IR 05000324/2015002
| ML15212A741 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/31/2015 |
| From: | Hopper G NRC/RGN-II/DRP/RPB4 |
| To: | William Gideon Duke Energy Progress |
| References | |
| IR 2015002 | |
| Download: ML15212A741 (40) | |
Text
UNITED STATES July 31, 2015
SUBJECT:
BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2015002 AND 05000324/2015002
Dear Mr. Gideon:
On June 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Steam Electric Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on July 16, 2015, with you and other members of your staff.
Three NRC-identified findings of very low safety significance (Green) were identified during this inspection. Two 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.a of the Enforcement Policy.
If you contest the violations or the significance of the violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region 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 Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Agency Rules of Practice and Procedure, 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 Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62
Enclosure:
IR 05000325, 324/2015002 w/Attachment: Supplementary Information
REGION II==
Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report No.: 05000325/2015002, 05000324/2015002 Licensee: Duke Energy Progress, Inc.
Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: Southport, NC Dates: April 1, 2015 through June 30, 2015 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector M. Orr, Resident Inspector (Acting)
M. Riches, Resident Inspector, Harris Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000325/2015002, 05000324/2015002; April 1, 2015, through June 30, 2015; Duke Energy
Progress, Inc., Brunswick Steam Electric Plant, Units 1 and 2, Fire Protection, Operability Determinations and Functionality Assessments, and Post-Maintenance Testing.
The report covered a three-month period of inspection by resident inspectors. There were two NRC-identified violations and one NRC-identified finding documented in this report. The significance of inspection findings are indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609,
Significance Determination Process, (SDP) dated April 29, 2015. The cross-cutting aspects are determined using IMC 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated February 4, 2015. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.
Cornerstone: Mitigating Systems
- Green.
An NRC-identified Green non-cited violation (NCV) of License Condition 2.B.(6),
Fire Protection Program, was identified for the licensees failure to maintain the 3-hour fire seals in the Unit 2 cable access way. Specifically, three cables in the Unit 2 cable access way were not within continuously enclosed conduits, which failed to preserve the integrity of the 3-hour rated barrier. As corrective action, the licensee sealed all three penetrations with a qualified 3-hour seal. This issue was entered into the licensees corrective action program (CAP) as nuclear condition report (NCR) 740606.
The inspectors determined that the licensees failure to maintain the 3-hour penetration fire barrier conduits in the Unit 2 cable access way, as required by licensee specification 118-003, Selection and Installation of Fire Barrier and Pressure Boundary Penetration Seals, was a performance deficiency. The finding was more than minor because it was associated with the external factors attribute (i.e. fire) of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in the failure of the three conduits to perform their function. The finding was screened using NRC IMC 0609,
Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because the finding affected the ability to confine a fire. Using IMC 0609, Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, dated September 20, 2013, the finding was assigned to the Fire Confinement category because the degraded penetrations were located in a fire barrier that separated two fire areas. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined the finding was of very low safety significance (Green) because safety significant equipment was located a sufficient distance from the degraded penetrations and the reactors ability to reach and maintain a safe shutdown condition was not impacted. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. (Section 1R05)
- Green.
An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, was identified for the licensees failure to have an adequate procedure to perform maintenance on the 1B conventional service water (CSW) pump strainer. Specifically, between August 28, 2009, and May 11, 2015, licensee procedure MNT-NGGC-0009, Application of Protective Coatings, was not adequate to perform repairs on the 1B CSW pump strainer, which resulted in through-wall leaks on three occasions. As corrective actions, the licensee repaired the weld, recoated the inside of the affected strainer area with Belzona coating using qualified individuals, and updated procedure MNT-NGGC-0009. The licensee entered this issue into the CAP as NCR 747712.
The inspectors determined that the licensees failure to have an adequate procedure to perform maintenance on the 1B CSW pump strainer was a performance deficiency. The finding was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, it could have led to a more significant failure of the 1B CSW pump strainer and the service water system. 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 human performance associated with the documentation attribute because the licensee failed to create and maintain complete, accurate and up-to-date documentation to correct the 1B CSW pump strainer through-wall leak issue on three occasions. [H.7] (Section1R15)
- Green.
An NRC-identified Green finding of licensee procedure CAP-NGGC-0205,
Condition Evaluation and Corrective Action Process, was identified for the licensees failure to perform an adequate extent of condition review for the 1C CSW pump strainer stop collar clearance issue. Specifically, between February 21, 2014, and April 8, 2015, the licensee failed to perform an adequate extent of condition to identify the 2C CSW pump strainer stop collar was also installed without being securely positioned. This resulted in the failure of the shear pin and inoperability of the 2C CSW strainer and pump. As corrective actions, the licensee replaced the shear pin securely and scheduled the replacement of the other CSW pump strainer shear pins at the earliest available work window. The licensee entered this issue into the CAP as NCR 742444.
