IR 05000324/2013003

Integrated Inspection Report 05000325/13-003 and 05000324-13-003

ML13221A073
Person / Time
Site:	Brunswick
Issue date:	08/08/2013
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	Hamrick G Carolina Power & Light Co
References
IR-13-003
Download: ML13221A073 (59)

Text

UNITED STATES August 8, 2013

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2013003 AND 05000324/2013003

Dear Mr. Hamrick:

On June 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on July 24, 2013 and August 1, 2013, with you and other members of your staff.

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

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

Five NRC-identified findings and one self-revealing finding of very low safety significance (Green), and one Severity Level IV violation were identified during this inspection. All of these findings were determined to involve a violation of NRC requirements. The NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation/finding or the significance of the NCV/finding, 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 II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Brunswick Steam Electric Plant.

If you disagree with the 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 II, and the NRC Resident Inspector at the Brunswick Steam Electric Plant. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document 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/

George Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

Inspection Report 05000325, 324/2013003 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report Nos.: 05000325/2013003, 05000324/2013003 Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road, SE Southport, NC 28461 Dates: April 1, 2013 through June 30, 2013 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector J. Dodson, Senior Project Engineer (Section 1R01, 4OA1)

R. Taylor, Senior Reactor Inspector (Section 1R04, 1R05, 1R11, 1R18, 1EP06)

Approved by: George Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000325/2013003, 05000324/2013003; 04/01/13 - 06/30/13; Brunswick Steam Electric

Plant, Units 1 & 2; Maintenance Effectiveness, Maintenance Risk Assessments and Emergent Work Control, Operability Evaluations, Plant Modifications, and Post Maintenance Testing.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Six Green findings and one Severity Level IV violation were identified. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, issued June 19, 2012 Significance Determination Process (SDP). The cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas, issued October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Rev. 4.

Cornerstone: Mitigating Systems

Green.

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have adequate installation and testing instructions for the EDG control oil system overspeed boost cylinder and accomplish the installation and testing in accordance with these instructions. The licensee replaced the boost cylinder and returned the EDG to operable. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 567016.

The inspectors determined that the failure to properly install the EDG 3 overspeed boost cylinder and properly test the boost cylinder, to ensure the boost cylinder can perform its design basis function, was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correctly install and test the EDG 3 overspeed boost cylinder resulted in the failure of EDG 3 to start and EDG 3 being declared inoperable on October 14, 2012. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because the licensee did not have complete, accurate and up-to-date design documentation, procedures, and work packages to install and test the EDG 3 overspeed boost cylinder. H.2(c) (Section 1R12.1)

Green.

An NRC-identified Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to follow the procedure to properly lubricate the 1B RHR room cooler damper The licensee lubricated the damper and returned the room cooler to operable, and entered this issue into the CAP as NCR 607514.

The inspectors determined that the failure of the licensee to properly lubricate the 1B RHR room cooler damper in accordance with Procedure 0PM-DMP500 was a performance deficiency. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to lubricate the 1B RHR room cooler damper resulted in a failure of the cooler fan and damper, and the inoperability of the 1B RHR train. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.

The finding has a cross-cutting aspect in the area of human performance associated with the work practices attribute because the licensee did not define and effectively communicate expectations regarding procedural compliance to Procedure 0PM-DMP500 and personnel did not follow this procedure. H.4(b) (Section 1R12.2)

Green.

An NRC-identified Green NCV of 10 CFR 50.65(a)(4) was identified for the failure of the licensee to manage the increase in risk that resulted from the E6 bus outage. Specifically, between May 19, 2013 and May 21, 2013, the licensee did not manage the increase in risk on Unit 2 during the E6 bus outage by use of appropriate risk management actions (RMAs). Operations personnel took immediate actions to protect the equipment in the control room and in the field. The licensee entered this issue into the CAP as NCR 607741.

The inspectors determined that the failure of the licensee to manage risk during the E6 outage by performing RMAs for the protected 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened vent was a performance deficiency. The finding was more than minor because if left uncorrected, the failure to perform RMAs when required could result in safety-related mitigating equipment being unavailable during already elevated plant risk, specifically the 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened vent. This finding was associated with the human performance attribute of the Mitigating Systems Cornerstone. Using IMC 0609, Appendix K, issued May19, 2005, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowchart 2, Assessment of RMAs, the inspectors determined the finding screened as very low safety significance (Green) since the incremental core damage probability was less than 1E-6. The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately plan work activities by incorporating risk insights during the E6 bus outage. H.3(a) (Section 1R13)

Green.

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the failure of the licensee to verify the adequacy of the design acceptance criteria for jacket water leakage to ensure EDG 3 could meet the design basis mission time of seven days. The licensees corrective actions include developing a plan to fill the EDG jacket water system to ensure operation of the EDG for seven days. The licensee entered this issue into the CAP as NCR 615491.

The inspectors determined that the failure to ensure sufficient jacket water to the EDGs, with a jacket water leak, for the seven-day mission time, was a performance deficiency.

The violation is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the calculational error assuming a four-day mission time versus a seven-day mission time results in a condition where there was reasonable doubt on the capability of an EDG when a jacket water leak exists. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding screened to a detailed risk evaluation because the finding represented an actual loss of function of at least a single Train of EDG for greater than the TS Allowed Outage time. The regional SRA performed a Phase 3 analysis on the finding. The time to failure of the EDG due to the leak precluded any internal risk impact, since it exceeded 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to failure. A screening calculation was performed to estimate the impact the finding would have on an extended loss of offsite power from seismic or external flooding. The low likelihood of the seismic or external flood event occurring, combined with the short time the deficiency existed, resulted in a finding of very low safety significance (Green). The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance.

Engineering evaluation was performed on July 7, 2004. (Section 1R15.1)

Cornerstone: Barrier Integrity

Green.

An NRC-identified Green non-cited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, was identified, for the licensees failure to have an adequate instruction or procedure to perform a modification to the control room emergency ventilation system (CREV). The licensee took immediate action to return CREV to service and entered this issue into the CAP as NCR 578363.

The inspectors determined that the failure of the licensee to have an adequate procedure for installing a jumper on the 2A CREV system was a performance deficiency.

The finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to have an adequate procedure to install a jumper on the 2A CREV system resulted in the safety system functional failure of CREV. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding screened to a detailed risk evaluation because the finding represented a degradation of the radiological barrier function and smoke or toxic atmosphere function of the control room barrier. The regional SRA performed a Phase 3 analysis on the finding. A screening calculation was performed to estimate the impact the finding would have on the facility for conditions that would lead to plant shutdown, or failure of the filtering function of the ventilation system. The low likelihood of failure to recover the system, combined with the short time the deficiency existed, resulted in a finding of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating the impact of changes to the work scope or activity on the plant when installing a ring lug jumper on the 2A CREV subsystem. H.3(b) (Section 1R12.3)

• SLIV. An NRC-identified SLIV NCV of 10 CFR 50.71(e) was identified for the licensees failure to revise the UFSAR with information consistent with plant conditions.

Specifically, from August 6, 2006 to the present, the licensee did not remove reference to or correct information to reflect current plant conditions related for the chlorine detection system used by the CREV in UFSAR Sections 6.4, Habitability System and 9.4.1, Control Building Ventilation System. The licensees corrective actions include revising the UFSAR. The licensee entered this issue into the CAP as NCR 614474.

The inspectors determined the failure of the licensee to update the UFSAR after removing the chlorine detection function from the safety-related CREV as required by 10 CFR 50.71.e and in accordance with Procedure REG-NGGC-0101, Final Safety Analysis Report Revisions, was a performance deficiency. This issue is considered within the traditional enforcement process because it has the potential to impede or impact the NRCs ability to perform its regulatory functions. The inspectors used the Enforcement Policy, Supplement I - Reactor Operations, to evaluate the significance of this violation.

Similar to Enforcement Policy, Section 6.1, example d.3, the inspectors determined the violation was a SLIV violation since the erroneous information not updated in the UFSAR has not resulted in any unacceptable change to the facility or procedures. (Section 1R18)

Green.

A self-revealing Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure incorporating a preventative maintenance schedule which specifies inspection or replacement of the RPS coil contactor 2-C72B-K1A that had a specific recommended lifetime. The licensee took action to manually open valve 2-E11-F009 and entered this issue into the CAP as NCR 599641.

The inspectors determined that the failure of the licensee to have an adequate procedure incorporating a preventative maintenance schedule which specifies inspection or replacement of contactor 2-C72B-K1A was a performance deficiency. The finding was more than minor because if left uncorrected, the failure of the GE CR105 contactors could result in the failure of the Unit 1 and Unit 2 A and B RPS buses. The finding was also associated with the configuration control attribute of the Barrier Integrity Cornerstone. Specifically, the failure to perform a PM on contactor coil 2-C72B-K1A resulted in a loss of decay heat removal to the SFP on April 5, 2013. Using IMC 0609,

Attachment 4, issued June 19, 2012, Initial Characterization of Findings, the inspectors determined that since this issue occurred during a refueling outage, that the finding should be processed in accordance with IMC 0609, Appendix G, issued February 28, 2005, Shutdown Operations Significance Determination Process. Using IMC 0609,

Appendix G, Table 1, Losses of Control, the inspectors determined that the finding was of very low safety significance (Green) because the inadvertent change in RCS temperature due to loss of RHR divided by the change in temperature that would cause boiling was less than 0.2 (temperature margin to boil). The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. The PM was not implemented per vendor recommendations in 1990.

