IR 05000528/2012004

IR 05000528-12-004, 05000529-12-004, 05000530-12-004; 07/01/2012 - 09/30/2012, Palo Verde Nuclear Generating Station, Integrated Res. and Region. Report; Adverse Weather. Prot., Fire Prot., Op. Evals Ident., and Res. of Probs; Event Flwp

ML12319A635
Person / Time
Site:	Palo Verde
Issue date:	11/14/2012
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
IR-12-004
Download: ML12319A635 (49)

Text

UNITE D S TATE S NUC LEAR RE GULATOR Y C OMMI S SI ON ber 14, 2012

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2012004, 05000529/2012004, AND 05000530/2012004

Dear Mr. Edington:

On September 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station Units 1, 2, and 3. The enclosed inspection report documents the inspection results which were discussed on October 3, 2012, with R. Bement and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission=s rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Six NRC identified findings of very low safety-significance (Green) were identified during this inspection.

All six of these findings were determined to involve violations of NRC requirements. One of these findings was associated with a traditional enforcement Severity Level IV violation.

Further, licensee-identified violations which were determined to be of very low safety-significance are 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 Palo Verde Nuclear 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 Palo Verde Nuclear 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 accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Ryan Lantz, Chief Project Branch D Division of Reactor Projects Docket Nos.: 50-528, 50-529, 50-530 License Nos.: NPF-41, NPF-51, NPF-74

Enclosure:

Inspection Report 05000528/2012004, 05000529/2012004, and 05000530/2012004 w/ Attachments:

1. Supplemental Information

REGION IV==

Docket: 50-528, 50-529, 50-530 License: NPF-41, NPF-51, NPF-74 Report: 05000528/2012004, 05000529/2012004, 05000530/2012004 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5951 South Wintersburg Road Tonopah, Arizona Dates: July 1 through September 30, 2012 Inspectors: M. Brown, Senior Resident Inspector M. Baquera, Resident Inspector J. Laughlin, Emergency Preparedness Inspector J. Melfi, Project Engineer B. Parks, Project Engineer D. Reinert, Resident InspectorN. Taylor, Senior Project Engineer D. You, Project Engineer Approved Ryan Lantz, Chief, Project Branch D By: Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000528, 529, 530/2012004; 07/01/2012 - 09/30/2012, Palo Verde Nuclear Generating

Station, Integrated Res. and Region. Report; Adverse Weather. Prot., Fire Prot., Op. Evals Ident.,

and Res. of Probs; Event Flwp.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Five Green non-cited violations, one Severity Level IV and two licensee-identified violations 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 crosscutting 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 identified a Green non-cited violation of License Conditions 2.C.7, 2.C.6, and 2.F for Palo Verde Units 1, 2, and 3 for the licensees failure to take timely corrective actions for a condition adverse to fire protection. Specifically, in 2004, the licensee identified that line thermal detection for 13.8 Kilo Volt cabling in three fire areas were not in conformance with vendor technical documents.

Since then, corrective actions for the condition failed to be implemented as scheduled. After several spurious actuations of the fire protection system, the licensee installed the appropriately rated wire in Unit 1 and will install the appropriate detection in Units 2 and 3, respectively, at the next available outage.

The licensee entered this issue into the licensees corrective action program as Palo Verde Action Request (PVAR) 4201472.

The failure to take timely corrective actions for a condition adverse to fire protection was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the protection against external factors of the Initiating Events Cornerstone and its objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding was determined to be a low degradation of the fixed fire protection system and screens to green using step 1.3.1. The inspectors determined this finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to prioritize corrective actions for conditions adverse to fire protection P.1(c) (Section 1R05).

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation of 10 CFR Part 50 Appendix B, Criterion XVI, Corrective Action, for the failure of the licensee to correct a condition adverse to quality. Specifically, on November 7, 2011, after the inspectors notified the licensee about scupper obstruction on safety related building roofs, the licensee failed to enter this issue into the corrective action program and take appropriate corrective actions to remove the obstructions. The licensee rediscovered this condition during post Fukushima walkdowns in response to a Request for Information pursuant to 10 CRF 50.54(f), removed the obstructions and established walkdowns to ensure the scuppers remained unobstructed. The licensee has entered the issue into the corrective action program as PVAR 4255561.

The inspectors concluded that the failure of the licensee to correct a condition adverse to quality was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the protection against external events of the Mitigating Systems Cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initialing events to prevent undesirable consequences. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and 0609 Appendix A, The Significance Determination Process (SDP) for Findings at-Power. The inspectors concluded the finding was of very low safety-significance (Green)because the finding did not result in the complete loss of a safety function due to an external event. The inspectors determined this finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to have a low threshold for entering issues into the corrective action program P.1(a)(Section 1R01).

Green.

The inspectors identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of engineering personnel to follow Procedure 70TI-9ZC01, Boric Acid Walkdown Leak Detection, to provide an adequate evaluation of an active boric acid leak.

Specifically, an evaluation of a boric acid leak from the packing of the charging backpressure header control valve did not assess all consequences of continued operation. The licensee performed a subsequent boric acid leakage evaluation and determined that monitoring coupled with mitigating actions of cleaning and greasing all susceptible components was sufficient to support the functionality of the valve. The licensee will repair the valve at the soonest available opportunity; prior to restart after any maintenance or refueling outage.

The inspectors concluded that the failure of the engineering personnel to provide an adequate evaluation of an active boric acid leak was a performance deficiency.

The performance deficiency was more than minor, and therefore a finding, because if left uncorrected the performance deficiency could possibly become a more significant safety concern in that unevaluated boric acid leaks could result with unmitigated boric acid corrosion of components. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings.

Inspectors determined that the finding affected the Mitigating Systems Cornerstone and using Inspection Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) for Findings at-Power. Inspectors concluded the finding was of very low safety-significance (Green) because the finding is a design or qualification issue confirmed not to result in the loss of operability or functionality. The inspectors determined this finding has a crosscutting aspect in the area of human performance associated with the decision making component because the licensee failed to make conservative assumptions and allowed corrosion of carbon steel components without an appropriate understanding of their function or unintended consequences H.1(b) (Section 1R15).

Green.

The inspectors identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations and engineering personnel to follow station procedures to provide an adequate technical justification for continued operation of a degraded structure, system, or component. After a ventilation damper failed to close during a functional stroke test, plant personnel did not consider previous operability determinations and failed to provide supporting analysis to confirm there was no reduction in reliability of ARD relays. This issue is captured in the corrective action program as PVAR 4255816. The licensee has successfully cycled all ARD relays which could be performed during at-power operations, scheduled testing for remaining relays, and initiated a design change document that will determine a permanent substitute for the ARD660UR DC relays.