The inspectors determined that the licensees failure to perform an adequate extent of condition review for the 1C CSW pump strainer stop collar clearance issue, as required by licensee procedure CAP-NGGC-0205 was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in the failure of 2C CSW pump strainer shear pin, and inoperability of the 2C CSW strainer and pump. 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 problem identification and resolution associated with the evaluation attribute because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee failed to evaluate the applicability of the stop collar clearance issue to the other strainers after the failure of the 1C CSW pump strainer shear pin. [P.2] (Section1R19)
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent rated thermal power (RTP). On May 29, 2015, the unit was down-powered to 70 percent for a scheduled control rod sequence exchange and returned to 100 percent RTP on May 31, 2015. On June 1, 2015, the unit was down-powered to 83 percent for a scheduled control rod pattern adjustment and returned to 100 percent RTP on June 2, 2015. On June 2, 2015, the unit was down-powered to 88 percent for a scheduled control rod pattern adjustment and returned to 100 percent RTP on June 3, 2015. The unit remained at or near 100 percent RTP for the remainder of the inspection period.
Unit 2 began the inspection period shutdown for refueling outage B222R1. On April 4, 2015, the unit was started up and returned to 100 percent RTP on April 18, 2015. On June 5, 2015, the unit was down-powered to 70 percent for a scheduled control rod sequence exchange and returned to 100 percent RTP on June 8, 2015. On June 8, 2015, the unit was down-powered to 71 percent for a scheduled control rod improvement and returned to 100 percent RTP on June 9, 2015. The unit remained at or near RTP for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed the licensees preparations to protect risk-significant systems from Tropical Storm Ana from May 8 - 10, 2015. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures, including operator staffing, before the onset of and during the tropical storm conditions. The inspectors reviewed the licensees plans to address the ramifications of potential sustained high winds, continual rainfall or flash flooding conditions. The inspectors verified that operator actions specified in the licensees adverse weather procedure maintain readiness of essential systems. The inspectors verified that required surveillances were current, or were scheduled and completed, if practical, before the onset of anticipated adverse weather conditions. The inspectors also verified that the licensee implemented periodic equipment walkdowns or other measures to ensure that the condition of plant equipment met operability requirements. Lastly, the inspectors toured the switchyard and walked down other outside protected areas to verify the licensee removed or properly secured any potential tornado missile hazards.
Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
.2 (Grid Reliability) Readiness of Offsite and Alternate Alternating Current (AC) Power
Systems (71111.01 - 1 sample)
a. Inspection Scope
The licensee did not implement equipment or procedure changes that potentially affect operation or reliability of offsite and alternate AC power systems since the last time the inspectors assessed grid reliability. The inspectors reviewed the material condition of offsite and onsite alternate AC power systems (including switchyard and transformers)by performing a walkdown of the switchyard. The inspectors reviewed outstanding work orders (WOs) and assessed corrective actions for degraded conditions that impacted plant risk or required compensatory actions. Documents reviewed are listed in the
.
b. Findings
No findings were identified.
.3 Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors conducted a detailed review of the stations adverse weather procedures written for extreme high temperatures and extended hot weather concerns. The inspectors verified that weather-related equipment deficiencies identified during the previous year had been placed into the work control process and/or corrected before the onset of seasonal extremes. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures before the onset of and during seasonal hot weather conditions. Documents reviewed are listed in the
.
The inspectors evaluated the following risk-significant systems:
- EDG ventilation and air conditioning
- Technical Support Center and Emergency Operations Facility ventilation and air conditioning
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors verified that critical portions of the selected systems were correctly aligned by performing partial walkdowns. The inspectors selected systems for assessment because they were a redundant or backup system or train, were important for mitigating risk for the current plant conditions, had been recently realigned, or were a single-train system. The inspectors determined the correct system lineup by reviewing plant procedures and drawings. The inspectors observed whether there was indication of degradation, and if so, verified degradation was being appropriately managed in accordance with an aging management program, if applicable, and it had been entered into the licensees CAP at the appropriate threshold. Documents reviewed are listed in the Attachment.
The inspectors selected the following four systems or trains to inspect:
- Unit 1, 1B residual heat removal service water (RHRSW) pump with the 1A RHRSW pump out of service on June 3, 2015
- Units 1 and 2, 125/250 V direct current system on June 10, 2015
- Unit 2, Reactor core isolation cooling with high pressure coolant injection out of service on June 16, 2015
b. Findings
No findings were identified.
.2 Complete Walkdown
a. Inspection Scope
The inspectors verified the alignment of the Unit 2 standby liquid control (SLC) System.
The inspectors selected this system for assessment because it is a risk-significant mitigating system. The inspectors determined the correct system lineup by reviewing plant procedures, drawings, the updated final safety analysis report, and other documents. The inspectors reviewed records related to the systems outstanding design issues, maintenance work requests, and deficiencies. The inspectors verified that the selected system was correctly aligned by performing a complete walkdown of accessible components.
The inspectors observed whether there was indication of degradation, and if so, verified degradation was being appropriately managed in accordance with an aging management program, if applicable, and it had been entered into the licensees CAP at the appropriate threshold.