(Section 1R19.1)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent of rated thermal power (RTP). On May 17, 2013, the unit was shut down for maintenance outage B119M3 to replace the 1B reactor recirculation pump seal and the E5 and E6 transformers. Unit 1 was started up on May 28, 2013 and returned to RTP on May 31, 2013 for the remainder of the quarter.

Unit 2 began the inspection period in refueling outage B221R1. On, May 5, 2013, the unit was started up. The unit was returned to RTP on June 2, 2013 for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 (Grid Reliability) Readiness of Offsite and Alternate Alternating Current Power Systems

(71111.01 - 1 grid sample)

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• Coordination between the TSO and the plant during off-normal or emergency events

• Explanations for the issues arose that could impact the offsite power system

• Estimates of when the offsite power system would be returned to a normal state

• Notifications from the TSO to the plant when the offsite power system was returned to normal The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• Actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to ensure the continued operation of the safety-related loads without transferring to the onsite power supply

• Compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions

• Re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power

• Communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged Inspectors reviewed the material condition of offsite AC power systems and onsite alternate AC power systems to the plant, including switchyard, transformers, emergency diesel generators, and emergency buses.

The inspectors also reviewed CAP items to verify that the licensee was identifying issues at an appropriate threshold and entering them into the CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought as a result of high temperatures.

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

Additionally, the inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed CAP items to verify that the licensee was identifying weather issues at an appropriate threshold and entering them into the CAP in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

• Control building ventilation and air conditioning

• Service water Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.3 Readiness for Impending Adverse Weather Condition

a. Inspection Scope

On June 7, 2013, a tropical storm warning was issued for the plant area as Tropical Storm Andrea approached the site. Inspectors reviewed the licensees overall preparations/protection for impending adverse weather conditions. The inspectors walked down areas of the plant susceptible to high winds, including the licensees emergency AC power systems. The inspectors evaluated the licensees preparations against the sites procedures and determined that the licensees 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 systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Quarterly Partial System Walkdowns (71111.04Q - 4 samples)

a. Inspection Scope

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

• CREV on May 22, 2013

• Unit 2A RHR on May 24, 2013

• Unit 1 reactor core injection cooling (RCIC) on June 12, 2013

• Emergency substation E6 on June 24, 2013 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, TS requirements, outstanding WOs, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify that system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Resident Inspector Tours (71111.05Q - 5 samples)

a. Inspection Scope

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

• 1PFP-RB1-1c, 1PFP-RB1-1d, and 1PFP-RB1-2, Unit 1 RHR and high pressure coolant injection (HPCI) rooms -17 elevation

• 0PFPF-DGFST, Technical Support Center/Emergency Operations Facility EDG and fuel storage tank

• 1PFP-RB1-1c and 1PFP-RB1-1d, Unit 2 RHR room -17 elevation

• 0PFP-CB-23, control room 49 elevation

• 1PFP-RB1-1h E and 1PFP-RB1-1h W, Unit 1 reactor building 50 elevation The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. 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. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of an underground bunker/manhole subject to flooding that contains cables whose failure could disable risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manhole MH-4SW, to verify that the cables were not submerged in water, that cables and/or splices appeared intact, and to observe the condition of cable support structures. When applicable, the inspectors verified proper dewatering device (sump pump) operation and verified level alarm circuits were set appropriately to ensure that the cables would not be submerged. Where dewatering devices were not installed, the inspectors ensured that drainage was provided and was functioning properly. The sample will be documented as complete when two additional manholes are inspected. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the Unit 2 RHR heat exchanger B to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also visually inspected the service water side of the heat exchanger to ensure that the heat exchanger was free of debris and biological growth. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

(71111.11Q - 1 sample)

a. Inspection Scope

On May 23, 2013, the inspectors observed a crew of licensed operators in the plants simulator during an emergency preparedness (EP) drill to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and to ensure that training, where appropriate, was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Ability to take timely actions in the conservative direction

• Prioritization, interpretation, and verification of annunciator alarms

• Correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Ability to identify and implement appropriate TS actions and EP actions and notifications The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

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

(71111.11Q - 1 sample)

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Specifically, on May 5, 2013, the inspectors observed Unit 2 startup from refueling outage B221R1. The inspectors reviewed various licensee policies and procedures listed in the Attachment. The inspectors evaluated the following areas:

• Operator compliance and use of procedures

• Control board manipulations

• Communication between crew members

• Use and interpretation of plant instruments, indications and alarms

• Use of human error prevention techniques

• Documentation of activities, including initials and sign-offs in procedures

• Supervision of activities, including risk and reactivity management

• Pre-job briefs and crew briefs

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• EDG 3 overspeed boost cylinder installed backwards resulting in a failure of the EDG to start on October 14, 2012

• RHR room cooler damper inadequate lubrication results in damper failure on November 9, 2012

• CREV 2A failure while performing maintenance on December 14, 2012 The inspectors reviewed events where ineffective equipment maintenance may have resulted in equipment failure or invalid automatic actuations of Engineered Safeguards Systems, and independently verified the licensees actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

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

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification

• Verifying appropriate performance criteria for mitigating SSCs/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1)

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

.1 Failure to Adequately Install and Test the EDG 3 Overspeed Boost Cylinder

Introduction.

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have adequate installation and testing instructions for the EDG control oil system overspeed boost cylinder and accomplish the installation and testing in accordance with these instructions.

Description.

On October 14, 2012, EDG 3 failed to successfully start during performance of the quarterly Procedure 0PT-12.2C, Zero Oil Pressure Test. A local start was initiated, however, the EDG failed to start.

Maintenance personnel had installed the overspeed boost cylinder backwards during implementation of WO 1033630 on November 8, 2007. The WO stated for the lead mechanic to verify that the valve(s) and cylinder are installed in the correct orientation with respect to system flow. Reference 0-FP-20014 and / or Vendor Technical Manual:

FP-20323. Drawing 0-FP-20014, Engine Pneumatic Control Schematic, and Vendor Technical Manual FP-20323, Diesel Engine Parts Manual, did not clearly state the proper orientation of the boost cylinder.

The licensee performed a cause evaluation and determined the apparent cause to be the control oil system overspeed boost cylinder seals had failed and oil leaked from the as-installed oil side to the as-installed air side of the cylinder, and the contributing cause to be the overspeed boost cylinder had been installed backwards. The corrective action for the apparent cause was to replace the boost cylinder and for the contributing cause was to develop and implement a method for ensuring the boost cylinder is installed in the proper orientation.

The inspectors questioned the licensees cause evaluation for what caused the seals to fail since the EDG 3 boost cylinder had been installed in 2007, and the other EDGs boost cylinders had been installed since plant startup with no seal failures. Also, the inspectors questioned what corrective actions the licensee was taking to correct the cause of the seal failures. After the inspectors questions, the licensee determined that the seals failing was not the cause of the failure of EDG 3 to start, and the licensee re-performed the apparent cause determination. The licensee determined the most probable cause to be the overspeed boost cylinder had been installed backwards in combination with the performance of the quarterly Zero Oil Pressure Test. The licensee determined that since Procedure 0PT-12.2C, Section 7.0(i), states when the test gauge indicates approximately zero, then close test gauge instrument drain valve, and the pressure bleeds down at a non-linear rate, that in previous tests, the oil pressure did not fully reach zero. The licensee believes the draining activity on October 14, 2012 lasted longer than those previously performed and was of sufficient duration to achieve zero psig at the oil side of the boost cylinder. The inspectors determined that if the test had been correctly performed in the past, then the licensee would have identified that the boost cylinder had been installed backwards in 2007.

The licensees corrective actions for the apparent cause was to replace the overspeed boost cylinder, develop and implement a method for ensuring the boost cylinders are installed in the proper orientation, and revise the quarterly Zero Oil Pressure Test to ensure consistency when performing the test to ensure the purpose of the test is fulfilled.

The licensee wrote CR 614935 to address the inadequate apparent cause evaluation.

The inspectors reviewed the licensees reportability evaluation and determined the failure of EDG 3 to start was not reportable since the inoperability occurred during testing on October 14, 2012, when the operators took the control oil pressure to zero, and the inoperability of the diesel did not exceed the TS allowed outage time.

Analysis.

The inspectors determined that the failure to properly install the EDG 3 overspeed boost cylinder and properly test the boost cylinder, to ensure the boost cylinder can perform its design basis function, was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correctly install and test the EDG 3 overspeed boost cylinder resulted in the failure of EDG 3 to start and EDG 3 being declared inoperable on October 14, 2012. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because the licensee did not have complete, accurate and up-to-date design documentation, procedures, and work packages to install and test the EDG 3 overspeed boost cylinder. H.2(c)

Enforcement.