The failure of the operations and engineering personnel to follow Procedure 40DP-9OP26 to evaluate the operability of a structure, system, or component was a performance deficiency. The inspectors concluded the performance deficiency was more than minor because it affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and 0609 Appendix A, The Significance Determination Process (SDP) for Findings at-Power. Inspectors concluded that the finding was of very low safety-significance (Green) because the finding is not a design or qualification issue, did not represent an actual loss of safety function of the system or train, did not result in the loss of one or more trains of non-technical specification equipment, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that the finding has a cross-cutting aspect in the area of human performance associated with decision making. Specifically, the licensee did not communicate the results of the apparent cause evaluation for the first three ARD relay failures to the appropriate operations personnel H.1(c) (Section 1R15).

Cornerstone: Emergency Preparedness

• SL-IV. Inspectors identified a Severity Level IV, non-cited violation of 10 CFR 50.54 (q), Conditions of licenses, and an associated Green finding for the licensees failure to perform an appropriate design scope change, which resulted in the reduction in effectiveness of the emergency plan. Specifically, on May 19, 2011, the licensee completed a modification to revise protective area lightning power sources and removed ground fault protections on a circuit breaker attached to the bus, which powers the technical support center. This change created a condition that would remove power to the technical support center and prevent emergency plan required back up power from being able to power the bus. On August 10, 2012, a lighting fault caused a complete loss of power to the technical support center, demonstrating that this change decreased the effectiveness of the emergency plan. On September 26, 2012, the licensee reactivated the ground fault protection for the circuit breaker and established compensatory measures to restore power to ensure technical support center staffing will not be challenged.

The licensee entered this into their corrective action program as condition report disposition request 4230209.

The failure to perform an appropriate design scope change was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the facilities and equipment attribute of the Emergency Preparedness Cornerstone and its objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process. The finding was determined to be of very low safety significance (Green). Additionally, the violation of 10 CFR 50.54 (q) impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. This violation was determined to be a Severity Level IV violation per Section 6.6 of the NRC Enforcement Policy because the violation was not associated with licensees ability to meet or implement any regulatory requirement related to assessment or notification. Although the regulatory requirement could be implemented during the response to an actual emergency, the implementation would be degraded. The inspectors determined this finding has a crosscutting aspect in the area of human performance associated with the work practices component because the licensee failed to ensure supervisory management and oversight of contractors such that nuclear safety is supported [H.4.(c)] (Section 4OA2).

Green.

The inspectors identified a Green non-cited violation of 10 CFR 50.54(q)for the failure of operations personnel to adequately implement the emergency plan. Specifically, on August 26, 2012, auxiliary operators felt vibratory ground motion inside the protected area at 12:31pm and again at 1:58pm. The United States Geological Survey (USGS) confirmed that two earthquakes, of magnitude 5.3 and 5.5 respectively, occurred at those times in the area of the plant. Plant operators did not declare an Unusual Event in accordance with the emergency plan. The licensee entered the issue into the corrective action program as PVAR 4255819 and initiated an apparent cause evaluation to identify the cause and corrective actions.

The failure to implement the emergency plan and declare an Unusual Event was a performance deficiency. The performance deficiency was more than minor and therefore a finding, because it affected the Emergency Response Organization performance attribute of the Emergency Preparedness cornerstone and affected the cornerstone objective to ensure the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Using Manual Chapter 0609, Appendix B, "Emergency Preparedness Significance Determination Process," Attachment 1, the finding was determined to have very low safety - significance (Green) because the actual event implementation problem was associated with an Unusual Event. This finding has a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure training of personnel was adequate to assure proper implementation of the emergency plan [H.2.(b)]

(Section 4OA3).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full power during the inspection period.

Unit 2 operated at essentially full power until September 15, 2012 when the unit began a planned reduction in power in preparation for refueling outage 2R17.

Unit 3 operated at essentially full power until July 4, 2012, when the unit experienced a main turbine trip and reduced power to approximately 10 percent. The unit returned to essentially full power on July 7, 2012 and remained there until July 30, 2012, when unit reduced power to approximately 81 percent to address a condenser tube leak. The unit returned to full power on August 4, 2012 and remained there for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of the adverse weather procedures for seasonal extremes (e.g., extreme high temperatures, extreme low temperatures, or hurricane season preparations). The inspectors verified that weather-related equipment deficiencies identified during the previous year were corrected prior to the onset of seasonal extremes and evaluated the implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of, and during, the adverse weather conditions.

During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions.

Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that plant personnel were identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

• July 30, 2012, Unit 1, Unit 2, and Unit 3, normal and essential ventilation system readiness for seasonal extreme temperatures These activities constitute completion of one readiness for seasonal adverse weather sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for August 23, 2012, the inspectors reviewed the plant personnels overall preparations/protection for the expected weather conditions. On August 23, 2012, the inspectors walked down each units essential spray pond system because their functions could be affected, or required, as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the plant staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the UFSAR and performance requirements for the system selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of corrective action program items to verify that the licensee-identified adverse weather issues at an appropriate threshold and dispositioned them through the corrective action program in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one readiness for impending adverse weather condition sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.3 Readiness to Cope with External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the UFSAR for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable.

Additionally, the inspectors performed an inspection of the protected area to identify any modification to the site that would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one external flooding sample as defined in Inspection Procedure 71111.01-05.

b. Findings

Failure to Correct Scupper Obstruction

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure of the licensee to correct a condition adverse to quality. Specifically, on November 7, 2011, after the inspectors notified the licensee about scupper obstruction on safety related building roofs, the licensee failed to enter this issue into the corrective action program and take appropriate corrective actions to remove the obstructions. The licensee later re-discovered this condition during post-Fukushima walkdowns in response to an NRC Order, entered the issue into the corrective action program, removed the obstructions, and established walkdowns to ensure the scuppers remained unobstructed.

Description.

On November 7, 2011, inspectors performed walkdowns of safety related building roofs in response to an issue of concern associated with the drainage capabilities of the structures. During these inspections, as documented in Palo Verde Inspection Report 2012002, Section 4OA2, inspectors identified a hose obstructing a scupper utilized for the auxiliary building roof drainage in Unit 3. This hose was in place to pump rainwater from the tendon gallery area adjacent to containment to the drainage system. Inspectors alerted operations personnel to the condition. The licensee corrected the condition for Unit 2 but failed to address Unit 1 and Unit 3. The issue of obstruction to the scuppers was not entered into the corrective action program after the licensee was made aware of the concern by inspectors.