To verify the licensee was identifying and resolving equipment alignment discrepancies, the inspectors reviewed corrective action documents, including condition reports and outstanding WOs. The inspectors also reviewed periodic reports containing information on the status of risk-significant systems, including maintenance rule reports and system health reports. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the adequacy of selected pre-fire plans and fire protection procedures by comparing the pre-fire plans to the defined hazards and defense-in-depth features specified in the fire protection program. In evaluating the pre-fire plans, the inspectors assessed the following items:
- control of transient combustibles and ignition sources
- fire detection systems
- water-based fire suppression systems
- gaseous fire suppression systems
- manual firefighting equipment and capability
- passive fire protection features
- compensatory measures and fire watches
- issues related to fire protection contained in the licensees CAP The inspectors toured the following fire areas to assess material condition and operational status of fire protection equipment. Documents reviewed are listed in the
.
- 0PFP-CB-2, 6, 9, and 10, Control Building, 23-foot Elevation
- 0PFP-DG-01, Diesel Generator Building Basement, 2-foot Elevation
- 0PFP-DG-2, 3, 4, and 5, Diesel Generator Cells, 23-foot Elevation
- 2PFP-RB2-1h, Unit 2, Reactor Building, 50-foot Elevation
- 2PFP-RB-2-1j and 1k, Unit 2 Reactor Building, 80-foot Elevation
b. Findings
Degraded Fire Barrier Seals in the Unit 2 Cable Access Way
Introduction:
An NRC-identified Green NCV of License Condition 2.B.(6), Fire Protection Program, was identified for the licensees failure to maintain the 3-hour fire seals in the Unit 2 cable access way. Specifically, three cables in the Unit 2 cable access way were not within continuously enclosed conduits, which failed to preserve the integrity of the 3-hour rated barrier.
Description:
On March 27, 2015, the inspectors performed a walkdown of the Unit 2 cable access way in the 23-foot elevation of the control building. The inspectors identified the cable associated with floor penetration 0-FP-CB-1-314-1 did not have a 3-hour fire barrier conduit or a penetration seal. The cables associated with floor penetrations 0-FP-CB-1-314-2 and 0-FP-CB-1-314-3 did not have a 3-hour fire barrier conduit and the penetration seals were degraded.
The inspectors reviewed Calculation 85-125-0-26-F, Control Building Cable Access Way Penetration Evaluation, which evaluated cables in conduit runs that begin in the turbine building cable tunnel, pass through the 23-foot elevation of the control building cable access way and exit into the cable spreading rooms or, continue to the 49-foot elevation of the cable access way and exit into the control room area. The calculation assumed that all cables in the cable access way are located within continuously enclosed conduits to preserve the integrity of the 3-hour rated fire barrier.
The inspectors reviewed licensee specification 118-003, Selection and Installation of Fire Barrier and Pressure Boundary Penetration Seals, Section 5.3, which discusses the requirements for internal conduit seals. The specification allowed either an open-ended conduit with a 3-hour fire seal or a continuously enclosed conduit. Section 5.3.4.1 states, An open ended conduit which extends 5 feet or less from the face of the barrier is required to be sealed with a 3-hour rated fire seal. Section 5.3.6.1 states, in part, Continuous, enclosed conduits do not require a 3-hour fire seal at the barrier. The inspectors determined that the three cables were not installed in continuously enclosed conduits, nor had 3-hour fire seals. After the inspectors questions, the licensee wrote NCR 746606 and took action to seal all three penetrations with a qualified 3-hour fire seal per WO 13506878.
Analysis:
The inspectors determined that the licensees failure to maintain the 3-hour penetration fire barrier conduits in the Unit 2 cable access way, as required by licensee specification 118-003, was a performance deficiency. The finding was more than minor because it was associated with the external factors attribute (i.e., fire) of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in the failure of the three conduits to perform their function. Using Inspection Manual Chapter 0609.04, Phase 1-Initial Screening and Characterization of Findings, the finding was determined to require additional evaluation under Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because the finding affected the ability to confine a fire. Using IMC 0609, Appendix F, 1, Fire Protection SDP Phase 1 Worksheet, dated September 20, 2013, the finding was assigned to the Fire Confinement category because the degraded penetrations were located in a fire barrier that separated two fire areas. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined the finding was of very low safety significance (Green) because safety- significant equipment was located a sufficient distance from the degraded penetrations and the reactors ability to reach and maintain a safe shutdown condition was not impacted. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance.
Enforcement:
License Condition 2.B.(6), Fire Protection Program, requires, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program. Calculation 85-125-0-26-F assumes that all of the cables in the cable access way are located within continuously enclosed conduits to preserve the integrity of the 3-hour rated barrier. Licensee specification 118-003, Selection and Installation of Fire Barrier and Pressure Boundary Penetration Seals, Section 5.3, allowed either an open-ended conduit with a 3-hour fire seal or a continuously enclosed conduit. Contrary to the above, from plant startup to April 6, 2015, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program.