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Contrary to the above, from November 8, 2007 to present, WO 1033630 was not appropriate to the circumstance to accomplish the installation of the EDG 3 overspeed boost cylinder in the correct orientation, and Procedure 0PT-12.2C was not appropriate to the circumstance to accomplish the testing of the boost cylinder to ensure it can perform its design basis function to start the EDG. The licensee replaced the boost cylinder and returned the EDG to operable. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 567016, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013003-01 and 05000324/2013003-01, Failure to Have Adequate Installation and Testing Instructions for the EDG Overspeed Boost Cylinder.

.2 Failure to Fully Lubricate the 1B Residual Heat Removal Cooler Damper

Introduction.

An NRC-identified Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to follow the procedure to properly lubricate the 1B RHR room cooler damper.

Description.

On November 9, 2012, at 0112, during performance of 0PT-8.2.2.B, Low Pressure Coolant Injection (LPCI)/RHR Operability Test - Loop B, the 1B RHR room cooler fan did not start when the control switch was place in start. The licensee found 1-VA-1K-TPD-RB damper did not fully open, resulting in the limit switch failing to start the fan. The licensee declared 1B RHR loop inoperable. The licensee lubricated the damper with light oil and the damper/fan tested satisfactorily. The 1B RHR room cooler was restored to operable and TS 3.5.1 and 3.6.2.3 were exited on November 9, 2012 at 15:00.

The licensee determined the likely cause of the problem was the instructions in Procedure, 0PM-DMP500, HVAC Damper Inspection, for the type of lubricant. These instructions were generic and did not include specific instructions for the 1B RHR dampers so that the wrong lubrication, graphite lubricant instead of light oil lubricant, was used on the damper. The last preventative maintenance performed on this damper was on September 5, 2012, during which the damper was lubricated with a graphite lubricant in accordance with WO 1979599.

The inspectors questioned the cause as to the failure mechanism of a graphite lubricant, and the corrective actions associated with this cause evaluation. The graphite lubricant was used on this damper on September 5, 2012, and the damper failed to fully open on November 9, 2012. The inspectors noted that the 1A and 2B RHR room dampers had been lubricated with a graphite lubricant, as well as other safety-related dampers, and that these dampers did not have a history of failure. After reconsideration, the licensee determined the cause to be that maintenance personnel did not adequately lubricate the damper. The licensee changed the corrective action to add a note to the WO template stating Ensure damper is appropriately lubricated. Failure of damper may occur as a result of inadequate or improper lubrication. The licensee wrote NCR 607514 to address the inadequate cause evaluation. The inspectors concluded that maintenance personnel did not follow the procedure to adequately lubricate the damper.

Analysis.

The inspectors determined that the failure of the licensee to properly lubricate the 1B RHR room cooler damper in accordance with Procedure 0PM-DMP500 was a performance deficiency. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to lubricate the 1B RHR room cooler damper resulted in a failure of the cooler fan and damper, and the inoperability of the 1B RHR train. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.

The finding has a cross-cutting aspect in the area of human performance associated with the work practices attribute because the licensee did not define and effectively communicate expectations regarding procedural compliance to Procedure 0PM-DMP500 and personnel did not follow this procedure. H.4(b)

Enforcement.

TS 5.4.1, Procedures, states that written procedures shall be established, implemented, and maintained covering the following activities: a. The applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 1.33). Safety Guide 1.33,Section I.2 states, that preventative maintenance schedules should be developed to specify lubrication schedules. WO 1979599-01 states to Perform 1-VA-1K-TPD-RB damper inspection / lube in accordance with applicable sections / steps of 0PM-DMP500 and 0MMM-054.

Procedure 0PM-DMP500, HVAC Damper Inspection, Section 7.4.12, states, to lubricate damper pivot points with a graphite type lubricant.

Contrary to the above, between September 5, 2012 and November 9, 2012, the licensee failed to follow Procedure 0PM-DMP500, HVAC Damper Inspection, and WO 1979599 to adequately lubricate the 1B RHR loop room cooler damper 1-VA-1K-TPD-RB. This resulted in the damper failing to fully open, which resulted in the failure of the room cooler fan to start, and the inoperability of the 1B RHR loop. The licensee lubricated the damper and returned the room cooler to operable. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 607514, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013003-02, Failure to Adequately Lubricate the 1B Residual Heat Removal Cooler Damper.

.3 Inadequate Work Order to Perform Maintenance on the Control Room Emergency

Ventilation System

Introduction.

An NRC-identified Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified, for the licensees failure to have an adequate instruction or procedure to perform a modification to the CREV system.

Description.

On December 14, 2012, the licensee was implementing a modification to upgrade the control building fire detection system. The 2A CREV subsystem was placed in the radiation/smoke protection mode in accordance with Technical Requirements Manual (TRM) 3.3.7.1, CREV System Instrumentation, Condition B. This action prevents the auto start of the 2B CREV subsystem, and as such, TS 3.7.3, CREV System, Condition A, was entered to restore 2B CREV to operable within 7 days. During work to electrically isolate one of the fire detectors associated with the 2A CREV subsystem, electrical continuity was lost during a jumper installation, resulting in a charcoal fire signal being sent to the 2A CREV subsystem circuitry and shutting down the 2A CREV subsystem. With the 2A CREV subsystem shutdown, the licensee entered TS 3.7.3, Required Action C.1, for both CREV subsystems being inoperable, which required the unit to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The licensee took immediate actions to restart the 2A CREV subsystem within approximately 2 minutes.

The licensee performed a cause evaluation and determined the apparent cause to be inadequate documentation and communication of the required system alignment. The licensee determined that the work planners had assumed that the duration of the jumper installation would be less than one hour and the operations personnel would not enter TRM 3.3.7.1, Condition B. The inspectors questioned the apparent cause and the proposed corrective actions. The inspectors challenged the licensees assumption that operations personnel should not have entered the short one hour duration TRM 3.3.7.1, Condition B, to place the 2A CREV subsystem in the radiation/smoke protection mode.

The licensee agreed with the inspectors and determined that operations personnel had made the correct conservative decision to enter the one hour action statement. The inspectors noted that WO 213458 was planned to jumper on live contacts.

After the inspectors review, the licensee revised the apparent cause to state that the CREV modification implementation manager did not change the WO instructions to acknowledge that the 2A CREV fan would be running while performing a jumper installation. The inspectors also noted that the planning instructions did not identify that a ring lug jumper was required by Procedure 0AI-59, Jumpering and Wire Removal, and that installation of this type of jumper requires the contact terminal screw to be removed, resulting in a loss of continuity for the system. The corrective action was to coach the implementation manager and the crew to maintain a questioning attitude and stop work when faced with uncertainty during the jumper installation. The inspectors concluded that the WO was inadequate to jumper on a live system.

Analysis.

The inspectors determined that the failure of the licensee to have an adequate procedure for installing a jumper on the 2A CREV system was a performance deficiency.

The finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to have an adequate procedure to install a jumper on the 2A CREV system resulted in the safety system functional failure of CREV. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding screened to a detailed risk evaluation because the finding represented a degradation of the radiological barrier function and smoke or toxic atmosphere function of the control room barrier. The regional SRA performed a Phase 3 analysis on the finding. A screening calculation was performed to estimate the impact the finding would have on the facility for conditions that would lead to plant shutdown, or failure of the filtering function of the ventilation system. The low likelihood of failure to recover the system, combined with the short time the deficiency existed, resulted in a finding of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating the impact of changes to the work scope or activity on the plant when installing a ring lug jumper on the 2A CREV subsystem. H.3(b)

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Contrary to the above, on December 14, 2012, the licensee did not have an adequate WO appropriate to the circumstance to land a ring lug electrical jumper for a modification to the charcoal filter thermal detection function of the CREV. This resulted in the 2A CREV fan automatically tripping, while the 2B CREV train was inoperable, and a loss of CREV safety function. The licensee took immediate action to return CREV to service.

Because this finding is of very low safety significance and was entered into the licensees CAP as NCR 578363, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013003-03 and 05000324/2013003-03, Inadequate Work Order to Perform a Modification to the Control Room Emergency Ventilation System

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Unit 2 elevated risk due to Division II emergency bus outage on April 9, 2013

• Unit 1 and Unit 2 elevated risk due to emergency bus E8 outage on April 15, 2013

• Unit 1 and Unit 2 elevated risk due to emergency bus E7 outage on April 22, 2013

• Unit 2 elevated risk during reactor cavity drain down on April 23, 2013

• Unit 1 and Unit 2 elevated risk due to emergency bus E6 outage on May 21, 2013 These activities were selected based on their potential risk-significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment.

b. Findings

Failure to Implement Risk Management Actions during Elevated Risk

Introduction.

