety busses were unaffected because they were cross tied and being supplied by the No. 7 transformer. All non-vital systems lost power including normal service water which was removing core decay heat until operators could manually start and align essential service water pumps. Power to all systems was restored within approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors found that the installation of temporary equipment was an unevaluated long standing practice. The temporary procedure was consistent with a system operating procedure when it was approved on January 17, 2012. This conclusion differed from Wolf Creeks apparent cause determination which did not identify the issue as an unevaluated modification. The inspectors concluded that they added value and considered the issue NRC identified.

Initially, corrective actions included changing the clearance order to prevent removing of fuses to the temporary relay. After inspector questions, Wolf Creek blocked the use of the temporary procedure and procedure SYS MA-120 until further evaluation was completed. This has been entered into the corrective action program as condition reports 48182, 48642, and 51408.

Failure to control system configuration such that unplanned loss of power would not occur is a performance deficiency. The inspectors determined that this finding was more than minor because it impacted the mitigating systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Specifically, it impacted the configuration control attribute of shutdown equipment lineup which created a loss of offsite power to 13.8kV bus PA01. The inspectors screened the loss of service water pumps B and C, A and B circulating water pumps, vital air conditioning units, emergency diesel generator starting air compressors, transformer XNB01 cooling fans, heat tracing, auxiliary boiler steam heating, the condensate storage tank makeup pump, and the refueling water storage tank makeup pump to Manual Chapter 0609, attachment G, checklist 4. Wolf Creek had inventory in the pressurizer with a time to boil greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The inspectors screened the finding to Green or very low safety significance because it did not involve a loss of reactor coolant system inventory, did not affect reactor coolant system level instrumentation, did not affect the licensees ability to terminate a leak path, did not affect the licensees ability to add reactor coolant system inventory when needed, or degrade the licensees ability to recover decay heat removal once it was lost. Additionally, the inspectors screened the loss of the electric fire pump and jockey (keep full) fire pump to Inspection Manual Chapter 0609.04. Specifically, these pumps were out of service for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and therefore, screened to Green or very low safety significance. The inspectors identified that the cause of the finding had a human performance cross-cutting aspect in the area of resources because the loss of power was caused by a lack of complete, accurate and up-to-date design documentation, procedures, drawings, fuse labeling, and work orders necessary to support the temporary configuration established through TMP 12-001 H.2.c]. (Section 4OA3)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50.55a(f)(4), Codes and Standards, for failure to adequately demonstrate that the seat leakage for 12 emergency core cooling system and containment spray valves remained within acceptable limits. These valves have a combined allowable leakage rate of 3.8 gpm to ensure that control room operator radiation doses remain within regulatory limits during an accident. Since the flowpaths have valves for which seat leakage is limited to a specific maximum amount, the inspectors identified that they should be considered Category A valves as specified in ASME OM (American Society of Mechanical Engineers Operations &

Maintenance) Code. Wolf Creek subsequently took corrective action to perform valve seat leakage testing on March 10, 2012, which demonstrated that leakage was within acceptable limits. Additionally, Wolf Creek plans to change Chapter 15 of the USAR and correct its ASME OM Code basis document. This issue was entered into the licensees corrective action program as condition report 46927.

Failure to correctly identify and perform testing needed to assure plant design for control room habitability is a performance deficiency. This finding is greater than minor because it was associated with the Barrier Integrity Cornerstone attribute of configuration control and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, it affects the design control objective by failing to ensure that design limits were met on a periodic basis. Using Inspection Manual Chapter 0609.04, the issue was determined to not impact public and control room dose (above regulatory limits), it did not impact the control room due to toxic gas, it did not represent an actual open containment bypass path (above of regulatory limits), and did not impact hydrogen igniters.

Therefore, this finding was found to be of very low safety significance. Also, public dose was not impacted with a potential radiation dose above a 10 CFR Part 50, Appendix I criteria. This finding did not have a cross-cutting aspect since the error associated with the inservice testing program was not reflective of current licensee performance because the failure to identify and include these valves occurred more than 3 years ago. (Section 1R22)

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has 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 associated corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Wolf Creek entered the inspection period on January 1, 2012, at 100 percent power. The plant tripped automatically on January 13, 2012, due to main generator output breaker fault which was followed by a loss of offsite power. All safety systems functioned properly and the plant successfully completed a natural circulation cooldown to cold shutdown conditions on January 4, 2012. Wolf Creek remained in a forced outage until March 20, 2012, when the reactor was restarted. The plant returned to 100 percent power on March 30,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Partial Walkdown

a.

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

Inspection Scope

• January 4, 2012, Motor-Driven auxiliary feedwater train A

• March 6, 2012, Offsite power and auxiliary support power

• March 13, 2012, Residual heat removal train B

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 affect the function of the system, and therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, updated safety analysis report (USAR), technical specification requirements, administrative technical specifications, outstanding work orders, 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 inspected 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 corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

.2 Complete Walkdown

a.

On March 15, 2012, the inspectors performed a complete system alignment inspection of the control room ventilation system to verify the functional capability of the system.

The inspectors selected this system because it was safety significant. The inspectors inspected the system to review mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These activities constitute completion of one complete system walkdown sample as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a.

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

Inspection Scope

• February 17, 2012, Vital battery rooms

• February 17, 2012, 4kV vital switchgear rooms

• March 13, 2012, Lower cable spreading room

• March 13, 2012, Upper cable spreading room

• March 14, 2012, Central alarm station room

The inspectors reviewed areas to assess if licensee personnel 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 had 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 affect equipment that 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, 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 corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b.