Specifically, three cables in the Unit 2 cable access way were not installed in continuously enclosed conduits, nor had 3-hour fire seals, which failed to preserve the integrity of the 3-hour rated barrier. Because this finding is of very low safety significance and was entered into the licensees CAP as NCR 740606, consistent with Section 2.3.2.a of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000324/2015002-01, Degraded Fire Barrier Seals in the Unit 2 Cable Access Way.
.2 Annual Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire brigade performance during a drill on May 8, 2015, and assessed the brigades capability to meet fire protection licensing basis requirements. The inspectors observed the following aspects of fire brigade performance:
- capability of fire brigade members
- leadership ability of the brigade leader
- use of turnout gear and fire-fighting equipment
- team effectiveness
- compliance with site procedures The inspectors also assessed the ability of control room operators to combat potential fires, including identifying the location of the fire, dispatching the fire brigade, and sounding alarms. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R06 Flood Protection Measures
.1 Internal Flooding
a. Inspection Scope
The inspectors reviewed related flood analysis documents and walked down the area listed below containing risk-significant structures, systems, and components susceptible to flooding. The inspectors verified that plant design features and plant procedures for flood mitigation were consistent with design requirements and internal flooding analysis assumptions. The inspectors also assessed the condition of flood protection barriers and drain systems. In addition, the inspectors verified the licensee was identifying and properly addressing issues using the CAP. Documents reviewed are listed in the
.
- Unit 2, South Residual Heat Removal Room
b. Findings
No findings were identified.
.2 Underground Cables
a. Inspection Scope
The inspectors reviewed related flood analysis documents and inspected the areas listed below containing cables whose failure could disable risk-significant equipment. The inspectors directly observed the condition of cables and cable support structures and, as applicable, verified that dewatering devices and drainage systems were functioning properly. In addition, the inspectors verified the licensee was identifying and properly addressing issues using the CAP. Documents reviewed are listed in the Attachment.
- Unit 2, Manhole 2-MH-6NW
- Unit 2, Manhole 2-MH-2SE
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification
(71111.11 - 1 sample)
a. Inspection Scope
On April 16, 2015, the inspectors observed a simulator scenario for the loss of offsite power conducted for training of an operating crew. The inspectors assessed the following:
- licensed operator performance
- the ability of the licensee to administer the scenario and evaluate the operators
- the quality of the post-scenario critique
- simulator performance Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Review of Licensed Operator Performance in the Actual
Plant/Main Control Room (71111.11 - 1 sample)
a. Inspection Scope
The inspectors observed licensed operator performance in the main control room on April 14, 2015, during a down-power of Unit 1 from 95 percent to 90.8 percent to perform a restart of 1B circulating water intake pump following a trip on low lube water flow. On April 4, 2015, the inspectors observed licensed operator performance in the main control room during the startup from the Unit 2 B222R1 refueling outage.
The inspectors assessed the following:
- use of plant procedures
- control board manipulations
- communications between crew members
- use and interpretation of instruments, indications, and alarms
- use of human error prevention techniques
- documentation of activities
- management and supervision Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors assessed the licensees treatment of the issues listed below to verify the licensee appropriately addressed equipment problems within the scope of the maintenance rule (10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants). The inspectors reviewed procedures and records to evaluate the licensees identification, assessment, and characterization of the problems as well as their corrective actions for returning the equipment to a satisfactory condition. The inspectors also interviewed system engineers to assess the accuracy of performance deficiencies and extent of condition. Documents reviewed are listed in the
.
- NRC Event Notification 49230, Part 21 Report, Deviation of ABB HK Circuit Breaker Close Latch Spring
- Reactor Protection System Limit Switches for the Main Steam Isolation Valves (MSIVs)
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the maintenance activities listed below to verify that the licensee assessed and managed plant risk as required by 10 CFR 50.65(a)(4) and licensee procedures. The inspectors assessed the adequacy of the licensees risk assessments and implementation of RMAs. The inspectors also verified that the licensee was identifying and resolving problems with assessing and managing maintenance-related risk using the CAP. Additionally, for maintenance resulting from unforeseen situations, the inspectors assessed the effectiveness of the licensees planning and control of emergent work activities. Documents reviewed are listed in the
.
- Unit 2, April 8, 2015, elevated risk condition for 2C CSW pump outage
- Unit 1, May 7, 2015, elevated risk condition for 1B CSW pump strainer leak and pump outage
- Units 1 and 2, May 8, 2015, elevated risk condition for Tropical Storm Ana
- Unit 1 , May 27, 2015, elevated risk condition for 1A electrohydraulic control (EHC)pressure regulator failure
- Unit 1, June 1, 2015, 1A SLC pump out of service
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
.1 Operability and Functionality Review
a. Inspection Scope
The inspectors selected the operability determinations or functionality evaluations listed below for review based on the risk-significance of the associated components and systems. The inspectors reviewed the technical adequacy of the determinations to ensure that TS operability was properly justified and the components or systems remained capable of performing their design functions. To verify whether components or systems were operable, the inspectors compared the operability and design criteria in the appropriate sections of the TS and updated the final safety analysis report to the licensees evaluations. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment.