An NRC-identified Green NCV of 10 CFR 50.65(a)(4) was identified for the failure of the licensee to manage the increase in risk that resulted from the E6 bus outage. Specifically, between May 19, 2013 and May 21, 2013, the licensee did not manage the increase in risk on Unit 2 during the E6 bus outage by use of appropriate risk management actions (RMAs).

Description.

On May 19, 2013, the licensee took safety-related bus E6 out of service to replace the 4160 V to 480 V transformer. Bus E6 is a 480V bus that supplies safety-related equipment for both Unit 1 and Unit 2. The licensee evaluated the risk associated with this activity in accordance with 10 CFR 50.65(a)(4) and their Equipment Out of Service Software (EOOS) and determined the risk would be in a high yellow risk condition. The RMAs were to protect equipment required for injection and decay heat removal during a design basis event. For Unit 2, the equipment required to be protected was the 2A RHR and RHRSW loops, the 2A and 2B core spray, and the hardened wet well vent.

Brunswick Procedure 0AP-025, BNP Integrated Scheduling, and OPS-NGGC-1311, Protected Equipment, implement the requirements of 10 CFR 50.65(a)(4) at the site.

Procedure OPS-NGGC-1311, Section 9.4.7 states, equipment shall be posted when any of the following conditions apply: a) when a component is out of service and is required for current plant operations, the redundant component as listed in the site-specific procedure shall be posted. Procedure 0AP-025, Attachment 8, describes which equipment should be protected. With one low pressure emergency core cooling system (ECCS) injection/spray subsystem inoperable, protect the remaining low pressure ECCS injection/spray subsystems, and with one subsystem of RHRSW out of service, protect the remaining RHRSW subsystem. With bus E6 out of service, 2B train of RHR and RHRSW was unavailable.

On May 21, 2013, the inspectors reviewed the risk assessment and walked down this equipment to see if the RMAs were properly implemented. The inspectors identified that the 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened wet well vent were not protected in the field or in the control room. The inspectors determined that the equipment had not been protected since bus E6 was taken out of service on May 19, 2013. Once the inspectors informed operations personnel that the equipment was not protected, operations personnel took immediate actions to protect the equipment in the control room and in the field. The licensee entered this issue into the CAP as NCR 607741. The licensee did have temporary power to install to RHR suppression pool cooling valve 2-E11-F028B, and battery chargers 1B-1 and 1B-2.

The licensee performed a cause evaluation and determined that: 1) neither the SROs removing the bus from service, nor the unit control room supervisor (CRS) reviewed the risk assessment which listed the equipment required to be protected prior to removing the bus from service; this was based on the assumption of previous performance of identical tasks on the E7 and E8 transformers, the required protected equipment was not verified; and 2) the progress reporter schedule did not have a task to protect the required equipment prior to de-energizing the associated electrical bus, as is the normal practice for planned bus outages.

The inspectors also identified that additional RMAs were not taken, including not providing a write-up of the protected equipment in operator logs, not posting the increased risk at the protected area entrance, and not using the risk stoplight to show an increased risk at the site. The licensees corrective actions included counseling the SROs involved on the proper method of validating what equipment is required to be protected, and coaching the personnel responsible for creating, reviewing, and approving the schedule on verifying the required tasks are scheduled.

Analysis.

The inspectors determined that the failure of the licensee to manage risk during the E6 outage by performing RMAs for the protected 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened vent was a performance deficiency. The finding was more than minor because if left uncorrected, the failure to perform RMAs when required could result in safety-related mitigating equipment being unavailable during already elevated plant risk, specifically the 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened vent. This finding was associated with the human performance attribute of the Mitigating Systems Cornerstone. Using IMC 0609, Appendix K, issued May19, 2005, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowchart 2, Assessment of RMAs, the inspectors determined the finding screened as very low safety significance (Green) since the incremental core damage probability was less than 1E-6. The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately plan work activities by incorporating risk insights during the E6 bus outage. H.3(a)

Enforcement.

Title 10 of the Code of Federal Regulations, 50.65(a)(4) states, in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, between May 19, 2013 and May 21, 2013, the licensee did not manage the increase in risk on Unit 2 during the E6 bus outage by use of appropriate RMAs. This resulted in the 2A RHR and RHRSW loops, the 2A and 2B core spray and the hardened vent not being protected, as required, during the high yellow risk E6 bus outage. When notified that the equipment was not protected, the licensee took immediate actions to protect the equipment in the control room and in the field. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 607741, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000324/2013003-04, Failure to Implement Risk Management Actions During Elevated Risk.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Jacket water leak on EDG 3 on August 12, 2012

• Low service water flow to EDG 3 on January 12, 2013

• Flange cracks on emergency substation E4 breaker connection on April 10, 2013

• Low core-to-ground resistance on emergency substation E5 and E6 on May 24, 2013

• Temporary leak repair of nuclear service water line 1-SW-72-4-157 on June 2, 2013

• Unqualified coating used in containment on June 11, 2013 The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS 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. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the

.

.1 Inadequate Design Control for Allowable Jacket Water Leak Rate

Introduction.

An NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the failure of the licensee to verify the adequacy of the design acceptance criteria for jacket water leakage to ensure EDG 3 could meet the design basis mission time of seven days.

Description.

On March 21, 2012, while conducting periodic test 0PT-12.2.C, No. 3 Diesel Generator Monthly Load Test, a jacket water leak was detected on the engine driven jacket water pump mechanical seal during engine startup. The leak rate was measured to be 10 ml/min. Since the leak rate was below the operability limit specified in 0OP-39, Diesel Generator Operating Procedure, of 15 ml/min, EDG 3 was determined to be operable. The licensee prepared a work request to repair the mechanical seal on the engine-driven jacket water pump.

Diesel 3 was run monthly from April 2012 - July 2012 with no leaks noted by operations personnel. On August 12, 2012, while conducting a periodic test, 0PT-12.2.C, a jacket water leak was detected again on the engine-driven jacket water pump mechanical seal during engine startup. The leak rate was measured to be 10 ml/min. Even though the leak rate was below the acceptance criteria, EDG 3 was declared inoperable to repair the jacket water pump. On August 15, 2012, the EDG 3 jacket water pump seal was repaired and returned to service.

The licensee performed EC 56519, DG Jacket Water System Leakage Criteria, on July 7, 2004, to determine the jacket water leak rate allowed to ensure the EDGs could run for a mission time of four days as specified in UFSAR Section 8.3.1.1.6.2.8, which ensures fuel oil makeup capability within four days. The acceptable leak rate was determined to be 15 ml/min. Engineering personnel assumed that a source of makeup water through the demineralized water system or the fire water system would be available to make up water to the EDG jacket water system between four and seven days. The inspectors reviewed EC 88949 which defined the EDG mission time as seven days as specified in the UFSAR, Section 8.3.1.1.6.2.8, which ensures a seven day fuel oil supply. The inspectors reviewed EC 56519 and determined the EDG mission time used in the calculation should have been seven days verses four days in accordance with EC 88949.

The inspectors questioned the availability of the demineralized water system and the fire water system as makeup water sources since neither system is safety-related (i.e. not seismically qualified) and has no emergency power supply available. Proper operation of these systems relies on pumps that lose power upon a loss of off-site power. The unavailability of the makeup systems was not considered during EC 56519. Without a reliable makeup source, the calculation was non-conservative to use a four-day instead of a seven-day mission time. The inspectors also determined that if the licensee continued to use a four-day mission time for the calculation, and relied on making up to the jacket water system, that no source of water was identified and no contingency procedure was in place to fill the system.

The inspectors determined that the allowed jacket water leak rate would be reduced to 8 ml/min using a seven day mission time. Therefore, EDG 3 should have been declared inoperable on March 21, 2012 and August 12, 2012 when a leak was measured at 10 ml/min. The licensee entered this issue into the CAP as NCR 615491.

Analysis.

The inspectors determined that the failure of the licensee to verify the adequacy of the design acceptance criteria for jacket water leakage to ensure EDG 3 could meet the design basis mission time of seven days was a performance deficiency.

The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee calculation assumed a four-day mission time versus a seven-day mission time. This resulted in reasonable doubt that the emergency diesel generator with a jacket water leak above the acceptance criteria could perform its intended function. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding screened to a detailed risk evaluation because the finding represented an actual loss of function of at least a single Train of EDG for greater than the TS Allowed Outage time. The regional SRA performed a Phase 3 analysis on the finding. The time to failure of the EDG due to the leak precluded any internal risk impact, since it exceeded 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to failure. A screening calculation was performed to estimate the impact the finding would have on an extended loss of offsite power from seismic or external flooding. The low likelihood of the seismic or external flood event occurring, combined with the short time the deficiency existed, resulted in a finding of very low safety significance (Green). The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. The engineering evaluation was performed on July 7, 2004.

Enforcement.

10 CFR Part 50, Appendix B, Criteria III, Design Control, requires, in part, that measures shall be established to verify the adequacy of the design. Engineering Change 88949 defines the EDG mission time as seven days. The acceptance criteria for a jacket water leak to meet the seven day mission time was 8ml/min.

