21st Annual Report, Volume II, Exhibit D.9, Report on Fact-finding Meeting by Diablo Canyon Independent Safety Committee (DCISC) at Diablo Canyon Nuclear Power Plant (DCPP) on February 28–March 1, 2011 by Robert J. Budnitz, Member, and R. Ferman Wardell, Consultant

1.0 Summary

The results of the February 28–March 1, 2011 fact-finding trip to the Diablo Canyon Nuclear Power Plant in Avila Beach, CA are presented. The subject addressed and summarized in Section 3 was as follows:

  1. Reactor Coolant Pumps
  2. Employee Concerns Program Visibility Initiative
  3. Digital Control Systems
  4. System Engineering Program
  5. License Renewal Update
  6. Foreign Material Exclusion Program
  7. Engineering Evaluation Rigor Improvement Action Plan
  8. Bob Budnitz Meet with Jim Becker, Site Vice-President
  9. Outage Safety Plan for Outage 2R16

2.0 Introduction

This fact-finding trip to the DCPP was made to evaluate specific safety matters for the DCISC. The objective of the evaluation was to determine if PG&E’s performance is appropriate and whether any areas revealed observations which are important enough to warrant further review, follow-up, or presentation at a Public Meeting. These safety matters include follow-up and/or continuing review efforts by the Committee, as well as those identified as a result of reviews of various safety-related documents.

Section 4—Conclusions highlights the conclusions of the Fact-finding Team based on items reported in Section 3—Discussion. These highlights also include the team’s suggested follow-up items for the DCISC, such as scheduling future fact-finding meetings on the topic, presentations at future public meetings, and requests for future updates or information from DCPP on specific areas of interest, etc.

Section 5—Recommendations lists specific recommendations to PG&E proposed by the Fact-finding Team. These recommendations will be considered by the DCISC. After review and approval by the DCISC, the Fact-finding Report, including its recommendations, is provided to PG&E. The Fact-finding Report will also appear in the DCISC Annual Report.

3.1 Reactor Coolant Pumps

The DCISC Fact-finding Team met with Corie Colburn, Senior Component Engineer for Mechanical Rotating Equipment, to discuss the DCPP Reactor Coolant Pumps (RCPs). This is the first specific DCISC review of DCPP RCPs.

There are four Westinghouse-provided electric-motor-driven RCPs for each nuclear unit, one for each Reactor Coolant System (RCS) primary flow loop. All eight RCPs are identical with their electric motors being unit-specific. The RCP electric motors are rated at ZZZ horsepower and operate at 480 Volts AC. The RCP pressure boundary is considered safety-related and is designed for seismic forces. Pump function is not safety-related, though it is important for assurance of reliable plant operation. If RCP operation is interrupted, the Reactor Protection System will shut down the reactor because of cessation of cooling water flow. Cooling flow is provided by natural circulation of reactor coolant around the RCS with heat rejection to the Steam Generators, which are in turn cooled by Auxiliary Feedwater. The only significant accident scenarios for RCPs are a locked rotor event or a failure of one of the pump seals, both of which are analyzed in the Final Safety Analysis Report (FSAR).

Each pump has three shaft seals. Seal water is injected at a nominal nine gpm into the No. 3 Seal with six gpm injected into the RCS and leak off of three gpm from the Number 1 and 2 seals. Seal water is important for cooling and leakage control to assure proper pump operation. Pump seals are given a general, non-intrusive inspection each year (8,760 operational hours) and a boroscope inspection of the pump rotor from inside every 10 years (87,600 operational hours). Pump seals are inspected with a boroscope typically every six years (52,560 operating hours), unless there are problems. Seals are being replaced on a three-cycle frequency. Because of the presence of Foreign Material, i.e., contamination, following the Steam Generator replacements, three Unit 1 RCP seals were replaced. This is considered typical practice.