- Units 1 and 2, EDG Incorrect Relay Model Installed in Governor Control Panel, April 16, 2015
- Unit 1, Core Spray North Sump Pump Non-Functional, April 22, 2015
- Unit 1, 1B CSW Pump Strainer Through-Wall Leak, May 7, 2015
- Units 1 and 2, EDG Basement Water Leaks, May 18, 2015
- Units 1 and 2, EDG Allen Bradley 700-RTC Relays for undeclared complex programmable logic devices for EDGs 1, 2 and 4, May 29, 2015
- Units 1 and 2, EDG 3 Exhaust Crack, June 23, 2015
b. Findings
Inadequate Procedure for the 1B Conventional Service Water Pump Strainer Repair
Introduction:
An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to have an adequate procedure to perform maintenance on the 1B CSW pump strainer.
Specifically, between August 28, 2009, and May 11, 2015, licensee procedure MNT-NGGC-0009, Application of Protective Coatings, was not adequate to perform repairs on the 1B CSW pump strainer, which resulted in through-wall leaks on three occasions.
Description:
On October 28, 2008, during ultrasonic testing of the 1B CSW pump strainer, two areas of localized wall thinning were identified in the area of the weld for instrument line 1-SW-V54. The licensee initiated NCR 303817, and determined the strainer was operable but degraded. On August 28, 2009, the licensee performed weld repairs to the outside of the strainer and installed Belzona coatings to the inside of the strainer under WO 1439816-01.
On June 23, 2010, the 1B CSW pump strainer developed a through-wall leak on the weld for instrument line 1-SW-V54. The licensee initiated NCR 406525. The cause of the through-wall leak was determined to be a lack of proper prepping of the surface area and application of the Belzona coating on August 28, 2009, due to relying on skill of the craft. This allowed water to get underneath the rubber Belzona coating and contact the carbon steel surface. The through-wall leak was a result of localized corrosion within the weld area from inside the strainer vessel. As corrective actions, the licensee performed a structural integrity evaluation and determined the area was structurally acceptable, repaired the through-wall leak under WO 1776265-01 on July 15, 2010, and conducted a training needs analysis for maintenance personnel on Belzona coating applications and application techniques. The licensee determined that no additional training was required. In 2011, a qualification guide (MEQ0062N) was created for Belzona coatings, and licensee procedure MNT-NGGC-0009, Application of Protective Coatings, was updated to include all the new coating qualification guides.
On October 5, 2014, the 1B CSW pump strainer again developed a pin hole through-wall leak on the weld for instrument line 1-SW-V54. The pump was stopped and subsequently restarted the next day. When the pump was restarted, the leakage worsened and a spray developed from the leak location. The pump was secured, declared inoperable due to the increased leakage, the licensee entered TS 3.7.2, Service Water System and Ultimate Heat Sink, to repair the strainer and initiated NCR 711625. The licensee determined the cause of the through-wall leak was the Belzona coating was not applied correctly in 2010. No training or qualification existed in 2010 when the 1B CSW pump strainer was last repaired and coated with Belzona. As corrective actions, the licensee performed a weld repair for the through-wall leak and recoated the area with Belzona coating under WO 13442338 on October 9, 2014. The licensee also created a qualification guide, and updated licensee procedure MNT-NGGC-0009 to ensure Belzona coatings were applied correctly on service water equipment, by qualified individuals.
On May 7, 2015, the 1B CSW pump strainer developed a through-wall weep on the weld for instrument line 1-SW-V54. During preparation for the ultrasonic test, a pin hole leak developed. The licensee declared the pump inoperable, entered TS 3.7.2, to repair the strainer, and initiated NCR 747712. As the area was cleaned and prepped for a weld repair, through-wall leaks were identified in three different areas. The exterior paint provided the only barrier against water leakage. The licensee performed a correct only evaluation, repaired the weld, and recoated the inside of the affected strainer area with Belzona coating under WO 13519970 on May 11, 2015.
The inspectors identified that the licensee did not perform a cause evaluation on the May 7, 2015, strainer failure to determine why the strainer had a through-wall leak in the same location for a third time, and therefore, no corrective actions were identified.
Due to the inspectors questions, the licensee concluded that procedure MNT-NGGC-0009 did not have adequate directions for application of the Belzona coating, and there was no acceptance or inspection criteria defined to determine if the coating was applied appropriately. The licensee generated EC 99149, Service Level III, Non-Safety Related, Augmented Quality Process Requirements for Coatings Applied to Service Water Systems, to add this documentation to procedure MNT-NGGC-0009 via procedure revision request 756034. The licensee also provided to maintenance personnel additional communications to emphasize the importance of using procedure MNT-NGGC-0009 in Belzona applications and provided additional training on the process and procedure requirements. The licensee plans to replace this strainer shell with a new strainer shell that will be rubber lined at the manufacturer under reoccurring preventative maintenance task 726808 in August 2015.
Analysis:
The inspectors determined that the licensees failure to have an adequate procedure to perform maintenance on the 1B CSW pump strainer was a performance deficiency. The finding was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, it could have led to a more significant failure of the 1B CSW pump strainer and the service water system.