No findings were identified.

Findings

1R06 Flood Protection Measures

a.

The inspectors reviewed the USAR, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

• January 10, 2012, Electrical manhole MHE4 (bunker/manhole)

These activities constitute completion of one flood protection measures inspection sample and one bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b.

No findings were identified.

Findings

1R11 Licensed Operator Requalification Program

a.

On March 21, 2012, the inspectors observed a crew of licensed operators in the plants simulator 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:

Inspection Scope

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to preestablished operator action expectations and successful critical task completion requirements.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b.

No findings were identified.

Findings

1R13 Maintenance Risk Assessments and Emergent Work Control

a.

The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-Inspection Scope

related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• February 6, 2012, unplanned entry into Yellow risk for core decay heat removal due to draining 3 steam generators less than 66 percent wide-range level

• March 6, 2012, risk assessment for surveillance of train B vital 4160V bus undervoltage and degraded voltage relays

The inspectors selected these activities based on potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. 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 the technical specification requirements and inspected 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.

These activities constitute completion of two maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b.

See section 4OA7.

Findings

1R15 Operability Evaluations and Functionality Assessments

a.

The inspectors reviewed the following assessments:

Inspection Scope

• January 4, 2012, Auxiliary feedwater tricentric butterfly valve disc ear stress evaluation

• February 14, 2012, Condensate pipe hanger functionality evaluation after pipe movement

• March 2, 2012, Residual heat removal pump A motor oil leak

The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability

was properly justified and to verify 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 technical specifications and USAR to the licensees 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. 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. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three operability evaluations inspection sample(s) as defined in Inspection Procedure 71111.15-05.

b.

No findings were identified.

Findings

1R18 Plant Modifications

.1 a.

Temporary Modifications To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the temporary modification for containment penetration ZNE274 Module A replacement with a fabricated stainless steel plug. The modification was necessitated by a cable to cable fault at one of the penetration modules on March 20 and again on March 22, 2012, which overheated the penetration seal for that module.

Inspection Scope

The inspectors reviewed the temporary modification and the associated safety-evaluation screening against the system design bases documentation, including the USAR and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of one sample for temporary plant modifications as defined in Inspection Procedure 71111.18-05.

b.

No findings were identified.

Findings

1R19 Post Maintenance Testing

a.

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

Inspection Scope

• February 20-22, Emergency diesel generator B endurance run and load reject test after rotor field wire replacement and exciter capacitor replacement

• March 7, 2012, Emergency diesel generator A integrated engineered safety features actuation signal load reject test after governor replacement

• March 8, 2012, Emergency diesel generator A accident load and margin test after rotor field wire replacement and exciter capacitor replacement

• March 28, 2012, Turbine-driven auxiliary feedwater full flow test after bearing replacements

The inspectors selected these activities based upon the structure, system, or component's ability to affect 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

The inspectors evaluated the activities against the technical specifications, 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 postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b.

No findings were identified.

Findings

1R20 Refueling and Other Outage Activities

a.

The inspectors reviewed the outage safety plan and contingency plans for the forced outage, conducted between January 13 and March 26, 2012, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

Inspection Scope

• Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

• Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Startup and ascension to full power operation, tracking of startup prerequisites, and walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers.

• Licensee identification and resolution of problems related to forced outage activities.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b.

Introduction.

On February 13, 2012, the inspectors reviewed a Green, self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for a procedure that was not appropriate to the circumstances because it failed to reestablish a reactor coolant pump seal return flow path prior to raising reactor coolant system pressure and causing the seal return relief valve to lift.

Findings

Description.

On February 12, 2012, Wolf Creek was in Mode 5 with a water-filled (solid)pressurizer. At 10:57 am, reactor coolant system pressure was raised from 94 psig to 250 after pressurizer power operated relief valve maintenance was completed. Fifteen hours later, a control room operator questioned the unexpected increasing trend in pressurizer relief tank level. During that time, chemistry control evolutions had caused the pressurizer relief tank to increase and decrease, but the tank level showed an increasing trend for the entire period.

Wolf Creek subsequently discovered that the reactor coolant pump seal return valve BGHV8100 had been shut when reducing pressure for power operated relief valve maintenance. Subsequently, when pressure was raised, there was no path for the seal return water other than to lift relief valve BG8121. Relief valve BG8121 has a lift pressure of 150 psig while reactor coolant system pressure was raised to 250-260 psig.

Relief valve BG8121 discharges to the pressurizer relief tank. Wolf Creek subsequently opened valve BGHV8100 to re-establish a reactor coolant pump seal return path, and verified that the relief valve reseated.

The inspectors reviewed plant computer data for the valve positions, pressurizer relief tank level, and reactor coolant system pressure. The inspectors calculated approximately 760 gallons of water was lost from the reactor coolant system to the pressurizer relief tank.

The inspectors determined that General Operating Procedure GEN 00-006, Hot Standby to Cold Shutdown, revision 82, was written to transition the plant directly through Mode 5 (cold shutdown) to Mode 6 (refueling), at which time operators would enter procedure GEN 00-008, RCS Level Less than Reactor Vessel Flange Operations. Procedure GEN 00-006 isolated the seal return path, and would eventually restore the seal return flow path prior to reentering to Mode 5. The inspectors concluded that GEN 00-006 was inappropriate to the circumstances under which it was being used on February 12, since the procedure did not consider raising pressure above the relief valve setpoint.

Wolf Creek subsequently revised GEN 00-006, Hot Standby to Cold Shutdown, and GEN 00-002, Cold Shutdown to Hot Standby, to open the seal return isolation valve BGHV8100 prior to raising reactor coolant system pressure.