In March 2010 a trouble-shooting team determined that RCP 1-4 Seal No. 2 leak-off was causing excessive RCS leakage. The seal leakage had increased several times due to several “thermal shock” events. Entering Refueling Outage 1R16 and with RCP 1-1 exhibiting excessive seal leakage, DCPP decided to inspect all RCP 1-1 and 1-4 seals. The RCP 1-4 inspections showed excessive or uneven wear on all three seals along with metallic debris. RCP 1-1 seals showed excessive wear and metallic debris. RCP 1-3 was also inspected and showed debris and abnormal wear. RCP 1-2 was left alone because its seals were operating normally and it has exhibited stable leak-off. The metallic debris was identified as coming from prior work performed on the seal injection line.

There were 14 corrective actions, which fell into the following categories:

  1. Increase component inspections when work is performed upstream of the seal injection lines
  2. Expand Foreign Material Exclusion (FME) high-risk zones to areas encompassing seal injection lines
  3. Augment flush procedures following physical work on seal injection lines
  4. Increase preventive maintenance (PM) on seal line components
  5. Perform a Seal Improvement Performance Plan to evaluate overall system, chemistry, and operating practices.
  6. Develop controls to assure only correct materials are used in replacement parts

These corrective actions have been completed. DCPP believes the FME problems will be found on all RCP seals and is applying the corrective to all RCPs for both units. The DCISC FF Team believed these corrective actions were appropriate.

RCP motors have generally been trouble-free. They are inspected regularly and re-built on-site over a ten-year schedule. Beginning December 2009, there have been multiple instances of TCP motor bearing temperatures spiking high and immediately returning to normal. These instances are being tracked in the Corrective Action Program to determine the cause of the spikes and to ascertain the need for any corrective actions.

RCS system health was Yellow (unacceptable) for Third Quarter 2010, improved to White (acceptable) at the end of 2010. These ratings were due to other than RCP problems.

Conclusions:
DCPP Reactor Coolant Pumps (RCPs) have performed well without significant problems. The RCP seals, which are sensitive to debris and thermal transients, are receiving proper attention in the form of periodic inspections, flushing of upstream seal water injection lines, and regular replacements.
Recommendations:
None

3.2 Employee Concerns Program (ECP) Visibility Initiative

The DCISC Fact-finding Team met with Rick Burnside, ECP Manager, and Russell Glines, ECP Investigator, to discuss results of the July 2010 NRC Problem Identification and Resolution (PI&R) inspection (Reference 6.1) pertaining to the DCPP ECP. The DCISC last reviewed the DCPP ECP at the DCISC February 10–11, 2010 Public Meeting (Reference 6.2) and the January 19–20, 2010 Fact-finding Meeting (Reference 6.3) when it concluded the following:

It appears that the Nuclear Safety Culture Survey and the Safety Conscious Work Environment (SCWE) Survey are effective in terms of receiving employee comments and answers regarding DCPP safety culture and work environment. DCPP should continue conducting these Nuclear Safety Culture and SCWE surveys. DCPP is in the process of conducting a 100% safety culture survey of all employees using the Nuclear Energy Institute (NEI) 09-07 report, “Fostering a Strong Nuclear Safety Culture” as guideline for this survey.

DCPP received a large number of Employee Concerns in 2008 and 2009 compared to years past. DCPP believes the NRC received the large number of allegations in 2008 and 2009 because there was an unusually long Steam Generator replacement outage in each of 2008 and 2009 with its associated unusually high work load and numbers of contractors. Given the trend in the number of allegations received by the NRC, the DCISC should continue to review the Employee Concerns Program at future Fact Finding Meetings.

The NRC PI&R inspection report determined that improvements could be made to enhance the visibility and use of the DCPP ECP. This was documented in a Notification and entered into the Corrective Action Program (CAP). From this, an action plan to promote the ECP was initiated. The action plan has the following six actions:

  1. Move the Generic Employee Training (GET) ECP presentation into Current Issues (CI). The ECP Group is developing stand-alone safety culture and ECP training to include a requirement to take the training on a recurring frequency.
  2. Place ECP posters with pictures of ECP Group personnel in various plant locations. These posters have already been placed throughout the plant. ECP and the DCPP Communications Department have developed an ECP communications plan. The first action has been completed–publication in the plant newsletter, “News You Can Use” on February 14, 2011.
  3. Promote ECP at various plant venues. The ECP Group continues to work with individual work groups to identify venues for ECP communications.
  4. Develop and deliver ECP communications.
  5. ECP promotional items.
  6. Consider anonymous Notification capability. This is to be incorporated following Outage 1R16.
Conclusions:
The action plan to increase visibility of the DCPP Employee Concerns Program appears to be appropriate.
Recommendations:
None