Contrary to the above, from July 7, 2004 to the present, the licensee did not verify the adequacy of the design acceptance criteria to ensure sufficient jacket water to the EDGs, with a jacket water leak, for EDG 3 to meet the design basis mission time of seven days in that they used an acceptance criteria of 10 ml/min.. This resulted in a reasonable doubt on the capability of EDG 3 to perform for the design basis mission time when the jacket water leak existed. The licensees corrective actions include developing a plan to fill the EDG jacket water system to ensure operation of the EDG for seven days. The finding does not represent an immediate safety concern since the EDG jacket leak was repaired. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 615491, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013003-05 and 05000324/2013003-05, Inadequate Design Control for Allowable Jacket Water Leak Rate.

.2 (Opened) URI 05000325/2013003-06 and 05000324/2013003-06, Non-Conservative

Calculation for Service Water Flow Rate to the Emergency Diesel Generators

Introduction.

The inspectors are opening an URI to review the revision to Calculation M-89-0008, Heat Balance on DG 2 Jacket Water Service Heat Exchanger, for service water flow rate required for EDG operability during a design basis event, to determine if the performance deficiency associated with this issue is more than minor.

Description.

On January 14, 2013, the licensee was performing Procedure 0ENP-2705, Service Water Heat Exchanger Thermal Performance Testing, to measure the service water flow rate to the EDG 3 jacket water heat exchanger, and found flow to be in the range of 351 to 358 gpm. The expected flow rate is 900 gpm to 1100 gpm. After visual inspection, it was determined the EDG 3 service water outlet valve 2-SW-V208 was throttled to 1-1.25 turns instead of the required 2.25 turns specified in 0OP-39, Diesel Generator Operating Procedure. Diesel 3 was determined to be operable based on Calculation M-89-0008, which required the measured service water flow rate to be above 350 gpm at an ultimate heat sink temperature of 90F. The licensee performed a past operability evaluation and determined the service water outlet valve 2-SW-V208 was out of position since April 2010. The licensee determined the maximum service water inlet temperature experienced between April 2010 and January 2013 was 89.2F on August 2, 2011 and August 6, 2012. The licensee concluded that since the inlet temperature was below 90F in 2011 and 2012, and the service water flow rate was above 350 gpm, that EDG 3 had always been operable. The inspectors reviewed Calculation M-89-0008 and determined that the calculation assumed an EDG loading of 3500 kW instead of the EDG loading of 3850 kW allowed by TS 3.8.1, AC Sources -

Operating, Surveillance Requirement 3.8.1.11. The inspectors determined that the failure to have an adequate calculation for service water flow rate required for EDG operability was a performance deficiency. The inspectors are opening an URI to review the revision to Calculation M-89-0008 and determine if the performance deficiency is more than minor. The licensee entered this issue in the CAP as NCR 592035. This issue is being tracked as a URI: URI 05000325/2013003-06 and 05000324/2013003-06, Non-Conservative Calculation for Service Water Flow Rate to the Emergency Diesel Generators.

1R18 Plant Modifications

a. Inspection Scope

The following modifications were reviewed and selected aspects were discussed with engineering personnel:

• CREV chlorine detection function retirement in place (AR 204435204435

• Unit 2 14-day Limiting Condition for Operation 4 kV switchgear addition (EC79101)

• Main Steam Isolation Valve Guide Pad modification (EC47474)

• E8 unit substation transformer replacement (EC91400)

These documents and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screenings, consideration of design parameters, implementation of the modifications, post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors reviewed completed work activities to verify that installation was consistent with the design control documents. Documents reviewed are listed in the Attachment.

b. Findings

Failure to Update the UFSAR for the Removal of the Chlorine Detection System

Introduction.

An NRC-identified SLIV NCV of 10 CFR 50.71(e) was identified for the licensees failure to revise the UFSAR with information consistent with plant conditions.

Specifically, from August 6, 2006 to the present, the licensee did not remove reference to or correct information to reflect current plant conditions related for the chlorine detection system used by the CREV in UFSAR Sections 6.4, Habitability System and 9.4.1, Control Building Ventilation System.

Description.

On August 6, 2006, the licensee retired in the place the chloride detection system. This system was used by the CREV system to detect chlorine intrusion into the control room and automatically isolate the CREV system.

The inspectors noted that currently the UFSAR Section 6.4.4.2 states, that Brunswick Plant will have chlorine detection capability as described in Section 6.4.2.2. Also, Section 6.4.1 states, in part, Automatic isolation of the control room air intakes is provided for operator protection upon detection of high chlorine concentration. Section 9.4.1, Control Building Ventilation System, also describes the function of chlorine detection. The inspectors also noted that Technical Requirements Manual (TRM) 3.19, Control Room Emergency Ventilation System - Chlorine Protection Mode required the chlorine protection mode of the CREV system to be operable when the chlorine tank car is located within the exclusion area.

The inspectors reviewed the 10 CFR 50.59 screening the licensee performed in 2006 which identified that the power would be removed to the eight chlorine detectors for greater than 90 days. The licensee determined that an adverse change was not made to the UFSAR since the chlorine tanker truck was removed from the exclusion area prior to retiring the chlorine detection system. The licensee now uses sodium hypochlorite in place of chlorine for the service water and circulating water system. The licensee determined that sodium hypochlorite is not a control room habitability concern.

The inspectors determined that the UFSAR should have been updated within two years of when the system was removed from service in 2006. The licensee plans to remove reference to this system during the next UFSAR update tracked by AR 555459555459

Analysis.

The inspectors determined the failure of the licensee to update the UFSAR after removing the chlorine detection function from the safety-related CREV as required by 10 CFR 50.71.e and in accordance with Procedure REG-NGGC-0101, Final Safety Analysis Report Revisions, was a performance deficiency. This issue is considered within the traditional enforcement process because it has the potential to impede or impact the NRCs ability to perform its regulatory functions. The inspectors used the Enforcement Policy, Supplement I - Reactor Operations, to evaluate the significance of this violation. Similar to Enforcement Policy, Section 6.1, example d.3, the inspectors determined the violation was a SLIV violation since the erroneous information not updated in the UFSAR has not resulted in any unacceptable change to the facility or procedures.

Enforcement.

Title 10 CFR 50.71(e) states, in part, that the licensee shall update periodically, as provided in paragraphs (e)

(3) and

(4) of this section, the final safety analysis report (FSAR) originally submitted as part of the application for the license, to assure that the information included in the report contains the latest information developed. This submittal shall contain all the changes necessary to reflect information and analyses submitted to the Commission by the applicant or licensee or prepared by the applicant or licensee pursuant to Commission requirement since the submittal of the original FSAR, or as appropriate, the last update to the FSAR under this section.

Contrary to the above, between August 6, 2006 and the present, the licensee did not update the UFSAR to remove reference to or correct information to reflect current plant conditions related to the chlorine detection system used by the control room emergency ventilation system (CREV in Sections 6.4, Habitability System and 9.4.1, Control Building Ventilation System. Because this finding is of very low safety significance and was entered into the licensees CAP as NCR 614474, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a SL IV NCV: NCV 05000325/2013003-07 and 05000324/2013003-07, Failure to Update the UFSAR for the Removal of the Chlorine Detection System.

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:

• 0MST-DG24M, Emergency Bus Degraded Voltage Channel Functional Test, after voltage relay repair on March 22, 2013

• 0PT-01.1.7, RPS Automatic Scram Contactors Test, after relay repair on April 7, 2013

• 0PT-08.2.2c, Low Pressure Coolant Injection/Residual Heat Removal Operability Test - Loop A (RHR Heat Exchanger Bypass Valve 2-E11-F048A) after valve yoke to bonnet hold down stud replacement on April 9, 2013

• 0PT-20.10, Testing of Valve E51-F064 after valve repair on April 22, 2013

• 0PT-09.7, HPCI System Valve Operability Test after valve 2-E41-F001 repair on May 2, 2013

• 0PT-12.14L, Diesel Generator 4 Local Control Operability Test after repair of insulating barrier on ASSD switch on June 28, 2013 These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following, as applicable:

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

.1 Failure to Perform Preventative Maintenance on a SCRAM Contactor Coil

Introduction.

A self-revealing Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure incorporating a preventative maintenance schedule which specifies inspection or replacement of the RPS coil contactor 2-C72B-K1A that had a specific recommended lifetime.

Description.

On April 5, 2013, at 0530, the shutdown cooling inboard suction valve 2-E11-F009 spuriously closed. This caused a loss of decay heat removal function when RHR train B was being used in the fuel pool cooling assist mode to cool to the SPF. At the time of valve 2-E11-F009 closure, Unit 2 was in a refueling outage, all of the fuel from the reactor was offloaded to the SFP, and the gates from the SFP were open to the reactor. Operations personnel entered AOP-15, Loss of Shutdown Cooling, and AOP-38, Loss of Spent Fuel Pool Cooling. Operations personnel took actions to start the second loop of SFP cooling at 0612, and manually opened the F009 valve to restore RHR availability at 0709. When valve 2-E11-F009 failed closed, this put Unit 2 in a red risk configuration for the loss of the common suction path to both the primary and backup decay heat removal systems. At the time of the event, one train of SFP cooling was in service, but was not credited for the decay heat removal key safety function due to the decay heat load being greater than the removal capability of the SFP cooling.