Analysis.

Failure to align the reactor coolant pump seal return flow path prior to raising reactor coolant system pressure above the relief valve setpoint, creating a leak path, was a performance deficiency. The inspectors determined that this finding impacted the Initiating Events Cornerstone and its objective to limit the likelihood of events that upset plant stability and challenge safety functions during shutdown. Specifically, it impacted the configuration control attribute of shutdown equipment lineup which created an unmonitored intersystem leak. The inspectors used Inspection Manual Chapter 0609, Appendix G, Attachment 1, checklist 4 (cold shutdown, level in the pressurizer, time to boil >2 hours) to evaluate the significance of this finding. A Phase 2 analysis was not needed because the level of inventory was terminated when the normal path was opened and the relief valve reseated. The leak would have terminated itself if the reactor coolant system drained itself to below the pump seal. The finding did not affect reactor coolant system level indication, affect the ability to terminate the leak path, affect the ability to add inventory, or affect the ability to recover residual heat removal if it was lost. Therefore, the finding was determined to be of very low safety significance. The inspectors identified the cause of the finding had a human performance cross-cutting aspect in the area of resources. Specifically, complete and accurate procedures were nopt provided because Procedure GEN 00-006 did not contain guidance to establish the seal return flow path prior to raising reactor coolant system pressure above 150 psig

H.2.c].

Enforcement.

Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure GEN 00-006, Hot Standby to Cold Shutdown, revision 82, implements this requirement by establishing instructions for unit operation and safety-related portions of the reactor coolant pump seal return flow path. Contrary to the above, from February 12 to 13, 2012, the licensee controlled the primary plant configuration and pressure, an activity affecting quality, using a procedure that was not appropriate to the circumstances. Specifically, Procedure GEN 00-006 required operators to isolate the reactor coolant pump seal return flow path when pressure was lowered below 150 PSIG, but failed to require restoring this flow path prior to raising pressure above the relief valve setpoint. Because this violation is of very low safety significance and has been entered into Wolf Creek's corrective action program as condition report 49021, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2012002-01, Inadequate Procedure Causes Lift of Relief Valve and Reactor Coolant Leak During Shutdown.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the USAR, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to

verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• January 4, 2012, Component cooling water pumps A and C comprehensive pump in-service test (IST)

• March 10, 2012, Borated water storage system inservice valve test (IST)

• March 12, 2012, Emergency diesel generator A 24-hour run

• March 26, 2012, Emergency core cooling system train A void surveillance

• March 28, 2012, Main turbine power load unbalance test

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b.

Introduction.

The inspectors identified a non-cited violation of 10 CFR Part 50.55a(f)(4),

Codes and Standards, for the failure to adequately demonstrate that the seat leakage of valves associated with the emergency core cooling system recirculation flow path remained within acceptable limits.

Findings

Description.

On December 2, 2011, the inspectors reviewed the licensees ASME inservice testing program with respect to isolation valves within the post loss of coolant accident (LOCA) emergency core cooling system (ECCS) recirculation flowpath that provide a barrier to prevent the escape of sump fluids back to the refueling water storage tank. During a loss of coolant accident, the emergency core cooling system and containment spray system suctions are swapped to take suction from the containment sump. The containment sump valves open automatically. This pressurizes portions of these systems piping that is higher than at any other time. The refueling water storage tank is vented to atmosphere, so gases escaping from the vent can be pulled into the control room ventilation intake.

In their review, the inspectors discovered that the licensee had previously evaluated NRC Information Notice 91-56, Potential Radioactive Leakage to Tank Vented to Atmosphere, and identified several, but not all, potential leakage pathways back to the refueling water storage tank. The licensee had concluded that leakage would be limited accident by assuming that two-valve isolation would result in zero leakage. At that time, the licensee added some valves to its inservice leakage test program but not all.

Additionally, the licensee added USAR Section 15.6.5.4.1.4 to state that a local operator will shut the main refueling water storage tank isolation valve after containment sump recirculation is established to limit control room operator dose. Valve BNV-11 is a 24-inch diameter manual isolation valve. The inspectors noted that, despite having a function to close, valve BNV-11 was still classified as a passive valve with no maximum allowable seat leakage criteria assigned. The combined allowable leakage rates are used as an input assumption to Calculation AN-99-020, Radiological Consequences Analysis of a Loss of Coolant Accident, revision 1. The calculation evaluated dose to the control room operators during an accident using an assumed source term from primary coolant migrating to the refueling water storage tank, out its vent, and to the control building ventilation intake. The calculation assumed leakage is limited to 5 gpm for the first 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> of an accident and 2 gpm for the remaining 30 days of a loss of coolant accident.

On December 2, 2011, the inspectors identified to the licensee that seat leakage testing was only performed on a limited number of the flowpaths that could provide a pathway of recirculation sump fluid back to the refueling water storage tank during post-LOCA conditions. The inspectors found that testing was not performed on 12 valves.

Specifically, the inspectors identified that the four flowpaths associated with the centrifugal charging pumps and safety injection pumps, residual heat removal pumps, and containment spray pumps suctions have isolation valves that should be considered Category A valves as specified in ASME OM Code-1998 with 2000 Addendum, Code for Operation and Maintenance of Nuclear Power Plants. Section ISTA-1100, defines

the scope and general requirements as those extending to all pumps and valves that have a function in mitigating the consequences of an accident. Section ISTC-1300, Valve Categories, defines Category A valves as those for which seat leakage is limited to a specific maximum amount in the closed position for fulfillment of their required function. Section ISTC-3600, Leak Testing Requirements, stipulates that Category A valves with a leakage requirement be tested to verify their seat leakages within acceptable limits at least once every 2 years. Because the combined seat leakage limit of the isolation valves associated with the centrifugal charging pump, safety injection pump, residual heat removal, and containment spray suctions are required to be limited by Calculation AN-99-020, Radiological Consequences Analysis of A Loss of Coolant Accident, revision 1, the inspectors concluded that the valves should be tested per the requirements of ISTC-3600.