As part of the request for information pursuant to 10 CRF 50.54(f), regarding recommendations Section 2.3 of the Near-Term Task Force review of the Fukushima Dai-ichi accident, dated March 12, 2012, the licensee performed flooding walkdowns to verify that plant features credited in the current licensing basis for protection and mitigation from external flood events are available, functional, and properly maintained. During these walkdowns, on August 28, 2012, the licensee identified hoses obstructing suppers identical to the condition previously identified by inspectors. This issue was entered into the licensees corrective action program as PVAR 4255561. The roof drainage capabilities are identified as degraded as documented in Palo Verde inspection Report 2012002, Section 4OA2. The operability determination verified that the buildings would not collapse due to further inundation to an already degraded system.

The licensee removed the obstructions and established walkdowns to ensure the scuppers remain unobstructed.

Analysis.

The inspectors concluded that the failure by the licensee to correct a condition adverse to quality was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the protection against external events attribute of the Mitigating Systems Cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initialing events to prevent undesirable consequences. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and 0609 Appendix A, The Significance Determination Process (SDP) for Findings at-Power. The inspectors concluded the finding was of very low safety-significance (Green) because the finding did not result in the complete loss of a safety function due to an external event. The inspectors determined this finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to have a low threshold for entering issues into the corrective action program P.1(a).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that conditions adverse to quality such as failure, malfunctions, deficiencies, deviations, defective material, and equipment nonconformances are promptly identified and corrected. Contrary to the above, from November 7, 2011, through August 28, 2012, operations personnel failed to correct a condition adverse to quality.

Specifically, operations personnel failed to correct a scupper obstruction, which negatively affected the drainage capability of the safety related building roofs, after inspectors alerted them to the condition. The licensee rediscovered this condition during post-Fukushima walkdowns in response to a Request for Information pursuant to 10 CRF 50.54(f),removed the obstructions and established walkdowns to ensure the scuppers remain unobstructed. Because this finding is of very low safety-significance and has been entered into the licensees corrective action program as PVAR 4255561, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000528; 529; 530/2012004-01, Failure to Correct Scupper Obstruction.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

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

• July 26, 2012, Unit 2, main steam system

• August 1, 2012, Unit 1, train B essential cooling water system

• August 8, 2012, Unit 3, train B containment spray system 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, UFSAR, 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. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Inspection Tours

a. Inspection Scope

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:

• July 12, 2012, Unit 2, control building, all elevations

• August 2, 2012, Unit 2, auxiliary building, 70 and 120 elevations

• August, 13, 2012, Unit 1, main steam support structure, all elevations

• August, 13, 2012, Unit 1, spray pond pump house, all elevations

• August, 13, 2012, Unit 2, spray pond pump house, all elevations 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. Findings

Untimely Corrective Action for Condition Adverse to Fire Protection

Introduction.

The inspectors identified a Green non-cited violation of License Conditions 2.C.7, 2.C.6, and 2.F for Palo Verde Units 1, 2, and 3 for the licensees failure to take timely corrective actions for a condition adverse to fire protection. Specifically, in 2004, the licensee identified that line thermal detection for 13.8kV cabling in three fire areas were not in conformance with vendor technical documents. The licensee did not implement corrective actions as scheduled and failed to provide justification for deferral.

Description.

During the inspectors regular attendance at plan of the day meetings, operations personnel discussed an issue of concern associated with fire protection impairments on July 12, 2012. Inspectors interviewed operations and fire protection personnel and determined that spurious actuations of fire protection valves in three fire areas occurred in all three units. The areas included power cabling for reactor coolant pumps and auxiliary feed water cables. During the actuations, the licensee had one hour to establish a fire watch and restore the panel to a functional condition. After restoration, ionization detectors were available as a backup detection system. Inspectors challenged the extent of condition review performed and the licensee assessed the issue under condition report disposition request 4207273. The licensee determined that the issue was caused by in line thermal detection wire for 13.8kV cabling that did not meet vendor specifications for the environment it was subjected to. The set point temperature for this detection wire was rated at 155°F, cable tray ambient temperatures are approximately 120°F, while the design documentation required a minimum rating of 190°F. The licensee determined that this issue was being adequately addressed by condition report disposition request 2731514 which implemented a modification to replace all affected thermal detection wire with the appropriate rating. The modification was scheduled to be implemented in 2006. There was no documented justification for any delay in implementation. In 2009 the modification received engineering review and was being prepared for implementation. The modification was scheduled as a refueling outage activity but was removed and was removed from the upcoming Unit 2 2R17 outage until inspectors alerted the licensee to the condition. The modification was then scoped back into the upcoming Unit 2 2R17 outage in October 2012 and will be implemented for all other affected areas at the next available opportunity.

Analysis.

The inspectors concluded that the failure to take timely corrective actions for a condition adverse to fire protection was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the protection against external factors attribute of the Initiating Events Cornerstone and its objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process.

The finding was determined to be a low degradation of the fixed fire protection system and screened to Green using step 1.3.1. The inspectors determined this finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to prioritize corrective actions for conditions adverse to fire protection P.1(c).

Enforcement.

Arizona Public Services Palo Verde Nuclear Generating Station License Conditions 2.C.7, 2.C.6, and 2.F for Units 1, 2, and 3 respectively, state, in part, that APS shall implement and maintain in effect all provisions of the approved fire protection program as described in the UFSAR for the facility, as supplemented and amended, and as approved in the Safety Evaluation Report through Supplement 11. The UFSAR, Revision 16, Section 17.2F.1.3.2.9, states in part, that conditions adverse to fire protection, such as failures, malfunctions, deficiencies, deviations, defective components uncontrolled combustible material and nonconformances are promptly identified, reported, and corrected. Contrary to the above, from September 23, 2004, through August 3, 2012, the licensee failed to promptly correct a condition adverse to fire protection. Specifically, in 2004, the licensee identified that line thermal detection for 13.8kV cabling in three fire areas were not in conformance with vendor technical documents. Since then corrective actions for the condition failed to be implemented as scheduled. After several spurious actuations of the fire protection system, the licensee has since installed the appropriately rated wire in Unit 1 and will install the appropriate wire in Units 2 and 3, respectively, at the next available outage. Because this finding is of very low safety-significance and has been entered into the licensees corrective action program as PVAR 4201472, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000529; 530/2012004-02, Untimely Corrective Action for Condition Adverse to Fire Protection.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the UFSAR, 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.