This resulted in a SFP heatup of approximately three degrees.

The licensee determined that fuse 2-C72B-F1A was found blown and the coil for contactor 2-C72B-K1A, a GE CR105 contactor, was found failed on the 2A RPS bus.

The loss of the 2A RPS bus caused valve 2-E11-F009 to fail closed. The licensee replaced the K1A contactor and restored 2A RPS bus to service on April 6, 2013 at 12:23. The licensee performed an extent of condition review in April 2013 and replaced the Unit 1 and Unit 2 A and B bus GE CR105 contactors.

The inspectors reviewed the licensees cause evaluation which determined the failure of the contactor K1A was due to a lack of a PM schedule which was the result of an inadequate response to GE SIL-508. GE SIL-508 was issued in 1990 on SCRAM contactor coil life and maintenance. The SIL stated that the coils for these contactors are rated for 20 years at 50% operation at 104F. The SIL stated that the heating can cause visible dark spots on the exterior of the coils and that they can be tested for short circuits. The SIL recommended that SCRAM contactor coils that had been in service more than 18 years should be replaced in the next outage, inspected each outage, and considered for periodic replacement. Licensee Procedure 0PM-BKR003, Preventative Maintenance of General Electric 480 VAC Motor Control Center Compartments, was revised to include coil inspection and resistance tests. However, no WOs were found that replaced the K1A contactors.

For IMC 0609, Appendix G, Table 1, the inspectors determined that the inadvertent change in RCS temp due to a loss of RHR divided by the change in temp that would cause boiling was 2.9F divided by 126.1F which equals a temperature margin to boil of 0.02.

The inspectors determined that contactor 2-C72B-K1A, a GE CR105 contactor, was found failed on the 2A RPS bus, and the loss of the 2A RPS bus caused valve 2-E11-F009 to fail closed. This resulted in the loss of decay heat removal function in the fuel pool assist mode of RHR for the SFP with the core fully offloaded to the SFP.

Analysis.

The inspectors determined that the failure of the licensee to have an adequate procedure incorporating a preventative maintenance schedule which specifies inspection or replacement of contactor 2-C72B-K1A was a performance deficiency. The finding was more than minor because if left uncorrected, the failure of the GE CR105 contactors could result in the failure of the Unit 1 and Unit 2 A and B RPS buses. The finding was also associated with the configuration control attribute of the Barrier Integrity Cornerstone. Specifically, the failure to perform a PM on contactor coil 2-C72B-K1A resulted in a loss of decay heat removal to the SFP on April 5, 2013. Using IMC 0609, 4, issued June 19, 2012, Initial Characterization of Findings, the inspectors determined that since this issue occurred during a refueling outage, that the finding should be processed in accordance with IMC 0609, Appendix G, issued February 28, 2005, Shutdown Operations Significance Determination Process. Using IMC 0609, Appendix G, Table 1, Losses of Control, the inspectors determined that the finding was of very low safety significance (Green) because the inadvertent change in RCS temperature due to loss of RHR divided by the change in temperature that would cause boiling was less than 0.2 (temperature margin to boil). The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. The PM was not implemented per vendor recommendations in 1990.

Enforcement.

TS 5.4.1, Procedures, states that written procedures shall be established, implemented, and maintained covering the following activities, a. The applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 1.33). Safety Guide 1.33,Section I.2 states that preventative maintenance schedules should be developed to specify inspection or replacement of parts that have a specific lifetime. GE SIL-508, issued in 1990, recommended that SCRAM contactor coils that had been in service more than 18 years should be replaced in the next outage, inspected each outage, and considered for periodic replacement.

Contrary to the above, from plant startup to the present, the licensee did not have a procedure incorporating a preventative maintenance schedule which specifies inspection or replacement of the RPS coil contactor 2-C72B-K1A that had a specific recommended lifetime. This resulted in the contactor failing, the trip of the 2A RPS bus, the closure of shutdown cooling inboard suction valve 2-E11-F009, and the loss of decay heat removal function in the fuel pool assist mode of RHR to the SFP with the core fully offloaded to the SFP. The licensee took action to manually open valve 2-E11-F009. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 599641, consistent with Section 2.3.2 of the NRCs Enforcement Policy, this violation is being treated as a NCV: 05000324/2013003-08, Failure to Have an Adequate Procedure for Preventative Maintenance on a SCRAM Contactor Coil.

.2 (Opened) URI 05000324/2013003-09, Residual Heat Removal A Heat Exchanger

Bypass Valve 2-E11-F048A Stud Failure

Introduction.

The inspectors are opening an URI to review the licensees evaluation of the operability of A RHR heat exchanger bypass valve 2-E11-F048A and determine if the performance deficiency associated with this issue is more than minor.

Description.

On March 29, 2012, during Unit 2 refueling outage B221R1, maintenance personnel were going to repack A RHR heat exchanger bypass valve 2-E11-F048A. A member of maintenance hit one of the four valve yoke to bonnet hold down 13/4 studs with his foot and the stud sheared off at the nut. A second yoke hold down stud sheared off at the nut when maintenance personnel tried to remove the nut. The licensees corrective actions included replacing the four studs. The licensee determined the failure mechanism of the two studs was low stress, high cycle fatigue caused by vibration of the valve during throttling operations. The inspectors determined that the performance deficiency associated with this issue was the failure of the licensee to evaluate the effects of vibration on valve 2-E11-F048A when the valve was used for throttling, which resulted in the two studs sheering. The inspectors are opening an URI to review the licensees evaluation of the operability of valve F048A and determine if the performance deficiency is more than minor. The licensee entered this issue in the CAP as NCR 598294. This issue is being tracked as a URI: URI 05000324/2013003-09, Residual Heat Removal A Heat Exchanger Bypass Valve 2-E11-F048A Stud Failure.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

Unit 2 began the inspection period in a refueling outage. The inspectors reviewed outage plans and contingency plans for the Unit 2 refueling outage, which ended with the generator sync to the grid on May 9, 2013, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth of key safety functions.

During the refueling outage, the inspectors monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable TSs when taking equipment out of service

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing

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

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities

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

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

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

• Controls over activities that could affect reactivity

• Maintenance of secondary containment as required by TS

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

• Licensee identification and resolution of problems related to refueling outage activities Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Maintenance Outage Activities

a. Inspection Scope

The inspectors reviewed the outage plan and contingency plans for the Unit 1 maintenance outage to replace the 1B reactor recirculation pump seal and the E5 and E6 480 volt transformers, conducted May 17, 2013 through May 29, 2013, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

During the maintenance outage, the inspectors observed portions of the shutdown and cool down processes and monitored licensee controls over the outage activities listed below.

• Reactor shutdown and cool down rates

• Licensee configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable TS when taking equipment out of service

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing

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

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities

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

• Controls to ensure that outage work was not impacting the ability of the operators to operate the SFP cooling system

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

• Controls over activities that could affect reactivity

• Maintenance of secondary containment as required by TS

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

• Licensee identification and resolution of problems related to refueling outage activities Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing (71111.22 - 4 surveillance test samples)

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed the test results for the following activities to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing requirements, and licensee procedural requirements.

The inspectors assessed the effectiveness of the tests in demonstrating that the mitigating SSCs were operationally capable of performing their intended safety functions. Documents reviewed are listed in the Attachment.

• 0PT-20.3-E11, Local Leak Rate Testing for RHR system on March 10, 2013

• 0MST-DG13R, EDG 3 Loading Test on April 4, 2013

• 0MST-DG14R, EDG 4 Loading Test on April 17, 2013

• 0PT-20.9, Containment Atmospheric Control System Accumulators Leak Test and RNA Check valve exercise on May 3, 2013

b. Findings

No findings were identified.

.2 In-Service Testing (IST) Surveillance (71111.22 - 1 IST sample)

a. Inspection Scope

The inspectors reviewed the performance of the following test:

• 0PT-80.1, Reactor Pressure Vessel American Society of Mechanical Engineers (ASME)Section XI Pressure Test on April 28, 2013 Inspectors evaluated the effectiveness of the licensees ASME Section XI testing program for determining equipment availability and reliability. The inspectors evaluated selected portions of the following areas: 1) testing procedures; 2) acceptance criteria; 3)testing methods; 4) compliance with the licensees IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6)required corrective actions. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.3 Reactor Coolant System (RCS) Leak Detection Inspection Surveillance (71111.22 - 1

RCS leak sample)

a. Inspection Scope

The inspectors observed and reviewed the test results for a RCS leak detection surveillance, 0OI-03.1, Reactor Operator Daily Surveillance Report, on April 20, 2013.