On December 14, 2011, the licensee subsequently initiated condition report condition report 46927 and operability evaluation BN-11-011 to evaluate if a required surveillance test had been missed. On December 16, 2011, BN-11-01 concluded that the accident analysis leakage assumption could be met. The inspectors concluded that this evaluation did not account for all leakage paths and that it relied on an assumption that untested valves would not leak.

Subsequent to further meetings, Wolf Creek decided to evaluate potential leak paths under condition report 46927. On February 14, 2012, Wolf Creek completed a revision to calculation AN-99-020 to revise the allowed leak rate to 3.8 gpm for the first 30 days of an accident and established a new administrative limit of 3 gpm for all valve leakage to the refueling water storage tank. On February 17, 2012, Wolf Creek completed its evaluation in condition report 46927 of potential leak paths. On March 7, 2012, Wolf Creek issued revision 16 to Procedure STS BN-206, Borated Refueling Water Storage System Inservice Valve Test, to include testing of the 12 valves. On March 10, 2012, Wolf Creek performed seat leakage testing associated with the centrifugal charging pumps, safety injection pumps, residual heat removal pumps, and containment spray pumps suction isolation valves. The 12 valves that had not been previously tested were valves BG8546A, BG8645B, BNHV8806A, BNHV8816B, BNLCV112E, BNLCV112D, EJ8958A, EJ8958B, EM8926A, EM8926B, ENV3, and ENV9. Total leakage measured during the testing was 1.239 gpm and was acceptable. Long-term corrective actions by the licensee include reclassification of the emergency core cooling system and containment spray suction isolation valves as Category A valves in the ASME OM test program. Also, Wolf Creek planned to remove Section 15.6.5.4.1.4 from the USAR to delete the manual action to shut valve BN-V11 and will instead rely on valve testing described above.

Analysis.

Failure to correctly identify and perform testing needed to assure plant design for control room habitability is a performance deficiency. This finding is greater than minor because it was associated with the Barrier Integrity Cornerstone attribute of configuration control and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, it affects the design control objective by failing to ensure that design limits were met on a periodic basis. Using Inspection Manual Chapter 0609.04,

Phase 1 - Initial Screening and Characterization of Findings, the issue was determined to not impact public and control room dose (above regulatory limits), it did not impact the control room due to toxic gas, it did not represent an actual open containment bypass path (above of regulatory limits), and did not impact hydrogen igniters. Therefore, this finding was found to be of very low safety significance. Also, public dose was not a potential release that could impact 10 CFR Part 50, Appendix I criteria. This finding did not have a cross-cutting aspect since the error associated with the inservice testing program was not reflective of current licensee performance.

Enforcement.

Title 10 CFR, 50.55a(f)(4), Codes and Standards, requires, in part, that throughout the service life of a nuclear power plant, that testing of code class 1, 2, and 3 valves meet the requirements of the ASME O&M code. Wolf Creek utilizes ASME OM Code 1998 edition through 2000 addendum, Code for Operation and Maintenance of Nuclear Power Plants. The ASME O&M Code sections ISTA and ISTC, in part, define Category A valves as those that are limited to a specified amount of seat leakage to perform their safety function. Section ISTC-3630 requires, in part, that category A valves be tested every 2 years. Calculation AN 99-020, Radiological Consequences Analysis of A Loss of Coolant Accident, revision 1, establishes requirements of General Design Criterion 19 to demonstrate acceptable dose to the control room operators. Specifically, part of the source term for that dose is valve seat leakage to the refueling water storage tank. Contrary to the above, Wolf Creek failed to test 12 class 2 valves throughout the service life of the nuclear power plant as required by the ASME O&M Code. Specifically, prior to March 10, 2012, the licensee failed to perform seat leakage testing for valves BG8546A, BG8645B, BNHV8806A, BNHV8816B, BNLCV112E, BNLCV112D, EJ8958A, EJ8958B, EM8926A, EM8926B, ENV3, and ENV9 to demonstrate that their seat leakage would limit post-LOCA dose to control room operators as required by the plant design. Because this finding is of very low safety significance and was entered into the licensee corrective action program as condition reports 46927, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2012002-02, Failure to Test ASME O&M Code Category A Valves in Post-LOCA Flow Path.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a.

The inspectors performed a review of the performance indicator data submitted by the licensee for the 4th Quarter 2011 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

Inspection Scope

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b.

No findings were identified.

Findings

.2 Unplanned Scrams per 7000 Critical Hours (IE01)

a.

The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical hours performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6.

The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 1, 2011, through December 31, 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned scrams per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.3 Unplanned Power Changes per 7000 Critical Hours (IE03)

a.

The inspectors sampled licensee submittals for the unplanned power changes per 7000 critical hours performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 1, 2011, through December 31, 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned transients per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.4 Unplanned Scrams with Complications (IE04)

a.

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 1, 2011, through December 31, 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned scrams with complications sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a.

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 that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness Inspection Scope

of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

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.

No findings were identified.

Findings

.2 Daily Corrective Action Program Reviews

a.

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

Inspection Scope

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b.

No findings were identified.