• August 29, 2012, Unit 3, auxiliary building, 40 and 51 elevation These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On August 22, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification training. The inspectors assessed the following areas:

• Licensed operator performance

• The ability of the licensee to administer the evaluations

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

• Follow-up actions taken by the licensee for identified discrepancies These activities constitute completion of one quarterly licensed operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On August 16, 2012, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity due to containment spray inservice testing. The inspectors observed the operators performance of the following activities:

• Surveillance testing including the pre-job brief In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of shift operations and other operations department policies.

These activities constitute completion of one quarterly licensed-operator performance sample as defined in Inspection Procedure 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:

• August 20, 2012, Unit 1, Unit 2, and Unit 3, ARD relays

• August 22, 2012, Unit 1, low pressure safety injection train A, containment spray train A, and shutdown cooling train A The inspectors reviewed events such as where ineffective equipment maintenance has 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)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(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 corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two quarterly maintenance effectiveness sample as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• August 8, 2012, Unit 2 main steam isolation valve 180 air hydraulic pump and four-way valve replacement following pump failure

• August 20, 2012, Unit 1and Unit 3 ARD relay extent of condition testing following failed surveillance test

• September 11, 2012, Unit 2, train A emergency diesel generator, emergency cooling water, emergency chilled water, and safety injection systems outage for planned maintenance 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 three maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following assessments:

• July 2, 2012, Unit 1, diesel generator B failed to manually shutdown following surveillance testing

• July 16, 2012, Unit 1, Unit 2 and Unit 3, Limitorque Fiberite switch material changes

• July 24, 2012, Unit 3, elevated iron during particulate sample of containment atmosphere

• July 25, 2012, Units 1, 2, and 3, seismic restraint for control building bookcase not as per approved detail drawing

• July 27, 2012, Unit 1 and Unit 3, containment concrete degradation

• July 30, 2012, Unit 2, containment dome concrete degradation

• August 8, 2012, Units 1, 2, and 3, possible site flooding due to spoils pile in east wash

• August 17, 2012, Unit 2, ARD relay failure operability determination

• September 28, 2012, Unit 3, emergency diesel generator B alarms during surveillance testing 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 UFSAR 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 nine operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

.1 Inadequate Boric Acid Evaluation

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of engineering personnel to follow procedure 70TI-9ZC01, Boric Acid Walkdown Leak Detection, to provide an adequate evaluation of an active boric acid leak. Specifically, an evaluation of a boric acid leak from the packing of the charging backpressure header control valve did not assess all consequences of continued operation.

Description.

On March 17, 2012, at the beginning of the Unit 3 refueling outage, inspectors and engineering personnel performed a walkdown in containment to identify components that may be leaking. During the activity, inspectors noted valve CHV-240 had obvious signs of leakage and corrosion, as denoted by rust-colored boric acid deposits.

Procedure 70TI-9ZC01, Boric Acid Walkdown Leak Detection, requires an evaluation of any leaks that have evidence of corrosion and denoted by red or rust-colored boric acid deposits. This procedure requires that if the leakage requires an evaluation, the evaluation must include all susceptible components, describe adequate acceptance criteria for each surface, assess consequences of continued operation, and identify actions that are necessary to prevent a susceptible material from contacting boric acid.

When restarting the unit from the refueling outage on April 12, 2012, the licensee discovered that the leak became worse after the packing adjustment, becoming an active leak. Subsequent attempts to tighten the packing on the valve failed to restrict further leakage. The licensee made a decision to proceed with start up with the valve in this degraded condition and defer maintenance of the identified boric acid leakage item to a future date.

A boric acid leakage evaluation was completed on June 7, 2012. Through the evaluation, the licensee instituted a monitoring program to assess the degraded valve, including containment entries. High iron content in containment radiation monitors alerted the licensee to an increase in corrosion of carbon steel components in containment. The containment entry made to assess the condition inspected for other sources of iron particulate but failed to clean the boric acid deposits. The licensee gathered an interdisciplinary group to address NRC concerns with the continued operation of CHV-240.

During these discussions the licensee became aware that the boric acid leakage evaluation completed on June 7, 2012, did not identify all susceptible materials; adequately identify function of all components; describe adequate acceptance criteria for each surface and; identify actions that are necessary to prevent a susceptible material from contacting boric acid. As such, susceptible components that could render the valve nonfunctional were allowed to corrode unmitigated. The licensee revised the evaluation and decision-making issue, as appropriate, to support monitoring of the degraded condition and continued functionality of the valve. The licensee will repair the valve at the soonest available opportunity and prior to restart after any maintenance or refueling outage.

Analysis.

The inspectors concluded that the failure of the engineering personnel to provide an adequate evaluation of an active boric acid leak was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected the performance deficiency could possibly become a more significant safety concern in that unevaluated boric acid leaks could result in unmitigated boric acid corrosion of components. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings. Inspectors determined that the finding affected the Mitigating Systems Cornerstone and using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at-Power. Inspectors concluded the finding was of very low safety-significance (Green) because the finding is a design or qualification issue confirmed not to result in the loss of operability or functionality. The inspectors determined this finding has a crosscutting aspect in the area of human performance associated with the decision making component because the licensee failed to obtain an interdisciplinary review of safety-significant decisions resulting with components not being identified and needing evaluation H.1(a).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure 0TI-9ZC01 Boric Acid Walkdown Leak Detection, Revision 12, provided guidelines and instructions for evaluating boric acid corrosion. Appendix C, Step 3.2 states, in part, to identify acceptable acceptance criteria for each surface.

Contrary to the above, from June 7, 2012, through August 3, 2012, engineering personnel failed to accomplish an activity affecting quality in accordance with the prescribed instructions, procedures, and drawings. Specifically, plant personnel failed to follow Procedure 70TI-9ZC01 and provide an evaluation for active boric acid leakage that provided acceptable acceptance criteria for each surface affected by boric acid corrosion.

The licensee performed a subsequent boric acid leakage evaluation and determined that monitoring coupled with mitigating actions of cleaning and greasing all susceptible components were sufficient to support the functionality of the valve. Because this finding is of very low safety-significance and has been entered into the licensees corrective action program as PVAR 4219791, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000530/2012004-03, Inadequate Boric Acid Evaluation.

.2 Inadequate Operability Determination for ARD Relay Reduction in Reliability

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations and engineering personnel to follow station procedures to provide an adequate technical justification for continued operation of a degraded structure, system, or component. Specifically, after a ventilation damper failed to close during a functional stroke test, plant personnel did not consider previous operability determinations and failed to provide supporting analysis to confirm there was no reduction in reliability of ARD relays.