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 human performance associated with the documentation attribute because the licensee failed to create and maintain complete, accurate and up-to-date documentation to correct the 1B CSW pump strainer through-wall leak issue on three occasions. [H.7]
Enforcement:
Appendix B to 10 CFR Part 50, 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, between August 28, 2009, and May 11, 2015, licensee procedure MNT-NGGC-0009, Application of Protective Coatings, was not appropriate to the circumstances to perform repairs on the 1B CSW pump strainer, which resulted in through-wall leaks on three occasions. As corrective actions, the licensee repaired the weld, recoated the inside of the affected strainer area with Belzona coating using qualified individuals, and updated procedure MNT-NGGC-0009. Because this finding is of very low safety significance and was entered into the licensees CAP as NCR 747712, consistent with Section 2.3.2.a of the NRCs Enforcement Policy, this violation is being treated as an NCV: NCV 05000325/2015002-02, Inadequate Procedure for the 1B Conventional Service Water Pump Strainer Repair.
.2 Operator Work-Around Review
a. Inspection Scope
The inspectors performed a detailed review of the licensees operator work-around, operator burden, and control room deficiency lists for the station in effect on June 29, 2015, to verify that the licensee identified operator workarounds at an appropriate threshold and entered them in the CAP. The inspectors verified that the licensee identified the full extent of issues, performed appropriate evaluations, and planned appropriate corrective actions. The inspectors also reviewed compensatory actions and their cumulative effects on plant operation. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors verified that the plant modification listed below did not affect the safety functions of important safety systems. The inspectors confirmed the modifications did not degrade the design bases, licensing bases, and performance capability of risk significant structures, systems and components. The inspectors also verified modifications performed during plant configurations involving increased risk did not place the plant in an unsafe condition. Additionally, the inspectors evaluated whether system operability and availability, configuration control, post-installation test activities, and changes to documents, such as drawings, procedures, and operator training materials, complied with licensee standards and NRC requirements. In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with modifications. Documents reviewed are listed in the Attachment.
- EC 89578, Fukushima Response Project - Spent Fuel Pool Wide Range Level Indication - Unit 2
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors either observed post-maintenance testing or reviewed the test results for the six maintenance activities listed below to verify the work performed was completed correctly and the test activities were adequate to verify system operability and functional capability.
- Units 1 and 2, WO 13501131, March 22, 2015, Main Stack Radiation Monitor Sample Pump Loss of Flow
- Units 1 and 2, WO 13502384, March 23, 2015, EDG 3 RCR Relay Suppressive Diode Installation
- Unit 2, WO 13503239, April 3, 2015, Division II Pressure Regulator 2-RNA-PCV-5247 Replacement
- Unit 2, WO 13509326, April 8, 2015, 2C CSW Pump Strainer Shear Pin Failure
- Unit 2, WO 2299262, April 8, 2015, HPCI Steam Admission Valve 2-E41-F001 Replacement
- Unit 2, WO 13509700, April 10, 2015, 2C RHRSW Booster Pump Motor Oil Leak The inspectors evaluated these activities for the following:
- acceptance criteria were clear and demonstrated operational readiness
- effects of testing on the plant were adequately addressed
- test instrumentation was appropriate
- tests were performed in accordance with approved procedures
- equipment was returned to its operational status following testing
- test documentation was properly evaluated Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with post-maintenance testing. Documents reviewed are listed in the Attachment.
b. Findings
.1 Failure to Perform an Adequate Extent of Condition Review for the 1C Conventional
Service Water Pump Strainer
Introduction:
An NRC-identified Green finding of licensee procedure CAP-NGGC-0205, Condition Evaluation and Corrective Action Process, was identified for the licensees failure to perform an adequate extent of condition review for the 1C CSW pump strainer stop collar clearance issue. Specifically, between February 21, 2014, and April 8, 2015, the licensee failed to perform an adequate extent of condition to identify the 2C CSW pump strainer stop collar was also installed without being securely positioned. This resulted in the failure of the shear pin and inoperability of the 2C CSW strainer and pump.
Description:
On April 8, 2015, the 2C CSW pump strainer shear pin failed, which resulted in the strainer not rotating, and entry into TS 3.7.2 for the 2C CSW pump being inoperable. The licensee repaired the strainer using licensee procedure 0PM-STR500, R.P. Adams Self-Cleaning Strainers, Models VWS 10 Through 40.
The inspectors determined a similar failure occurred on February 13, 2014, when the 1C CSW pump strainer shear pin failed, as documented in NCR 668564. The licensee performed a quick cause evaluation and determined the cause of the February 2014 strainer shear pin failure was the inadequate dimpling process, which allowed a gap to exist between the collar and the motor. This allowed the collar to come loose from the shaft and slide down, which resulted in an immediate failure. This was due to inadequate procedural guidance in procedure 0PM-STR500, which allowed the stop collar to be installed with a 1/8-inch clearance between the stop collar and the gear motor housing. However, Vendor Instruction Manual FP-20234, R.P. Adams CO., INC.,
Strainers, Poro-Edge Automatic, Maintenance Section, states, ensure that the stop collar is securely positioned against the underside of the gear motor. The corrective actions were to revise procedure 0PM-STR500 in accordance with the vendor manual and to reinstall the stop collar securely in accordance with the vendor manual.