Findings

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000482/2010006-00, Manual Reactor Trip due to Trip

of Main Feedwater Pump On March 8, 2010, while at 42 percent power, main feedwater pump A tripped. Control room operators manually tripped the reactor due to the decreasing steam generator levels. All control rods fully inserted and the reactor trip system and the engineered safety feature systems performed as expected. The licensee determined the cause of the main feedwater pump trip was a failed servo in the main feedwater control circuitry.

There were no adverse effects on the health and safety of the public.

In addition to this licensee event report (LER), the inspectors noted three other recent LERs reporting failures of main feedwater that caused reactor trips. LER 2009-001-00 described a reactor trip due to a main feedwater regulating valve closure in response to failures of the primary and secondary fuses for the Westinghouse 7300 control card frame that contained the associated control cards for the main feedwater regulating valve. LER 2010-005-00 described a reactor trip due to a trip of a main feedwater pump caused by the failed transfer of an inverter to its alternate power supply. LER 2011-007-

00 described a reactor trip due to failure of controller cards to main feedwater pump B turbine control system.

The inspectors noted the previous failures related to main feedwater could affect the maintenance rule status of the system. The issue of not monitoring the main feedwater pumps was previously discussed in NCV 05000482/2011002-03, Failure to Monitor the Performance of Nonsafety-Related Systems and Components Used in the Plant Emergency Operating Procedures under 10 CFR 50.65 Programs. The inspectors were also informed that this system was subsequently placed in maintenance rule (a)(1)status. The licensee intends to upgrade the control system in the future. Based on the licensee actions, this LER is closed.

.2 (Closed) LER 05000482/2010-11-00, Completion of a Technical Specification Required

Shutdown due to an Essential Service Water Leak On October 2, 2010, the licensee saw indications of water leakage from a buried portion of essential service water system train A piping. The licensee declared train A inoperable and entered Technical Specifications 3.7.8 and 3.8.1. Workers excavated the soil and found a through-wall leak in the pipe. The leakage could not be fixed within the allowed outage time of the technical specifications so the plant was shutdown to Mode 5. The cause of the through-wall leak was internal diameter initiated pitting, which the licensee repaired by encapsulating the pitted area with a cap welded on the outside of the pipe.

Subsequent engineering evaluation of the through-wall leak concluded that the pipe possessed sufficient structural integrity to endure all design loadings and that the system was capable of performing its design safety function. The licensee has initiated plans to replace this pipe to preclude these problems. The licensee planned to replace the buried pipe and was in the process of procuring the pipe and scheduling the work. The schedule showed work beginning in 2012 and actually placing the new pipe into service in 2013.

The licensee was monitoring the pipe wall thicknesses and leaks, and initiated repairs when necessary. Based on the licensees current monitoring and repair of the essential service water pipe and future replacement, this LER is closed.

.3 Reactor Trip from 100 Percent Power and Complete Loss of Offsite Power

a. Inspection Scope

.

On January 13, 2012, the inspectors responded to the announcement of a reactor trip and entered the control room at 2:08 p.m. The inspectors reviewed emergency action levels, examined control boards for system responses, reviewed the emergency plan declaration and notification, and observed operator performance and emergency operating procedure implementation. The inspectors contacted NRC management through the headquarters operations officer to convey plant status. The inspectors walked down the auxiliary feedwater system and emergency diesel generators. The inspectors performed a containment walkdown with Wolf Creek personnel and identified

an essential service water leak on containment cooler C. The inspectors observed control room operators until the low pressure safety injection signal was blocked during cooldown. Over the next several days, the inspectors observed portions of the plant cooldown. The inspectors walked down door breaches and fire impairments due to temporary power cables being used from many temporary power generators to plant equipment. Issues discovered by the inspectors and Wolf Creek during the event were turned over to an Augmented Inspection Team, which documented its inspection in NRC Inspection Report 05000482/2012-008 (ADAMS Accession No. ML12095A414).

b. Findings

.

Regulatory conclusions will be drawn in the Augmented Inspection follow-up team in Inspection Report 05000482/2012-009.

.4 Loss of Offsite Power to Non-Vital 13.8kV bus PA01.

a. Inspection Scope

.

At 5:23 a.m., on January 24, 2012, Wolf Creek experienced a non-vital power loss to 13.8kV bus PA01. Bus PA02 was out of service for troubleshooting of the cause of the January 13, 2012 loss of offsite power at this time. Wolf Creek had been placed in a back-feed electrical alignment in which power is supplied to bus PA01 through the unit auxiliary transformer during shutdown. The inspectors responded to the control room, reviewed residual heat removal and component cooling water strip charts, and interviewed the dayshift control room operators. The inspectors toured the emergency diesel generator spaces to view the starting air tank local pressure indications and looked for unidentified leaks. The inspectors interviewed off-shift rector operators and clearance order personnel who were had the task to restore power. Vital safety buses were unaffected because they were being supplied by a different transformer. The inspectors observed portions of power restoration to bus PA01.

b. Findings

.

Introduction.

Inspectors identified a non-cited violation of Technical Specification 5.4.1.a, Procedures, for implementation of an unauthorized modification by using a clearance order and a temporary procedure. This left the power source to a temporary protective relay unprotected. When another clearance order was being placed, the relay power source was lost and tripped offsite power to all nonvital busses.

Description.

During power operations, power is supplied to the non-safety 13.8kV busses PA01 and PA02 by the unit auxiliary transformer through the main generator transformers. During planned refueling outages, the main generator disconnects are removed and power is supplied to buses PA01 and PA02 by the unit auxiliary transformer through the main generator transformers. This alignment during refueling outages is known as a back-feed alignment.