Description.

Eaton Cutler-Hammer Type ARD660UR DC relays are used in multiple systems at Palo Verde. ARD relays are in a normally energized state. The loss of power to an energized ARD660UR DC relay is intended to place the associated valve or ventilation damper in its designated safety configuration.

Three failures of ARD relays occurred between January 22, 2012, and April 2, 2012. Each of the failures occurred during the first attempt to cycle the relay following a period of continuously energized service. In all three cases, the relay armature failed to drop out which resulted in ventilation dampers not repositioning to their post-accident positions.

Palo Verde launched an apparent cause evaluation to identify the cause of the three failures. The apparent cause evaluation condition report disposition request (CRDR) 40367198, issued July 20, 2012, determined the cause of the three failures to be the synergistic effects of return spring deficiencies, dimensional tolerances, and heat-related effects that lead to binding of the movable armature assembly.

On August 15, 2012, Unit 2 ventilation damper HAA-M03 failed to go closed when control room hand switch HAA-HS-112 was taken to the closed position during a functional stroke test in support of the apparent cause evaluation extent of condition review. This ventilation damper is controlled by an ARD relay and its function is to isolate the lower elevations of the auxiliary building during accident conditions. The failure on August 15 affecting ventilation damper HAA-M03 was the second failure for that specific damper.

ARD relay 2EZAAC03, which controls ventilation damper HAA-M03, also failed on April 2, 2012. At that time, the relay was replaced and retested. Following the second failure on August 15, operators declared the train A ESF pump room emergency air cleanup system inoperable and entered LCO 3.7.13, condition A. Corrective actions taken on August 15 consisted of generating a change mechanism work order to replace both the ARD relay and hand switch. After cycling the damper using the new components, operators declared the train A ESF pump room emergency air cleanup system operable on August 16, 2012.

Beginning August 16, the inspectors engaged the licensee regarding the adequacy of using a change mechanism work order to address operability of the ARD relay.

Specifically, the inspectors questioned whether the replacement of the failed ARD relay with an identical component was an acceptable means of restoring operability given the history of failures. The apparent cause report evaluation performed after the first three failures identified that each failure had occurred during the first attempt to cycle the relay following a period of continuous energization. The inspectors challenged that installing and energizing a new, identical ARD relay would subject the relay to the conditions associated with the previous four failures.

Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 31, Appendix E, contains considerations for the initial operability review. Appendix E specifically directs reviewers to consider previous operability determinations and evaluate if the structure, system, or component is further degrading or if there is a possibility that there is a common mode failure occurring.

The licensees initial operability review did not evaluate that this was the fourth recent failure of identical ARD relays. The inspectors also challenged that additional evaluation was needed to justify placing another identical relay into the same condition as the previous four failures without compensatory measures. Procedure 40DP-9OP26, step 3.2.10.3, requires that a prompt operability determination be performed if additional information such as supporting analysis or additional vendor research is needed to confirm the operability of a degraded or nonconforming structure, system, or component. Plant personnel did not perform an operability determination to consider that the reliability of the ARD relay population may be reduced due to the multiple and repetitive failures prior to returning the failed damper to service.

Following additional discussions with NRC inspectors, the licensee initiated an immediate operability determination on August 17. The first immediate operability determination was completed on August 18, but following a multi-organization conference call, the licensee returned the immediate operability determination for further evaluation. Operations personnel completed a second immediate operability determination and judged that the four recent failures did not constitute a reduction in reliability of ARD relays. A prompt operability determination was requested on August 18 in accordance with procedure 40DP-9OP26 to obtain additional supporting analysis and validate engineering judgment associated with a reduced reliability of ARD relays.

The licensee has entered this issue into their corrective action program as PVAR 4255816. The licensee has successfully cycled all ARD relays which could be performed during at-power operations. For remaining relays, the licensee initiated a review of relay specific performance history and performed a probabilistic risk assessment to justify an appropriate monitoring frequency. The licensee has also initiated a design change document that will determine a permanent substitute for the ARD660UR DC relays.

Analysis.

The inspectors concluded that the failure of the operations and engineering personnel to adequately evaluate the operability of a structure, system, or component was a performance deficiency. The inspectors concluded the performance deficiency is more than minor, and therefore a finding, because it affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and 0609, Appendix A, The Significance Determination Process (SDP) for Findings at-Power. Inspectors concluded that the finding was of very low safety significance (Green) because the finding is not a design or qualification issue, did not represent an actual loss of safety function of the system or train, did not result in the loss of one or more trains of non-technical specification equipment, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined this finding has a cross-cutting aspect in the area of human performance associated with the component of decision making because the licensee failed to communicate decisions and the basis for decisions to personnel who have a need to know the information in order to perform work safely, in a timely manner. Specifically, the licensee did not communicate the results of the apparent cause evaluation for the first three ARD relay failures to the appropriate operations personnel H.1(c).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 31, provided guidelines and instructions for evaluating the operability of structures, systems, or components, when degraded conditions were identified. Contrary to the above, from August 15-18, 2012, operations and engineering personnel failed to accomplish an activity affecting quality in accordance with the prescribed instructions, procedures, and drawings. Specifically, plant personnel did not consider previous operability determinations and failed to provide supporting analysis to confirm there was no reduction in reliability of ARD relays. Because this finding is of very low safety-significance and has been entered into the licensees corrective action program as PVAR 4255816, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000528; 529; 530/2012004-04, Inadequate Operability Determination for ARD Relay Failures.

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:

• July 3, 2012, Unit 1, train B, emergency diesel generator control room handswitch replacement

• September 12, 2012, Unit 2, train A, essential cooling water surge tank vacuum relief valve post-maintenance testing

• September 13, 2012, Unit 2, refrigerant head pressure control valve 2JEWACPV-0173 post maintenance testing

• September 15, 2012, Unit 2, train A, spray pond breaker overhaul post maintenance testing

• September 18, 2012, Unit 2, train A, emergency diesel generator post-maintenance testing following super outage 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 UFSAR, 10 CFR Part 50, requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the 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 five post-maintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, 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

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

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

• Reference setting data

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

• July 2, 2012, Unit 2, train B high pressure safety injection pump surveillance test

• July 27, 2012, Unit 3, control element assembly surveillance test

• August 16, 2012, Unit 3, train A containment spray pump inservice test Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The NRC Nuclear Security Incident Response Headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML12200A022 and ML12202A643 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b), and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the

.