The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; plant equipment calibration was correct, accurate, and properly documented; and the calibration frequency were in accordance with TSs, UFSAR procedures, and applicable commitments; applicable prerequisites described in the test procedures were satisfied; test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures; and other applicable procedures; test data and results were accurate, complete, within limits, and valid. Inspectors verified that test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; equipment was returned to a position or status required to support the performance of its safety functions; and all problems identified during the testing were appropriately documented and dispositioned in the CAP. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1EP6 Emergency Planning (EP) Drill Evaluation

a. Inspection Scope

The inspectors observed a site EP training drill conducted on May 23, 2013. The inspectors reviewed the drill scenario narrative to identify the timing and location of classifications, notifications, and protective action recommendations development activities. During the drill, the inspectors assessed the adequacy of event classification and notification activities. The inspectors observed portions of the licensees post-drill critique. The inspectors verified that the licensee properly evaluated the drill performance with respect to performance indicators and assessed drill performance with respect to drill objectives. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

Mitigating Systems Cornerstone (71151- 6 samples)

a. Inspection Scope

The inspectors sampled licensee submittals for the performance indicators listed below for the period of April 1, 2012 through March 31, 2013. The inspectors reviewed the licensees operator narrative logs, maintenance rule records, issue reports, derivation reports, event reports and NRC integrated inspector reports for the period 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 PI data collected or transmitted for this indicator and none were identified.

• Safety System Functional Failures

• Mitigating Systems Performance Index, Emergency AC Power System

• Mitigating Systems Performance Index, Cooling Water Systems - Service Water Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the CAP

a. Inspection Scope

To aid in the identification of repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily action request reports.

b. Findings

No findings were identified.

.2 Selected Issue Follow-up Inspection

a. Inspection Scope

The inspectors reviewed a 10 CFR Part 21, Reports of Defects and Noncompliances, which applied to Brunswick, associated with Flowserve Anchor Darling double-disc gate valve wedge pins sheering. The inspectors reviewed the licensees evaluation of the potential impact on the valves associated with this Part 21. The inspectors observed testing of a sample of the potentially affected valves to ensure the valves would continue to perform their design basis function. The inspectors ensured that the Part 21 was appropriately dispositioned in the CAP. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six-month period of January 1, 2013, through June 30, 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

Inspectors also reviewed major equipment problem lists, repetitive and rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy. Documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings were identified.

The inspectors evaluated a sample of departments that are required to provide input into the quarterly trend reports, which included outage and scheduling and system engineering departments. This review included a sample of issues and events that occurred over the course of the past two quarters to determine whether issues were appropriately considered or ruled as emerging or adverse trends, and in some cases, verified the appropriate disposition of resolved trends. The inspectors verified that these issues were addressed within the scope of the CAP, or through department review and documentation in the quarterly trend report for overall assessment. For example, the inspectors noted that consistent with the onset of an adverse trend in managing outage scope additions and deletions, the licensee appropriately identified this trend and entered it into the CAP as NCR 600460.

The inspectors identified an adverse trend in the adequacy of cause evaluations. The following examples did not have the correct cause and corrective actions identified until the inspectors challenged the cause evaluations. Examples include:

• EDG 3 overspeed boost cylinder installed backwards resulting in a failure of the EDG to start, discussed in Section 1R12.1 (NCR 567016)

• 1B RHR room cooler damper failure, discussed in Section 1R12.2 (NCR 572119)

• CREV 2A failure, discussed in Section 1R12.3 (NCR 578363)

• 1B Nuclear Service Water Pump bearing failure, dispositioned in NRC IR 2013004 (NCR 580155)

The licensee entered this trend into the CAP as NCR 614935.

4OA3 Follow-up of Events

.1 (Closed) Event Notification48972 Invalid Actuation Auto Start of All Four

Emergency Diesel Generators

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR 50.73 telephone notification for an invalid autostart of all EDGs on March 4, 2013. The actuation was caused by a Unit 1 SAT lockout relay being inadvertently energized. The emergency buses remained energized from the normal power supply and all emergency generators operated properly. The cause of the inadvertent relay energizing was determined to be a maintenance error. The inspectors reviewed the 10 CFR 50.73 notification to assess appropriate reporting within established criteria. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

.2 (Closed) LER 05000324/2011-001-02, Condition Prohibited by Technical Specifications

Due to Reactor Water Cleanup Instrumentation Inoperable

a. Inspection Scope

On July 28, 2011, a system data review identified that the Unit 2 Reactor Water Cleanup (RWCU) system inlet flow rate was reading approximately 18 percent lower than the system outlet flow rate. The licensee determined that the inlet flow was inaccurate because the flow orifice for the system inlet flow element had been installed backwards during maintenance activities on March 20, 2011. It was concluded that the flower flow readings from the RWCU inlet flow instrumentation would result in non-conservatism, and the non-conservatism resulted in the RWCU system isolation on Differential Flow -

High (TS 3.3.6.1-1, Primary Containment Isolation Instrumentation, Function 5.a) being inoperable. Corrective actions included reinstalling the flow orifice in the correct orientation, enhancing existing plant drawings associated with RWCU flow orifices, and reinforcing expectations regarding WO development with work planners. The licensee entered this issue into the CAP as NCR 479248 and NCR 584447. Documents reviewed are listed in the Attachment.

b. Findings

The licensee had originally submitted LER 05000324/2011-001-00, Condition Prohibited by Technical Specifications Due to Reactor Water Cleanup Instrumentation Inoperable, on September 26, 2011. The inspectors documented one licensee-identified violation of TS 3.3.6.1, Primary Containment Isolation Instrumentation, in NRC Inspection Report 05000325/2011004 and 05000324/2011004. The licensee retracted LER 05000324/2011-001-00 by letter dated November 20, 2011 when they determined that RWCU was not inoperable. The licensee disputed the licensee-identified violation by letter to the NRC on December 14, 2011. The inspectors issued a Task Interface Agreement on November 9, 2012, and a letter of denial for the disputed violation on November 20, 2012, to document the NRCs position that the RWCU was inoperable with the flow orifice installed backwards. The licensee resubmitted this LER 05000324/2011-001-02 on January 20, 2013.

No additional findings were identified during the review of this LER. This LER is closed.

.3 (Closed) LER 05000324/05000325-2012-007-00 and 05000324/05000325-2012-007-01,

Loss of Control Room Emergency Ventilation

a. Inspection Scope

On December 14, 2012, the licensee was implementing a modification to upgrade the control building fire detection system. The 2A CREV subsystem was placed in the radiation/smoke protection mode in accordance with Technical Requirements Manual (TRM) 3.3.7.1, CREV System Instrumentation, Condition B. This action prevents the auto start of the 2B CREV subsystem, and as such, TS 3.7.3, CREV System, Condition A, was entered to restore 2B CREV to operable within 7 days. During work to electrically isolate one of the fire detectors associated with the 2A CREV subsystem, electrical continuity was lost during a jumper installation, resulting in a charcoal fire signal being sent to the 2A CREV subsystem circuitry and shutting down the 2A CREV subsystem. With the 2A CREV subsystem shut down, the licensee entered TS 3.7.3, Required Action C.1, for both CREV subsystems being inoperable, which required the unit to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The licensee took immediate actions to restart the 2A CREV subsystem, and TS 3.7.3, Required Action C.1 was exited within approximately 2 minutes. The cause was determined to be inadequate documentation and communication of the required system alignment. The licensee entered this issue into the CAP as NCR 578363.

Documents reviewed are listed in the Attachment.

b. Findings

A violation of TS 5.4.1a was identified in Section 1R12.3. No additional findings were identified during the review of this LER.

This LER is closed.

.4 (Closed) LER 05000324/2013-001-00, Implementation of Enforcement Guidance 11-

003, Revision 1, Enforcement Guidance Memorandum (EGM) on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel (OPDRV)

a. Inspection Scope

The inspectors reviewed the plants implementation of NCR EGM 11-003 during Unit 2 maintenance activities which had the potential to drain the reactor vessel during the refueling outage. The activities were discussed in NRC Inspection Report 05000325/2013002 and 05000324/2013002, Section 4OA5.3. These activities took place without secondary containment being operable. Inspectors verified compliance with the guidelines of EGM 11-003 prior to and during these activities. The licensee entered this into the CAP as 593405. Documents reviewed are listed in the Attachment.

b. Findings

A violation of TS 3.6.4.1 was identified in NRC Inspection Report 05000325/2013002 and 05000324/2013002, Section 4OA5.3. No additional findings were identified during the review of this LER.

This LER is closed.

.5 (Closed) Granted Notice of Enforcement Discretion (NOED) 13-2-001: Brunswick TS

3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 Issue

a. Inspection Scope

On April 15, 2013, the inspectors reviewed the plants response to a Notice of Enforcement Discretion (NOED) that was required for the inoperability of Division II emergency buses E4/E8.