On January 13, 2012, Wolf Creek experienced a loss of offsite power and a forced outage. Normally, Wolf Creek would implement a back-feed alignment using Procedure SYS MA-120, but because the PA buses were already de-energized, Wolf Creek created temporary Procedure TMP 12-001 based on Procedure SYS MA-120.

Procedure TMP 12-001 used additional instructions to re-energize PA01 on January 17, 2012. The main transformers were being supplied through breaker 345-50 in the switchyard. Both procedures SYS MA-120 and TMP 12-001 used clearance orders to establish the electrical alignment by removing potential transformer fuses, installing jumper wires and temporary equipment, and removing the connectors between the main generator and the main transformers. The temporary equipment that was installed consisted of a relay and transformer for ground fault protection. The power source for the relay and transformer was temporarily derived from turbine test switch at panel MA104C which derives its power supply from potential transformer fuses.

On January 24, 2012, Wolf Creek was in cold shutdown with PA01 energized and supplying all non-vital loads, and PA02 de-energized. Operators hung clearance order, F-AC-N-001 to allow testing of the main generator stator using a generic clearance order for the main generator. This required removing the fuses that powered the temporary transformer and relay for the back-feed alignment. At 5:23 a.m. when the fuses were removed, a false ground fault was detected when the temporary relay de-energized.

This caused breakers 345-50 and PA101 to open, and all bus PA01 loads were de-energized. Safety buses were unaffected as they were both cross-tied and supplied by the No. 7 transformer, which was not part of the back-feed alignment.

When bus PA01 was deenergized, power was lost to electric fire pump, jockey (keep full) fire pump, service water pumps B and C, circulating water pumps A and B, emergency diesel generator starting air compressors, transformer XNB01 cooling fans, heat tracing, auxiliary boiler steam heating for external tanks, the condensate storage tank makeup pump, and the refueling water storage tank makeup pump. Control room operators manually started the safety-related essential service water pumps. The train A residual heat removal and component cooling water systems were providing reactor decay heat, and the temperature in these systems increased about 1°F and 14°F, respectively, before essential service water was started.

In response to this maintenance error, Wolf Creek issued a stop work order throughout the plant. A stand-down meeting with all employees was used to discuss the cause of the event. The stop work order continued until nonvital power was restored throughout the plant. Most power restoration was completed by the afternoon of January 24, with all power restoration completed at about 5 p.m. on January 25, 2012.

Wolf Creek subsequently initiated condition report 48182. The apparent cause noted that the field team electrician and operations clearance order tagging person discussed the steps for removal of the fuses with the electrical maintenance field oversight and also questioned the process with the control room personnel before moving forward. The temporary transformer and relay were not shown on any drawing, and TMP 12-001 was not reviewed prior to removing the fuses. Wolf Creek evaluators subsequently concluded that removal of the fuses was not necessary for the planned work, but

personnel had decided to use the guidance in the generic main generator clearance order anyway. The generic clearance order is normally used during outage periods for work on the generator, but it is not used with the plant in a back-feed alignment. Wolf Creek cause evaluators determined that some operators knew that a temporary transformer and relay were placed in-service per the TMP 12-001, but did not know that the fuses in question were used to power them. The temporary transformer and relay were installed by meter and relay personnel, and operators were not involved in that part of the procedure. Wolf Creek apparent cause evaluators concluded that the primary cause of this error was an inadequate clearance order.

The inspectors reviewed procedure AP 21E-001, Clearance Orders, revision 29A, and determined that it was intended to ensure personnel and equipment protection from energy sources, but did not clearly state that plant configuration control is a primary purpose, contrary to typical industry practice. The procedure only describes modifications in terms of clearance orders that are left in place for more than 60 days.

The inspectors determined that under Procedure AP 05-005, Design Control, revision 18, the 13.8kV buses are subject to the same design control process as safety-related equipment. TMP 12-001 caused a configuration change to the turbine trip panel to be used for a modified purpose during the back-feed alignment, but the design control process and temporary modification process were not implemented. Specifically:

• TMP 12-001 did not specify changes to controlled plant drawings to show the temporary configuration to allow operators and tagging personnel to understand the temporary configuration.

• The changes to the system involved the installation of jumpers, a temporary transformer, and temporary relay, as well as the removal of potential transformer fuses, which met the definition of a temporary modification per procedure AP21I-001, Temporary Modifications, revision 8A.

• The inspectors that procedure AP 21I-001 included examples of temporary modifications that included lifting leads and installing jumper wires. The inspectors concluded removing fuses for potential transformers are the same as lifting leads.

The inspectors concluded that clearance order F-AC-N-001 made changes to the 345kV and 13.8kV protective relaying outside of the design control Procedure AP 05-005 which led to the January 24 event.

The inspectors reviewed the document revision request that generated Procedure TMP 12-001 and the process for procedure changes, AP 15C-004, Preparation, Review and Approval of Procedures, Instructions and Forms, revision 40A. The inspectors concluded that the technical review for TMP 12-001 was inadequate because:

• Technical reviewers (operations procedure writers, licensed operators, and one engineer) failed to recognize that the procedure was a temporary modification.

• Reviewers failed to noted that the change was not consistent with the USAR, and failed to perform the specified technical evaluation.

• Reviewers failed to recognize that the setpoints in the procedure did not have a technical basis or evaluate whether the setpoint would affect the plant design.

• AP 15C-004, step 6.2.7, stated that a subject matter expert may be required for changes involving lifting leads or altering electrical circuits. In such cases, AP 15C-004, Attachment F invokes discipline specific mandatory reviews. However, no discipline specific, quality control department, or subject matter expert review was obtained.