These activities constitute completion of three samples as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the second quarter 2012 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

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

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system specific activity performance indicator for Palo Verde Nuclear Generation Station Units 1, 2, and 3 for the period from the third quarter 2011 through the second quarter 2012. 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 reactor coolant system chemistry samples, technical specification requirements, issue reports, event reports, and NRC integrated inspection reports for the period of third quarter 2011 through the second quarter 2012, 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. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of three reactor coolant system specific activity samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Reactor Coolant System Leakage (BI02)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system leakage performance indicator for Palo Verde Nuclear Generation Station Units 1, 2, and 3 for the period from the third quarter 2011 through the second quarter 2012. 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 logs, reactor coolant system leakage tracking data, issue reports, event reports, and NRC integrated inspection reports for the period of third quarter 2011 through the second quarter 2012, 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.

These activities constitute completion of three reactor coolant system leakage samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

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 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 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. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for 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.

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. Findings

No findings were identified.

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item:

• August 10, 2012, loss of power to technical support center due to lighting fault The inspectors considered the following during the review of the licensee's actions: (1)complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem;

(5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner.

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

These activities constitute completion of one in-depth problem identification and resolution sample as defined in Inspection Procedure 71152-05.

b. Findings

Failure to Perform 50.54

(q) Evaluation

Introduction.

Inspectors identified a Severity Level IV, non-cited violation of 10 CFR 50.54 (q), Conditions of Licenses, and an associated Green finding for the licensees failure to perform an appropriate design scope change, which resulted in the reduction in effectiveness of the emergency plan. Specifically, in May 19, 2011, the licensee completed a modification to revise protective area lightning power sources and removed ground fault protections on a circuit breaker attached to the bus, which powers the technical support center. This change created a condition that would remove power to the technical support center and prevent back up power from being able to power the bus.

The violation is associated with a reactor oversight process finding that has been evaluated by the SDP and communicated with an SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety-significance of the associated ROP finding.

Description.

During the inspectors review of corrective action documents, the inspectors noticed on August 10, 2012 the technical support center (TSC) suffered a complete loss of power. This was determined to be unusual as the TSC design is to have a redundant source of power to maintain continuity of emergency plan functions should the facility become activated. Condition report disposition request 4230209 evaluated the event which resulted in the loss of the bus powering the TSC and determined that the loss of power was due to a fault on security lighting. This fault propagated from the lighting feeder breaker AENGL50C3 to the main load center AENGNL50, which powers the TSC and other components. Because the TSC diesel generator, (the redundant power source),ties into the bus downstream of the main load center AENGNL50 and is attached to the same bus as the faulted lighting feeder breaker AENGL50C3, the diesel could not provide power to the TSC. During trouble shooting maintenance personnel discovered the lighting feeder breaker AENGL50C3 did not trip as designed given a lighting fault because its ground fault relay was disabled. Maintenance personnel were able to restore power to the TSC within an hour.

Inspectors determined that the ground fault relay was disabled during a design modification which installed the lighting onto the bus powered by the AENGNL50 load center. The modification was performed by contractors who disabled the relay to prevent nuisance trips. The decision to remove this protective feature was not a part of the original design modification and was added as a pen and ink change under procedure 81DP-0EE10 Design Change Process. Pen and ink changes are utilized for changes to modifications that will not affect the scope or previously analyzed aspects of the modification. Inspectors determined that the use of a pen and ink change was not appropriate in accordance with 81DP-0EE10 Design Change Process and engineering personnel failed to follow the procedure and apply design control measures commensurate with the original design. Inspectors determined that the design change to remove the protective relay had not been assessed for impacts to the emergency plan under a 10 CFR 50.54(q) review. PVAR 4244729 was generated to address this concern and determined that the change, which resulted in a lighting fault removing all power from the TSC, was a change that decreased the effectiveness of the emergency plan. The licensee has restored the ground fault relay functionality under work order 4247015.

Analysis.

The failure to perform an appropriate design scope change was a performance deficiency. The performance deficiency was more than minor, therefore a finding, because it affected the facilities and equipment attribute of the Emergency Preparedness Cornerstone and its objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process. The finding was determined to be (Green) of very low safety-significance because the change did not result with the loss of facility functionality.

The violation of 10 CFR 50.54

(q) impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. This violation was determined to be a Severity Level IV violation per Section 6.6 of the NRC Enforcement Policy because the violation was not associated with licensees ability to meet or implement any regulatory requirement related to assessment or notification. Although the regulatory requirement could be implemented during the response to an actual emergency, the implementation would be degraded. The inspectors determined this finding has a crosscutting aspect in the area of human performance associated with the work practices component because the licensee failed ensure supervisory management and oversight of contractors such that nuclear safety is supported. [H.4.(c)]

Enforcement.

Title 10 CFR Part 50.54, Condition of Licenses, Section

(q) states, in part, that a licensee may make changes to emergency plans without prior Commission approval only if the changes do not decrease the effectiveness of the plans. Contrary to the above, from May 19, 2011 to September 26, 2012, the licensee made a change to the emergency plan that decreased the effectiveness of the plan without prior Commission approval.

Specifically, on May 19, 2011, the licensee completed a modification to revise protective area lightning power sources and removed ground fault protections on a circuit breaker attached to the bus which powers the technical support center. This change created a condition that could remove power to the technical support center and prevent emergency plan required back up power from being able to power the bus. On August 10, 2012, a lighting fault caused a complete loss of power to the technical support center, demonstrating that this change decreased the effectiveness of the emergency plan. On September 26, 2012, the licensee reactivated the ground fault protection for the circuit breaker and has established compensatory measures to restore power to ensure technical support center power supplies will not be challenged. Because this finding is of very low safety-significance and has been entered into the licensees corrective action program as PVAR 4244729, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000528; 529; 530/2012004-05; Failure to Perform 50.54

(q) Evaluation.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Southern California Earthquake on August 26, 2012

a. Inspection Scope

The inspectors reviewed the licensees response to a seismic event that occurred on August 26, 2012, in southern California and was felt by plant personnel on site.

b. Findings

Failure to Declare an Unusual Event

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50.54(q) for the failure of operations personnel to adequately implement the emergency plan.

Specifically, on August 26, 2012, auxiliary operators felt vibratory ground motion inside the protected area at 12:31 p.m. and again at 1:58 p.m. The United States Geological Survey (USGS) confirmed two earthquakes, of magnitude 5.3 and 5.5 respectively, occurred at those times in the area of the plant. Plant operators did not declare an Unusual Event in accordance with the emergency plan. The licensee entered the issue into the corrective action program as PVAR 4255819 and initiated an apparent cause evaluation to identify the cause and corrective actions.