3.3 Digital Control Systems

The DCISC Fact-finding Team met with Scott Patterson, Instrumentation and Controls (I&C) Obsolescence Program Manager, for an update on DCPP’s use of digital controls. The DCISC last reviewed this subject at its October 24-25, 2007 Public Meeting (Reference 6.4) and its August 21–22, 2007 Fact-finding Meeting (Reference 6.5) when it concluded:

The DCPP Instrument and Control Long-Term Obsolescence Program was impressively conceived and implemented. The program appeared effective, and the Program Manager was knowledgeable and enthusiastic.

The discussion consisted of two parts: (1) DCPP I&C Obsolescence Management Program and (2) the Process Protection Systems (PPS) Replacement Project.

DCPP I&C Obsolesce Management Program

In the 1999–2000 timeframe DCPP began studying I&C obsolescence issues based on lessons-learned from replacements of components originally installed in the 1980s when the plant was built. Many components were no longer being manufactured or supported by the original vendors. The study resulted in an I&C Long-Term Strategic Plan with the following attributes:

The Long-Term I&C Strategy specified the use of a common upgradeable vendor platform for upgrades. The platform is based on a Triple-Modular Redundant Fault-Tolerant system with vendors having a wide customer base and proven customer support. Two platforms were specified: (1) triple-redundant Triconex system for safety-related and critical systems and (2) non-redundant but highly reliable Allen-Bradley components for the remaining systems. The formal I&C Obsolescence Management Program (OMP) was established in 2006.

Projects completed using the program include the following:

Upcoming Projects starting in 2011 include:

Though there have been challenges, overall the changes from analog to digital controls have been successful. DCPP has determined it best to perform programming of digital equipment itself, utilizing its Software Quality Assurance Program (SQAP), which the DCISC reviewed and found satisfactory in its December 10–11, 2010 Fact-finding Meeting (Reference 6.7).

Process Protection System Replacement Project (PPSRP)

The original Westinghouse 7100 analog protection sets were replaced in outages 1R6 and 2R6 with the existing Eagle 21 Process Protection System (PPS). The DCPP digital Eagle 21 PPS monitors plant parameters, compares them against setpoints, which if exceeded, provides signals to the Solid State Protection System (SSPS). The SSPS, in turn, evaluates the signals through coincident logic and performs Reactor Trip System (RTS) and Engineered Safety Features Actuation System (ESFAS) command functions to mitigate an event that may be in progress.

The PPSRP will replace the existing digital Eagle 21 Process Protection System with a software-based Triconex TRICON platform for the primary PPS functions and incorporate a logic-based Westinghouse/CS Innovations Advanced Logic System for functions, which require built-in diversity. The PPRP is scheduled to be implemented during outages 1R18 and 2R18 in February 2014 and September 2014, respectively.

The proposed PPS addresses current NRC regulations and guidance regarding Diversity and Defense-in-Depth. It will implement automatic protective functions in a logic-based system with built-in diversity that addresses software Common Cause Failure (CCF). DCPP plans to submit its PPSRP License Amendment Request (LAR) to the NRC in July 2011 and receive approval in 18 months, permitting installation in 2014. DCPP has already submitted its Defense-in-Depth and Diversity Evaluation to NRC. The LAR will include the following:

PPSRP suppliers must develop their hardware and software with an approved 10CFR50, Appendix B Quality Assurance Program, including an acceptable Validation and Verification Program. All systems developed or modified must be adequately tested before delivery. Pre-installation testing is performed by personnel familiar with the system but independent of the developers.

Digital reactor protection systems are relatively new for nuclear plants and the NRC. One plant, Oconee Nuclear Station (a Babcock & Wilcox PWR design), has NRC approval and will install its RPPS in Spring 2011.