The inspectors found that there was no previous technical basis for any of these aspects. The inspectors concluded that contrary to the requirements in Attachment E, that the technical reviewers did not verify the technical adequacy of TMP 12-001.

Corrective actions included training reactor operators on the back-feed alignment, adding tags to the fuse block, and adding notes to the clearance order software not to remove these fuses.

The inspectors reviewed the licensees apparent cause evaluation results and interviewed the apparent cause evaluator, and concluded that the apparent cause evaluation had not considered whether the system changes should have been done using a modification process. As a result, corrective actions did not address procedure changes to prevent unapproved modifications, to create a modification for the temporary equipment, to update drawings, or to evaluate the relay setpoints. The Wolf Creek cause evaluator stated all available revisions of SYS MA-120 were reviewed back through microfiche, but no modification documentation was found. The inspectors concluded that the apparent cause and associated corrective actions were not adequate because they did not address the lack of configuration control. The inspectors concluded that value was added to the issue such that the performance deficiency was NRC-identified.

The apparent cause evaluation re-assigned the extent of condition review to condition report 48642. Also, after inspector questions, Wolf Creek initiated condition report 51408 to evaluate adequacy of the permanent and temporary back-feed alignment procedures. Wolf Creek also blocked the use of the temporary procedure and procedure SYS MA-120 until further evaluation was completed.

Analysis.

Failure to control system configuration such that unplanned loss of power would not occur is a performance deficiency. The inspectors determined that this finding was more than minor because it impacted the Mitigating Systems Cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, it impacted the configuration control attribute of shutdown equipment lineup. The inspectors evaluated the loss of service water pumps B and C, circulating water pumps A and B, vital air conditioning units, emergency diesel generator starting air compressors, transformer XNB01 cooling fans, heat tracing, auxiliary boiler steam heating, the condensate storage tank makeup pump, and the refueling water storage

tank makeup pump using Inspection Manual Chapter 0609, Attachment G, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs, checklist 4 (inventory in the pressurizer, time to boil >2 hours). The inspectors screened the finding to Green or very low safety significance because it did not involve a loss of reactor coolant system inventory, did not affect reactor coolant system level instrumentation, did not affect the licensees ability to terminate a leak path, did not affect the licensees ability to add reactor coolant system inventory when needed, or degrade the licensees ability to recover decay heat removal once it was lost.

Additionally, the inspectors screened the loss of the electric fire pump and jockey (keep full) fire pump to Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings. Specifically, these pumps were out of service for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and therefore screened to Green or very low safety significance. The inspectors identified that the cause of the finding had a cross-cutting aspect in the resources area of human performance because the loss of power was caused by a lack of complete, accurate and up-to-date design documentation, procedures, drawings, fuse labeling, and work orders necessary to support the temporary configuration established through TMP 12-001 H.2.c].

Enforcement.

Technical Specification 5.4.1.a, Procedures, requires, in part, that procedures be established, implemented, and maintained for the activities listed in Appendix A to Regulatory Guide 1.33, revision 2, February 1978. Regulatory Guide 1.33 revision 2, Appendix A, Section 1.c, 1.d, and 1.e, require, in part, that procedures for equipment control, temporary change methods, and procedure review and approval, respectively.

a. Wolf Creek Procedure AP 21I-001, Temporary Modifications, revision 8A implements Regulatory Guide 1.33, Appendix A, Sections 1.c and 1.d. Procedure AP 21I-001, step 4.6, and Attachment A require, in part, that a technical basis and an update of essential drawings be provided for those systems listed in procedure AP 05-05, Design Control, revision 18, including the 13.8kV distribution system. Lifting leads and installing jumper wires are provided as examples of temporary modifications in Procedure AP 21I-001.

Contrary to the above, on January 17, 2012, Wolf Creek failed to implement Procedure AP 21I-001, step 4.6, and Attachment A. Specifically, potential transformer fuses were removed, jumper wires were installed, a transformer was installed, and a ground protection relay was installed to support the back-feed alignment without completing the evaluation or modification of essential plant drawings.

b. Procedure AP 15C-004 implements Regulatory Guide 1.33, Appendix A, Section 1.e.

Steps E.1.3.8, E.1.3.11, and E.1.3.15 require, in part that there is consistency with the USAR, a technical evaluation been established, and setpoints have a technical basis. Step 6.2.7 requires subject matter expert review for lifting electrical leads and invokes Attachment F for that review.

Contrary to the above, on January 15, 2012, Wolf Creek failed to follow Procedure AP 15C-004, steps E.1.3.8, E.1.3.11, and E.1.3.15, 6.2.7, and failed to utilize Attachment F for Procedure TMP 12-001. Specifically, Wolf Creek failed to implement subject matter expert review in Attachment F even though Procedure TMP 12-001 had instructions to remove fuses, place jumper wires, install a temporary transformer, and install a temporary relay. Additionally, technical reviewers failed to implement Attachment E, steps E.1.3.8, E.1.3.11, and E.1.3.15 to establish the technical basis for the procedure.

Because this finding is of very low safety significance and was entered into the licensee corrective action program as condition reports 48182, 48642, and 51408, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000482/2012002-03, Loss of Configuration Control Causes Loss of All Non-Vital Power.

.4 Partial Loss of Offsite Power

a. Inspection Scope

.