Before beginning the Division II emergency buses E4/E8 outage, the licensee entered the following Limiting Condition for Operations (LCOs) action statements for Unit 1:

TS 3.8.7, Condition C, entered at 7:15 a.m. on April 8, 2013, when DC control power supplies were re-aligned, (This condition was exited on April 14, 2013 at 1:16 p.m. when DC control power was returned to its normal source);

TS 3.7.3, Condition A, entered at 3:30 p.m. on April 8, 2013, when the 2A train of the CREV System was manually placed in the Radiation/Smoke protection mode; TS 3.8.4, Condition A, entered at 4:45 p.m. on April 8, 2013, when the Division II battery chargers, 2B-1 and 2B-2, were de-energized to install temporary power for the E4/E8 bus outage; and TS 3.8.1, Condition B, and TS 3.8.7, Condition A, were entered at 5:40 p.m. on April 8, 2013, when the Division II emergency buses E4/E8 were removed from service.

On April 11, 2013, at approximately 4:30 a.m., a degraded condition was identified on the E8 power transformer. During preventive maintenance, the E8 transformer core to ground was megger tested and an unsatisfactory reading of 0.21 M was obtained. The acceptance criteria is greater than or equal to 100 M. A visual inspection of the transformer core indicated that the transformer may have been overheated. A decision was made to replace the transformer. At that time, the necessary replacement parts were available onsite and the established work schedule provided for completion of the work before the applicable TS LCO action statements would expire. Late on April 14, 2013, associated work and testing activities were recognized that extended the work completion time beyond those allowed by the TS. Specifically, replacement and testing of the new transformer to restore operability would result in exceeding the completion times of TS 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A.1. The TS completion times scheduled to expire were as follows: TS 3.8.7, Required Action A.1, 3:15 p.m. on April 15, 2013; TS 3.7.3, Action A.1, 3:30 p.m. on April 15, 2013; TS 3.8.4, Required Action A.1, 4:45 p.m. on April 15, 2013; and TS 3.8.1, Required Action B.3, 5:40 p.m. on April 15, 2013.

Following risk assessments and evaluation of plant conditions, the licensee requested the NRC not enforce compliance with TS 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 until April 17, 2013 at 3:15 a.m. The licensee requested and was granted the NOED on April 15, 2013 at 2:05 p.m (NOED 13-2-001). The LCO extension allowed the site time to complete the replacement of and test the E8 transformer to restore operability.

The inspectors examined the sites actions to uncover the issue with the E8 transformer, their actions to address the issue once it was identified, and their compensatory actions associated with the receipt of the NOED. The inspectors also reviewed licensee documents to verify that information contained in the NOED request was accurate.

Inspection activities included gathering additional information on why the licensee needed the NOED; examining the sites decision-making process for the issue; reviewing the licensees condition evaluation; observing the licensees compensatory actions; and evaluating the licensees operability determination. To correct this issue and exit the NOED, the licensee completed replacement and satisfactory testing of the E8 transformer. Documents reviewed are listed in the Attachment.

b. Findings

The inspectors concluded that once the issue was discovered, the licensees efforts to identify and correct the condition were reasonable to restore operability of the Division II emergency buses E4/E8 and exit the NOED.

The inspectors opened a URI as discussed in Section 4OA3.6 to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, including enforcement action determinations, associated with the NOED.

.6 (Opened) URI 5000325/2013003-10; Notice of Enforcement Discretion for Replacement

of the E8 Transformer

Introduction.

In accordance with the NRCs NOED process, the inspectors are opening a URI to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, including enforcement action determinations, associated with the NOED. The inspectors are opening the URI to determine if a performance deficiency exists.

Description.

On April 15, 2013, due to the inoperability of Division II emergency buses E4/E8, the licensee requested the NRC not enforce compliance with TS 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 until April 17, 2013 at 3:15 am. The licensee requested and was granted the NOED on April 15, 2013 at 2:05 pm. The LCO extension allowed the site time to complete the replacement of and test the E8 transformer to restore operability.

The inspectors are opening an URI to determine if a performance deficiency exists. The licensee entered this issue in the CAP as NCR 601376. This issue is being tracked as a URI: (URI)5000325/2013003-10; Notice of Enforcement Discretion for Replacement of the E8 Transformer.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors observed the manual load test of the security emergency diesel generator on June 19, 2013 to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. The inspectors also observed security personnel and activities during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings were identified.

.2 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

The inspectors completed the review of the final report for the INPO plant assessment conducted in October 2012. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.

.3 (Closed) Unresolved ltem (URl)05000325/2012005-02 and 05000324/2012005-02,

Emergency Diesel Generator 3 Slow Start

a. Inspection Scope

The inspectors completed an evaluation of URI 05000325/2012005-02 and 05000324/2012005-02, Emergency Diesel Generator 3 Slow Start. On October 14, 2012, the licensee was running EDG 3 for a zero oil pressure start test in accordance with Procedure 0PT-12.2.c, No. 3 Diesel Generator Monthly Load Test. The EDG reached rated speed at approximately 38 seconds after the EDG was started and then tripped. Surveillance Requirement 3.8.1.7 requires the EDG reach rated conditions within 10 seconds. Several seconds after reaching rated speed, the EDG began to coast down due to receiving a lockout signal since full-rated conditions were not achieved within the nominal time delay of 45 seconds. The licensee replaced the overspeed start emergency boost cylinder and declared the EDG operable on October 17, 2012. The licensee determined the cause to be the overspeed boost cylinder had been installed backwards and inconsistent test performance of the zero oil pressure test. The inspectors reviewed the cause determination and interviewed engineering personnel to understand the cause of the failure.

b. Findings

An NRC-identified violation was identified and documented in section 1R12 of this report. This URI is closed.

4OA6 Management Meetings

Exit Meeting Summary

On July 24, 2013 and August 1, 2013, the inspectors presented the results of the quarterly integrated inspection activities to Mr. George Hamrick, and other members of the licensee staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection period.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Hamrick, Site Vice President

E. Wills, Director - Site Operations

J. Price, Director - Engineering

J. Krakuszeski, Plant General Manager

Y. Anagostopoulos, Manager - Major Projects

A. Brittain, Manager - Security

P. Dubrouillet, Manager - Nuclear Systems Engineering

A. Padleckas, Manager - Shift Operations

K. Allen, Manager - Design Engineering

S. Gordy, Manager - Maintenance

A. Pope, Manager - Nuclear Support Services

B. Houston, Manager - Environmental and Radiological Controls

J. Kalamaja, Manager - Operations

G. Kilpatrick, Manager - Training

J. Shumate, Manager - Outage and Scheduling

K. Hamm, Superintendent - Mechanical Maintenance

D. Petrusic, Superintendent - Environmental and Chemistry

O. Wrisbon, Superintendent - Electrical, Instrumentation and Controls Maintenance

L. Grzeck, Supervisor - Licensing

K. Crocker, Supervisor - Emergency Preparedness

B. Raper, Supervisor - U1 Outage Manager

W. Murray, Licensing Specialist

T. Sherrill, Licensing Specialist

M. Turkal, Licensing Specialist

NRC Personnel

G. Hopper, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000325; 324/2013003-06 URI Non-Conservative Calculation for Service Water Flow Rate to the Emergency Diesel Generators (Section 1R15.2)

05000324/2013003-09 URI Residual Heat Removal A Heat Exchanger Bypass Valve 2-E11-F048A Stud Failure (Section 1R19.2)5000325/2013003-10 URI Notice of Enforcement Discretion for Replacement of the E8 Transformer (Section 4OA3.6)

Opened and Closed

05000325; 324/2013003-01 NCV Failure to Have Adequate Installation and Testing Instructions for the EDG Overspeed Boost Cylinder.

(Section 1R12.1)

05000325/2013003-02 NCV Failure to Adequately Lubricate the 1B Residual Heat Removal Cooler Damper (Section 1R12.2)

05000325; 324/2013003-03 NCV Inadequate Work Order to Perform a Modification to the Control Room Emergency Ventilation System (Section 1R12.3)

05000324/2013003-04 NCV Failure to Implement Risk Management Actions During Elevated Risk (Section 1R13)

05000325; 324/2013003-05 NCV Inadequate Design Control for Allowable Jacket Water Leak Rate (Section 1R15.1)

05000325; 324/2013003-07 NCV Failure to Update the UFSAR for the Removal of the Chlorine Detection System (Section 1R18)

05000324/2013003-08 NCV Failure to Have an Adequate Procedure for Preventative Maintenance on a SCRAM Contactor Coil (Section 1R19.1)

Closed

48972 EN Invalid Actuation Auto Start of All Four Emergency Diesel Generators (Section 4OA3.1)

05000324/2011-001-02 LER Condition Prohibited by Technical Specifications Due to Reactor Water Cleanup Instrumentation Inoperable (Section 4OA3.2)

05000325; 324/2012-007- LER Loss of Control Room Emergency Ventilation and 01 (Section 4OA3.3)

05000324/2013-001-00 LER Implementation of Enforcement Guidance (EGM) 11-

003, Revision 1, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel (OPDRV) (Section 4OA3.4)

13-2-001 NOED Brunswick Technical Specifications 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 Issue (Section 4OA3.5)

05000324; 325/2012005-02 URI Emergency Diesel Generator 3 Slow Start (Section 4OA5.3)