The licensee performed an extent of condition review for the quick cause evaluation in NCR 668564, which stated, the as-found condition is only applicable to the 1C CSW pump strainer; however, by design, the potential exists for each of the service water strainer shear pins to fail. All of the service water strainers were inspected at time of discovery with no additional shear pin issues identified. The inspectors determined the licensee only performed a visual inspection of the shear pins to determine if any were currently failed. The licensee identified no corrective actions for the other strainers in NCR 668564.
The inspectors reviewed licensee procedure CAP-NGGC-0205, section 3.0, Definitions, Definition 21, which defines quick cause evaluation, in part, as an evaluation conducted to understand the extent of condition, likely cause, and develop appropriate corrective actions. Since the condition was determined to be a gap between the stop collar and gear motor housing, the inspectors determined that that the extent of condition inspection should have determined if this gap also existed on the other strainers, and not just if the shear pins were intact. The inspectors determined the licensee did not perform an adequate extent of condition inspection and did not identify and correct the shear pin gap issue on the 2C CSW pump, which resulted in the failure of the shear pin.
After the inspectors questions, the licensee performed a quick cause evaluation for the 2C CSW pump shear pin failure. The licensee determined the cause of the strainer shear pin failure was that the strainer stop collar was not installed securely, which allowed vertical movement in the strainer motor shaft and abnormal wear on the pin.
This issue was documented in NCR 742444. The licensee corrective actions included expediting maintenance to fix the stop collar gap on the remaining strainers, including the 1A CSW pump, 2A CSW pump, 1B nuclear SW pump, and the 2A nuclear SW pump.
Analysis:
The inspectors determined that the licensees failure to perform an adequate extent of condition review for the 1C CSW pump strainer stop collar clearance issue, as required by licensee procedure CAP-NGGC-0205 was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in the failure of 2C CSW pump strainer shear pin, and inoperability of the 2C CSW strainer and pump. 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 problem identification and resolution associated with the evaluation attribute because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee failed to evaluate the applicability of the stop collar clearance issue to the other strainers after the failure of the 1C CSW pump strainer shear pin. [P.2]
Enforcement:
This finding does not involve enforcement action because no violation of a regulatory requirement was identified since the licensee failed to follow their procedure CAP-NGGC-0205, Condition Evaluation and Corrective Action Process. The licensee entered this issue into the CAP as NCR 742444. Because this finding does not involve a violation and is of very low safety or security significance, it is identified as FIN:
FIN 05000324/2015002-03, Failure to Perform an Adequate Extent of Condition Review for the 1C Conventional Service Water Pump Strainer.
.2 (Opened) Unresolved ltem (URl)05000324/2015002-05, 2C Residual Heat Removal
Service Water Pump Oil Leak
Introduction:
The inspectors opened a URI to review the licensees evaluation of the motor oil leak on the 2C RHRSW pump and determine if there is a performance deficiency.
Description:
On April 8, 2015, the licensee identified an oil leak on the motor for the 2C RHRSW pump in excess of the amount that would be acceptable for the pump to meet the 30-day mission time, and the pump was declared inoperable. The licensees immediate corrective actions were to apply sealant to the mechanical joints of the bearing housings. The licensee entered this issue in the CAP as NCR 742643. This issue is being tracked as a URI: URI 05000324/2015002-04, 2C Residual Heat Removal Service Water Pump Oil Leak.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
Unit 2 began the inspection period in refueling outage B222R1. The inspectors reviewed outage plans and contingency plans for the Unit 2 refueling outage 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 following outage activities:
- 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.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the surveillance tests listed below and either observed the test or reviewed test results to verify testing adequately demonstrated equipment operability and met TS and licensee procedural requirements. The inspectors evaluated the test activities to assess for preconditioning of equipment, procedure adherence, and equipment alignment following completion of the surveillance. Additionally, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with surveillance testing. Documents reviewed are listed in the Attachment.
Routine Surveillance Tests (71111.22 - 4 samples)
- Unit 1, 1OP-19, High Pressure Coolant Injection System Operating Procedure, February 20, 2015
- Unit 2, 2MST-RPS22HR, Reactor Protection System Outboard Main Steam Line Isolation Valve B21-F028D Closure Channel Calibration, February 26, 2015
- Units 1 and 2, 0PT-12.2A, No. 1 Diesel Generator Monthly Load Test, April 3, 2015 Containment Isolation Valve (71111.22 - 1 sample)
- Unit 1, 0ENP-16.1, Inservice Test Pump and Valve Data, June 8, 2015 Reactor Coolant System (RCS) Leak Surveillance (71111.22 - 1 sample)
- Unit 1, 1OI-03.1, Reactor Operator Daily Surveillance Report, June 15, 2015
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed the emergency preparedness drill conducted on April 16, 2015.