At 8:08 p.m. on February 13, 2012, with the unit in cold shutdown with a water filled pressurizer, operators attempted to restart reactor coolant pump A for the first time since the startup transformer was returned to service following the loss of offsite power on January 13, 2012. The startup transformer experience a phase B differential current protective relay actuation leading isolation of the west 345kV bus. This was essentially a repeat of the startup transformer isolation that occurred on January 13, 2012. Although the transformer had been energized for days, when the coolant pump motor start inrush current drew from the transformer, the phase B differential current protective relay actuated again to isolate the transformer from the west 345kV bus. This caused a loss of offsite power to non-safety plant loads as well as safety bus B. A blackout condition existed for the train B safety related electrical power because the emergency diesel generator B was out of service for corrective maintenance at the time. Train A offsite power was unaffected because it was being supplied by the east 345kV bus through the No. 7 transformer. The inspectors responded to the control room upon notification from Wolf Creek. The inspectors reviewed control room strip charts, interviewed control room operators, and interviewed outage control center personnel regarding power restoration.

The reactor was being cooled by train B at the time and reactor coolant system temperature rose five degrees before operators manually aligned reactor cooling through train A 3 minutes later. Corresponding pressure increases of 100 psig also occurred and the pressure increase was arrested by lifting of the residual heat removal safety valves at 435 psi. Control room, auxiliary building, and fuel building ventilation isolations occurred as designed. Electrical power to the train B safety-related bus was not restored until 8:56 p.m. when buses A and B were cross-tied as allowed by technical specifications for reactor cold shutdown conditions. The inspectors responded to the site where they reviewed available strip chart data for reactor coolant pump A. The inspectors interviewed Wolf Creek cause evaluators as to the meaning of differentials between phases and possible causes.

.b Findings.

Regulatory conclusions will be drawn in the Augmented Inspection follow-up team in Inspection Report 05000482/2012-009.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 11, 2012, the inspectors presented the inspection results to Mr. M. Sunseri, President and CEO, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC an requirement which meets the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation.

Title 10 of the CFR, Part 50.65(a)(4) requires, in part, that before performing maintenance activities the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Wolf Creek Procedure APF 22B-001, Safety Function Status and Assessment Sumary, revision 3, requires that two or more steam generators have greater than 66 percent wide-range water level to be credited for core decay heat removal risk during Mode 5. Otherwise, the assessment escalates risk due to the absence of one method core decay heat removal. Procedure APF 22B-001 is required to be performed daily. Contrary to the above, on February 6, 2012, the licensee failed to assess risk by identifying entry into a Yellow shutdown risk assessment for core decay heat removal due to three of four steam generators being drained to less than 66 percent wide range level. Specifically, while performing the daily shutdown risk assessment, operators failed to identify that planned work to drain and refill the steam generators for cold wet layup chemistry control was to occur on several steam generators simultaneously. Concurrently, the reactor coolant system power operated relief valves were unavailable for feed and bleed, another method of decay removal. Operators recognized the elevated risk after 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> with three steam generators being drained below 66 percent water level. This finding is more than minor because it is associated with the equipment performance 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 (i.e., core damage). Specifically, operators failed to identify that they had crossed a shutdown risk management threshold, from Green to Yellow.

A Region IV senior reactor analyst verified that the finding was of very low safety significance (Green) and the delta-CDF was less than 1E-6. The licensee has entered this issue into their corrective action program as condition report 48775.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Baban, Manager, Systems Engineering

P. Bedgood, Manager, Radiation Protection

J. Broschak, Vice President, Engineering

R. Clemons, Vice President, Strategic Projects

T. East, Superintendent, Emergency Planning

R. Evenson, Requalification Program Supervisor

R. Flannigan, Manager, Nuclear Engineering

J. Harris, System Engineer

S. Hedges, Site Vice President

S. Henry, Operations Manager

R. Hobby, Licensing Engineer

D. Hooper, Supervisor, Regulatory Affairs

T. Jensen, Manager, Chemistry

T. Just, Senior Technician, Chemistry

J. Keim, Support Engineering Supervisor

S. Koenig, Manager, Corrective Actions

M. McMullen, Technician, Engineering

C. Medency, Supervisor, Radiation Protection

W. Muilenburg, Licensing Engineer

R. Murray, Simulator Supervisor

B. Norton, Manager, Engineering Programs

E. Ray, Manager, Training

L. Ratzlaff, Manager, Maintenance

L. Rockers, Licensing Engineer

R. Ruman, Manager, Quality

G. Sen, Regulatory Affairs Manager

R. Smith, Plant Manager

L. Solorio, Senior Engineer

M. Sunseri, President and Chief Executive Officer

J. Truelove, Supervisor, Chemistry

J. Weeks, System Engineer

M. Westman, Assistant to Site Vice President

R. Zyduck, Manager, Design Engineering

NRC Personnel

C. Long, Senior Resident Inspector

C. Peabody, Resident Inspector

Z. Hollcraft, Callaway Resident Inspector

J. Melfi, Reactor Inspector

G. Callaway, Senior Reactor Technology Instructor

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2012002-01 NCV Inadequate Procedure Causes Lift of Relief Valve and Reactor Coolant Leak During Shutdown (Section 1R20)

05000482/2012002-02 NCV Failure to Test ASME O&M Code Category A Valves in Post-LOCA Flow Path (Section 1R22)

05000482/2012002-03 NCV Loss of Configuration Control Causes Loss of All Non-Vital Power (Section 4OA3.4)

Closed

05000482/2010006-00 LER Manual Reactor Trip due to Trip of Main Feedwater Pump (Section 4OA3.1)

05000482/201011-00 LER Completion of a Technical Specification Required Shutdown due to an Essential Service Water Leak (Section 4OA3.2)