Description.

On August 26, 2012, at approximately 12:31 p.m., auxiliary operators in Unit 1 and Unit 3 operations support buildings, located adjacent to the control building, notified control room operators that they felt building motion. Control room operators reviewed the USGS website and confirmed an earthquake of magnitude 5.3 had occurred at that time in southern California. Subsequently, at 1:58 p.m., personnel felt building motion, which was confirmed to be a magnitude 5.5 earthquake from the same location. Operators did not declare an Unusual Event because the earthquake was not felt in the power block.

The inspectors challenged this decision, based on the requirements of the PVNGS Emergency Plan, Table 2, Initiating Conditions and EAL Thresholds. The emergency action level threshold for HU1, Natural or destructive phenomena affecting the PROTECTED AREA, states, in part:

1. Seismic event identified by any two of the following:

• VALID seismic event alarm

• Earthquake felt in plant

• National Earthquake Center The inspectors concluded that both earthquakes were felt in the plant and confirmed by the USGS National Earthquake Center.

The inspectors concluded that the most significant contributor to the performance deficiency was inadequate training provided to operators to ensure the adequate assessment of seismic events in the plant. Through interviews and reviews of training materials, inspectors identified that training on HU1 requirements did not clarify that vibratory ground motion felt inside the protected area meets the threshold, regardless of the fact it was not felt by control room personnel.

The licensee entered this issue into the corrective action program as PVAR 4255819.

Analysis.

The failure to implement the emergency plan and declare an Unusual Event was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the Emergency Response Organization performance attribute of the Emergency Preparedness cornerstone and affected the cornerstone objective to ensure the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Using Manual Chapter 0609, Appendix B, "Emergency Preparedness Significance Determination Process," Attachment 1, the finding was determined to have very low safety-significance (Green) because the actual event implementation problem was associated with an Unusual Event. This finding has a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure training of personnel was adequate to assure proper implementation of the emergency plan [H.2.(b)].

Enforcement.

Title 10 CFR Part 50.54(q), Emergency Plans, states, in part, that a licensee shall follow an emergency plan that meets the requirements in Appendix E to this part and the planning standards of § 50.47(b). PVNGS Emergency Plan, Revision 48, states, in part, an emergency shall be classified and declared if a specific emergency action level threshold has been reached. Contrary to the above, the licensee failed to classify and declare an Unusual Event after the specific emergency action level threshold had been reached. Specifically, on August 28, 2012, operations personnel failed to classify an Unusual Event for a seismic event that was felt in the plant and confirmed by the National Earthquake Center. The licensee initiated an apparent cause evaluation to identify the cause and corrective actions. Because this finding is of very low safety-significance and has been entered into the licensee's corrective action program as PVAR 4255819, this violation is being treated as a non - cited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000528;529;530/2012004-06, Failure to Declare an Unusual Event.

.2 (Closed) Licensee Event Report 05000530/2010-002-01, Condition Prohibited by

Technical Specification Resulting from Containment Spray Nozzle Obstruction On October 13, 2010, during a Unit 3 refueling outage, the licensee identified seven obstructed containment spray nozzles during a scheduled surveillance test. The nozzles were obstructed for a period greater than allowed by Technical Specification 3.6.6. The licensee issued the LER supplement to provide additional information on the cause and corrective actions for the condition. The licensee concluded the obstruction was caused by boric acid solution that was not removed from low points that entrapped water in the containment spray headers after these headers were filled with borated water during past containment spray header overfill events. The licensee also determined that the boric acid deposits were friable and easily removed using a pipe cleaner, and that the deposits would dissolve if an actual containment spray event occurred. The licensee subsequently cleaned the obstructed nozzles and successfully completed the surveillance test.

Corrective actions included inspection and cleaning of the containment spray headers with low points to remove boric acid residue in all units. Also, operations procedures were revised to initiate corrective actions to drain affected containment spray headers following overfill events. The inspectors originally dispositioned this issue as a licensee-identified violation in Section 4OA7 of NRC Integrated Inspection Report 05000528;529;530/2010005.

The inspectors reviewed the LER and did not identify any additional concerns. This LER is closed.

.3 (Closed) Licensee Event Report 05000528;05000530/2011-001-01, Unit 1 and Unit 3

Emergency Diesel Generator Actuation on Loss of Offsite Power to Class 4.16kV Bus On February 21, 2011, a valid actuation of the circuitry that starts the emergency diesel generators for Unit 1, train B and Unit 3, train A occurred due to an undervoltage condition on their respective 4.16kV safety buses. The EDGs started and loaded as designed.

The cause of the undervoltage condition was a cable splice failure on the cable for Y winding of the AE-NAN-X02 startup transformer. The licensee issued the LER supplement to provide additional information on the cause and corrective actions for the condition.

The licensees investigation concluded the splice failure occurred due to inadequate maintenance performed on the cable on February 7, 2011. The work order instructions lacked the necessary detail for the insulation taping that resulted in the failed splice.

Corrective actions include removing the allowance for taping of cable splices for 5kV to 15kV cables, and additional periodic testing of existing medium voltage cable splices.

Inspectors originally reviewed this issue and documented a Green self-revealing finding in Section 4OA2 of NRC Integrated Inspection Report 05000528;529;530/2011003.

The inspectors reviewed the LER and did not identify any additional concerns. This LER is closed.

.4 (Closed) Licensee Event Report 05000528;05000529;05000530/2012-002-00, Supported

Systems not Considered Inoperable with Support Equipment Inoperable On January 22, 2012, during surveillance testing in Unit 2, a control relay failed to change state as expected and essential ventilation dampers failed to reposition as required.

Operators declared the essential air handling units inoperable, but since no technical specification exists for the essential ventilation system, operators used existing procedural guidance and did not declare the supported systems inoperable. On May 9, 2012, following discussions with the NRC, the licensee concluded that a condition prohibited by technical specifications existed because the supported systems were inoperable for periods longer than allowed by the limiting conditions for operation.

The licensee concluded the cause of the event was an inadequate procedure that was based on an incorrect understanding of the relationship between essential ventilation equipment and operability of the electrical distribution system supported by the ventilation system. Corrective actions include revision of the procedure to require immediate operability determinations for technical specification equipment supported by inoperable essential ventilation system equipment. Inspectors originally reviewed this issue and documented a Green NRC-identified finding in Section 1R15 of NRC Integrated Inspection Report 05000528;529;530/2012003.

The inspectors reviewed the LER and did not identify any additional concerns. This LER is closed.