Conclusions:
The DCPP I&C Obsolescence Management Program, which replaces obsolescent analog process control and/or monitoring systems with digital systems is impressive in its design, implementation, and accomplishments to date. One significant part of this program is the replacement of the Eagle 21 Reactor Process Protection System, the primary system used to monitor process variables and take actions to trip the Reactor and actuate Engineered Safety Features, as needed. This project is undergoing NRC review, and DCPP expects to complete installation in 2014. The DCISC should continue to monitor this project.
Recommendations:
None

3.4 Transformer Leaks

The DCISC Fact-finding Team met with Joe Goryance, Electrical Supervisor in the Instrumentation & Control and Electrical (ICE) Systems Department, for an update on transformer leaks. The DCISC last reviewed transformer leaks at its November 2010 Public Meeting (Reference 6.8), August 2009 Fact-finding Meeting (Reference 6.9) and April 2010 Fact-finding Meeting (Reference 6.10), when it concluded the following:

DCPP identified the apparent cause of its adverse trend in transformer oil leaks as being ineffective preventive maintenance program implementation. This was due to the low priority given to transformer coatings preventive maintenance, which resulted in corrosion and leaks primarily in tube and fin oil radiators. In the future transformer coatings maintenance will receive higher priority. DCPP decided that all other remaining transformer leak maintenance will be corrective. Although not pro-active, this practice appears acceptable if leaks are identified and repaired in a timely manner and if leaks remain small and non-safety significant. The DCISC should monitor DCPP transformer leaks.

DCPP has become more deliberate, aggressive, and organized in its approach to solving the station’s longstanding problems pertaining to the reliability of large power transformers and to the accompanying effect on the safety of station personnel. Unless dictated by station events, the DCISC should perform its next periodic progress review after the next refueling outage, 1R16.

DCPP wrote an Apparent Cause Evaluation (ACE) on its leaking transformers because of an apparent adverse trend of oil leaks, the earliest being identified in 1999. More than 50 oil leak issues were listed in the applicable Corrective Action Program (CAP) Notification. The earliest of these events were considered to be of a minor nature; however, some had progressed to the point of being significant.

Recent significant leaks, which potentially affected plant operation, included the following:

An analysis of leaks from 2000–2009 concluded the following breakdown:

An analysis of leaks from 2000–2009 concluded the following breakdown:
34.0% Flange or gasket leaks
23.4% Corrosion-based leaks
23.4% Leaking valves
19.2% Penetration, weld or other minor leaks (leak is not hitting the ground)

DCPP reported that maintenance and leak repair methods have been generally effective in addressing all but the severe corrosion-based leaks. These leaks, caused by tube or fin corrosion, have outpaced coatings maintenance schedules. The flat plate radiators have sharp edges, which do not hold paint as well as flatter-edged surfaces. This leads to faster corrosion and leakage on the edges. Numerous transformer radiators are being replaced in the next two upcoming outages.

DCPP identified the apparent cause of these leaks as ineffective preventive maintenance (PM) program implementation for transformer coatings. The corrective action is to increase the priority and frequency of transformer coating preventive maintenance. The ACE also noted that DCPP does not have a PM program for transformer valves and flange gaskets. The current PM for transformers includes thermography, oil testing and analysis, electrical testing, engineering and operations walkdowns, bushing cleaning, device testing and calibrations, and load tap changer maintenance. All remaining maintenance activities are corrective. DCPP performed an extent-of-condition review of active oil leaks and determined that no additional actions beyond the CAP Notifications and normal repairs are necessary. Although not pro-active in preventing non-corrosion-based leaks, this practice appears acceptable if leaks are identified and repaired in a timely manner and if leaks remain small and non-safety significant.

DCPP transformer leakage correction is part of its Long-term Transformer Plan. In Refueling Outage 1R16 DCPP replaced radiators in Start-up Transformer 1-1 and Auxiliary Transformer 1-2. Work on Auxiliary Transformer 1-1 was rescheduled. In Outage 2R7 DCPP will replace radiators on Start-up Transformer 2-1. The problem with the radiators was corrosion caused by salt-water mist from the ocean. The replacement radiators are made from painted galvanized metal. Depending on the specific leak, DCPP uses three stages of repair:

  1. Plant Maintenance employing epoxy sealant or paint
  2. PG&E Substation Maintenance
  3. Outside vendor using specialized clamps and injected epoxy

DCPP believes its transformer leaks are under control.