The inspectors observed licensee activities in the simulator and/or technical support center to evaluate implementation of the emergency plan, including event classification, notification, and protective action recommendations. The inspectors evaluated the licensees performance against criteria established in the licensees procedures.
Additionally, the inspectors attended the post-exercise critique to assess the licensees effectiveness in identifying emergency preparedness weaknesses and verified the identified weaknesses were entered in the CAP. Documents reviewed are listed in the
.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors reviewed a sample of the performance indicator (PI) data, submitted by the licensee, for the Unit 1 and Unit 2 PIs listed below. The inspectors reviewed plant records compiled between April 1, 2014, through March 31, 2015, to verify the accuracy and completeness of the data reported for the station. The inspectors verified that the PI data complied with guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures. The inspectors verified the accuracy of reported data that were used to calculate the value of each PI.
In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with PI data. Documents reviewed are listed in the Attachment.
Cornerstone: Mitigating Systems
- Safety System Functional Failures
- Emergency AC Power Systems
- Cooling Water Systems
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review
The inspectors screened items entered into the licensees CAP to identify repetitive equipment failures or specific human performance issues for follow-up. The inspectors reviewed condition reports, attended screening meetings, or accessed the licensees computerized corrective action database.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors reviewed issues entered in the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, extent of condition evaluations, and cause evaluations, but also considered the results of inspector daily condition report screenings, licensee trending efforts, and licensee human performance results. The review nominally considered the 6-month period of January 1, 2015, through June 30, 2015, although some examples extended beyond those dates when the scope of the trend warranted. The inspectors compared their results with the licensees analysis of trends. Additionally, the inspectors reviewed the adequacy of corrective actions associated with a sample of the issues identified in the licensees trend reports. The inspectors also reviewed corrective action documents that were processed by the licensee to identify potential adverse trends in the condition of structures, systems, and/or components as evidenced by acceptance of long-standing non-conforming or degraded conditions. Documents reviewed are listed in the
.
b. Findings and Observations
No findings were identified.
The inspectors evaluated a sample of condition reports generated over the course of the past two quarters by departments that provide input to the quarterly trend reports. The inspectors determined that, in most cases, the issues were appropriately evaluated by licensee staff for potential trends and resolved within the scope of the corrective action program. However, the inspectors noted on the following three occasions that operations personnel did not follow procedures due to an issue being of short duration, even though this is not allowed by the procedure:
- Failure to classify the following two examples as operator workarounds:
o Unit 2 SLC tank level indicator clogged as discussed in FIN 05000324;05000325/2014004-04, Failure to Correct SLC Tank Level Indication Degradation.
o Drywell air temperature resistance temperature detector 2-CAC-TE-1258-17 failed low as described in NCR 747336.
- Failure to protect the 1B SLC subsystem during the 1A SLC subsystem outage as described in NCR 752032.
The inspectors considered that, while not a violation of regulatory requirements, this was an opportunity to identify a trend in the use of procedures by operations personnel. The licensee entered this issue into the CAP as NCR 758709.
4OA6 Meetings, Including Exit
On July 16, 2015, the resident inspectors presented the inspection results to Mr. William R. Gideon and other members of the licensees staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
W. Gideon Vice President
J. Krakuszeski Plant Manager
- K. Allen Director, Design Engineering
- A. Brittain Director, Nuclear Plant Security
J. Bryant Senior Nuclear Engineer
- K. Crocker Manager, Nuclear Emergency Preparedness
- M. Goddard Program Manager, Fire Protection
- L. Grzeck Manager, Nuclear Regulatory Affairs
- R. Heiber Superintendent, Nuclear Maintenance
- J. Hicks Manager, Nuclear Training
- B. Houston Manager, Maintenance
- F. Jefferson Director, Nuclear Engineering
- J. Johnson Manager, Nuclear Chemistry
- J. Kalamaja Manager, Nuclear Operations
- T. King Manager, Outage and Scheduling
W. Murray Lead Nuclear Engineer
- E. Neal Acting Manager, Nuclear Rad Protection
- J. Nolin General Manager, Nuclear Engineering
- W. Orlando Superintendent, E/I&C
- F. Payne Manager, Nuclear Work Management
- A. Pope Director, Nuclear Operating Experience
- M. Schultheis Manager, Nuclear Performance Improvement
- M. Smiley Manager, Nuclear Ops Training
- R. Wiemann Director, Electrical/Rx Systems
- E. Williams Superintendent, Nuclear Maintenance
NRC Personnel
- G. Hopper Chief, Reactor Projects Branch 4
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000324/2015002-01 NCV Degraded Fire Barrier Seals in the Unit 2 Cable Access Way (Section 1R05.1)
- 05000325/2015002-02 NCV Inadequate Procedure for the 1B Conventional Service Water Pump Strainer Repair (Section 1R15.1)
- 05000324/2015002-03 FIN Failure to Perform an Adequate Extent of Condition Review for the 1C Conventional Service Water Pump Strainer (Section 1R19.1)
Opened
Pump Oil Leak (Section 1R19.2)