.5 (Closed) Licensee Event Report 05000529/2011-002-01, Inoperable Steam Generator

Low Pressure Reactor Trip and Main Steam Isolation Signal Channels On May 5, during surveillance testing in Unit 2, the Channel A setpoint for Steam Generator Low Pressure Reactor Trip and Main Steam Isolation Signal was found to be at 950 psia, below its required value of 955 psia. Subsequently the channel was placed into bypass and set point was restored and declared operable.

The licensee concluded the cause of the event was an inadequate procedure that did not validate that the set points were prior to being required. Corrective actions include revision of the procedure to include verification of steam generator low pressure set point is operable prior to changing modes Inspectors reviewed this issue and documented a licensee-identified finding in Section 4OA7 of this report. This LER is closed.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On October 3, 2012, the inspectors presented the inspection results to R. Bement and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors 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 violations of very low safety-significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non-cited violations.

.1 Title 10 CFR 50.55(a) Codes and Standards states in part that systems and components

of nuclear power reactors must meet the requirements of the standards referenced in paragraph (b)(3) of this section. Title 10 CFR 50.55(a)(b)(3) states in part that references to the OM Code refer to the ASME Code for Operation and Maintenance of Nuclear Power Plants, including Mandatory Appendix I. Mandatory Appendix I Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants states in part that Class 1 pressure relief valves shall be tested at least once every five years, a minimum of 20% of the valves from each valve group shall be tested within any 24-month interval, and for replacement of a partial complement of valves, the valves removed from service shall be tested prior to resumption of electric power generation. Contrary to the above, prior to October 5, 2011, the licensee failed to test a minimum of 20% of Class 1 thermal relief valves within any 24 month interval for Units 1 and 3 and failed to test Class 1 thermal relief valves removed from service prior to resumption of electric generation for Unit 2.

The licensee has entered surveillance requirement SR 3.0.3 for all three units and will test the affected Class 1 thermal relief valves, in accordance with Mandatory Appendix I, at the next outage for each unit respectively. The inspectors concluded that the finding is of very low safety-significance (Green) because the reactor coolant system barrier remained intact, was not associated with the fuel barrier, and did not constitute a spent fuel pool issue and has been entered into the licensees corrective action program as PVAR 4206766.

.2 Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure 40OP-9ZZ11, Mode Change Checklist, describes requirements needed to be satisfied prior to changing modes. Contrary to the above on May 2, 2011, the licensee used procedure 40OP-9ZZ11, Mode Change Checklist, to change from Mode 4 to Mode 3, which did not have a requirement to verify the steam generator low pressure set point was operable prior to changing modes. While in Mode 3 operations personnel performed a surveillance test and discovered the steam generator low pressure set point was 905 psia, vice the required 955 psia. This was a condition prohibited by technical specifications and was reported as LER 2011-002-01. The licensee has revised 40OP-9ZZ11, to include verification of steam generator low pressure set point is operable prior to changing modes. This finding was of very low safety-significance (Green) because it is a qualification issue confirmed not to result in an actual loss of function and has been entered into the licensees corrective action program as PVAR 3729932.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

P. Anderson, Program Engineer

M. Austin, Team Leader, Chemistry

R. Barnes, Director, Regulatory Affairs

R. Bement, Senior Vice President, Site Operations

B. Berryman, Plant Manager, Plant Operations

M. Brannin, Program Engineer

J. Cadogan, Director, Plant Engineering

K. Chavet, Consultant, Nuclear Regulatory Affairs

D. Coxon, Operations, Department Leader

T. Dickinson, Technical Advisor, Radiation Protection

E. Dutton, Director, Nuclear Assurance Department

D. Elkinton, Senior Consultant, Regulatory Affairs

M. Fallon, Director, Communications

R.C. Folley, Welding Engineer, Inservice Inspection

F. Gaber, Engineer, System Engineering

T. Gray, Support Services Department Leader, Radiation Protection

W.B. Haley, Inservice Inspection SL

D.B. Hansen, Engineering

D. Hautala, Regulatory Affairs

R. Henry, Director

K. House, Director, Design Engineer

J. Jenkins, Engineer, System Engineering

M. Lacal, Vice President, Operations Support

F. Lake, Director, Performance Improvement Department

M. McGhee, Department Leader, Nuclear Regulatory Affairs

D. Mims, Senior Vice President, Regulatory & Oversight

C. Moeller, Manager, Radiation Protection

F. Oreshack, Consultant, Nuclear Regulatory Affairs

S. Payne, Engineer, System Engineering

M. Powell, Director, Nuclear Fuel Management

M. Radspinner, Department Leader, System Engineering

M. Ray, Director, Emergency Preparedness/Security

B. Routolo, Operations Department Leader, Radiation Protection

M. Shea, Director, Safety Culture

R. Stroud, Section Leader, Licensing

B. Thiele, Program Engineer, Department Leader

T. Weber, Department Leader, Regulatory Affairs

Attachment

NRC Personnel

M. Brown, Senior Resident Inspector

M. Baquera, Resident Inspector

J. Laughlin, Emergency Preparedness Inspector

J. Melfi, Project Engineer

B. Parks, Project Engineer

D. Reinert, Resident Inspector

N. Taylor, Senior Project Engineer

D. You, Project Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

NCV Failure to Correct Scupper Obstruction

05000528; 529; 530/2012004-01 (Section 1R01)

NCV Untimely Corrective Action for Condition

05000529; 530/2012004-02 Adverse to Fire Protection (Section 1R05)

NCV Inadequate Boric Acid Evaluation

05000530/2012004-03 (Section 1R15)

NCV Inadequate Operability Determination for

05000528; 529; 530/2012004-04 ARD Relay Failures (Section 1R15)

NCV Failure to Perform 45.50(q) Evaluation

05000528; 529; 530/2012004-05 (Section 4OA2)

NCV Failure to Declare an Unusual Event

05000528;529;530/2012004-06 (Section 4OA3)

Closed

05000530/2010-002-01 LER Condition Prohibited by Technical Specification Resulting from Containment Spray Nozzle Obstruction (Section 4OA3)

05000528;530/2011-001-01 LER Unit 1 and Unit 3 Emergency Diesel Generator Actuation on Loss of Offsite Power to Class 4.16kV Bus (Section 4OA3)

LER Supported Systems Not Considered

05000528;529;530/2012-002-00 Inoperable with Support Equipment Inoperable (Section 4OA3)

05000529/2011-002-01 LER Inoperable Steam Generator Low Pressure Reactor Trip and Main Steam Isolation Signal Channels (Section 4OA7)