Regarding DCPP’s overall transformer actions, DCPP is moving one GE and one Elin transformer to group them together by unit and manufacturer (GE on Unit 2 and Elin on Unit 1). A specification for bids for personnel protective walls for the main transformers has been sent out with plans to install the walls in outages 2R17 or 1R18.

Conclusions:
It appears DCPP has taken a pro-active approach to its transformer leaks and has them under control.
Recommendations:
None

3.5 System Engineering Program

The DCISC Fact-finding Team met with Mike Wright, Mechanical Engineering Manager, and Ryan West, I&C/Electrical Engineering Manager, to discuss DCPP System Engineering and system health. The DCISC last reviewed system engineering and system health in January 2009 (Reference 6.11), when it concluded the following:

The DCPP System Engineering Program (SEP), found satisfactory by the DCISC in 2005, was determined by DCPP in early 2008 to be ineffectively implemented with respect to correcting system health problems. The Program was revised to center its focus on system health and strengthen System Engineers’ ability to correct system health problems. The revision appears promising, and the DCISC should closely monitor system health to ascertain its effectiveness.

The four levels of system health are as follows:

Healthy

Unhealthy

The Fact-finding Team reviewed the current system health, which was as shown in the following table:

Unit 1

Unit 1, Health for the red and yellow systems
System Health Color Months Unhealthy Expected Return to Healthy Actions for Healthy
Auxiliary Feedwater Yellow 4 3/11 ACE for Failed Valve Actuator
Emergency Diesel Generator Yellow 2 2/12 Increased Load Margin and Repair Banjo Bolts
HVAC Yellow 2 3/11 Evaluate ABVs Flows: CFCU Reverse Rotation; CFCU Breaker Tripping; Replace ASW Pump Room Fan; and Remove Dumper Panel SPV
4 kV Yellow 11 1R17  
480V Red 1 TBD Replace Relays Susceptible to EMI
125VDC Yellow 5 3/11 ACE for Failed Battery Cell
230 kV Yellow 35 2R16 Implement Reliability Project

Unit 2

Unit 2, Health for the red and yellow systems
System Health Color Months Unhealthy Expected Return to Healthy  
Extraction System Yellow 1 3/11  
Auxiliary Salt Feedwater Yellow 12 2R16 Intake Readiness/Spare Parts: intake Cathodic Protection
Emergency Diesel Generator Yellow 2 2/12 Increased Load Margin and Repair Banjo Bolts
HVAC Yellow 22 2R16 Evaluate ABVs Flows: CFCU Reverse Rotation; CFCU Breaker Tripping; Replace ASW Pump Room Fan; and Remove Dumper Panel SPV
4 kV Yellow 11 2R17  
480 V Red 1 TBD Replace Relays Susceptible to EMI
230 kV Yellow 34 2R16 Implement Reliability Project

Actions and dates were identified to return these systems to healthy as shown. The DCISC observed a Plant Health Committee (PHC) meeting in December 2010 (Reference 6.12) when it concluded, as follows, that DCPP system health is improving:

The December 15, 2010 DCPP Plant Health Committee (PHC) meeting was well run, focused on system and program health improvement, and garnered good participation from attendees. The Committee’s emphasis was on assuring action plans were being implemented to achieve acceptable plant health. It is apparent that the PHC has increased its effectiveness by more closely focusing on the health of plant systems, components, and programs than previously done, which has resulted in improvement in system health measures.

This is substantiated with the following chart showing the trend of unhealthy systems.

Systems Red/Yellow for Greater Than Refueling Cycle

The Fact-finding Team reviewed the current DCPP System Engineering Program (SEP) Procedure (Procedure TS5.ID1). Significant improvements had been made in 2009. The improvements centered on system engineers and their supervision focusing more time on system health, performing more robust system walk-downs, having more reviews of health with supervision, higher expectations for system health cards, and more emphasis on system health by the Plant Health Committee.

DCPP system engineers are responsible for the following:

∗ Improvements in this process to achieve a better focus on system health combined with a similar focus in the System Engineering Program have good potential for maintaining DCPP systems healthy.

The Fact-finding Team reviewed the system health reports in their new format for the following systems:

These health reports contain the following information:

The Action Plans include the reason for the problem condition, owner, CAP Notification number, tracking number, action type, status, due date, responsible individual, last updated date, whether required for healthy, and whether in Top 10 plant action items. The Fact-finding Team believed the new style system health reports to be effective in capturing the important aspects of system health and the actions and dates for a return to healthy.

Conclusions:
Improvements in the System Engineering Program combined with those in the Plant Health Committee process to achieve a better focus on system health have good potential for maintaining DCPP systems healthy. DCPP system health has improved since these changes were made.
Recommendations:
None

3.6 License Renewal Update

The DCISC Fact-finding Team met with Loren Sharp, Senior Director of Engineering; Terry Grebel, License Renewal Project Manager; and Kristy Dennision, Enercon Engineer, for an update on DCPP License Renewal. The DCISC last reviewed license renewal in September 2010 (Reference 6.13), when it concluded the following:

The DCPP License Renewal review by NRC appears to be progressing as expected. DCPP is answering the many NRC requests for additional technical information, which are typical of NRC license renewal reviews. There are no technical or programmatic issues with the NRC. DCPP expects to get its NRC Advisory Committee on Reactor Safeguards review in mid-2011. There are two intervener contentions being reviewed by the NRC for the future public hearing.

The DCPP License Renewal Application was submitted to the NRC on November 23, 2009, and on January 8, 2010, NRC staff determined that the application contained sufficient information for the NRC to formally file the application and begin technical review. The review process is a two-track process, one track consisting of the review of safety impacts in accordance with 10 CFR Part 54 and a second track consisting of review of the environmental impacts in accordance with 10 CFR Part 51. Public input is provided and hearings are scheduled concerning both tracks of this process.

The license renewal application process involves an Integrated Plant Assessment (IPA) safety review, which includes elements of scoping, screening, aging management review, aging management programs, and time-limited aging analyses activities, and the preparation of an environmental report addressing consistency issues with reference to the Coastal Zone Management Act. IPA scoping involves analysis of those safety-related plant systems, structures and components that are within the scope of license renewal; all non safety-related systems, structures and components whose failure could prevent satisfactory accomplishment of any of the safety-related features; and all systems, structures and components that demonstrate compliance with NRC regulations for fire protection, environmental qualification, pressurized thermal shock, anticipated transients without scram, and station blackout. This analysis is also correlated with the NRC Maintenance Rule. Only passive components which are not replaced periodically and for which no aging management is required by the NRC are included, because active components and the adequacy of existing aging management programs are reviewed using other processes.

The NRC Advisory Committee on Reactor Safeguards (ACRS) Subcommittee review meeting for the DCPP license-renewal application was on February 9, 2010. This followed completion of the draft NRC Safety Evaluation Report. DCPP presented and answered ACRS questions on the following items:

DCPP is working with NRC Staff to resolve the above open items.

NRC presented the following:

Though the NRC safety review is concluding, the NRC environmental review schedule has slipped, and the California Coastal Commission review is under way. The history and schedule are shown below.

History and schedule of NRC and California Coastal Commission
Milestone Schedule Date Actual Date
Receive license renewal application (LRA) 11/24/09 11/24/09
Publish Federal Register Notice (FRN)–LRA availability 12/11/09 12/11/09
Publish FRN–acceptance and opportunity for hearing 01/21/10 01/21/10
Publish FRN–environmental scoping meeting 01/21/10 01/27/10
Audit–Environmental  04/19/10 04/19/10
Public Meeting–License Renewal Overview 02/09/10 02/09/10
Public Meeting–Environmental Scoping 03/03/10 03/03/10
Deadline for filing hearing requests and petitions for intervention 03/22/10 03/22/10
Environmental scoping period ends 04/12/10 04/12/10
Audit–Scoping & Screening Audit Methodology 03/15/10 03/15/10
Audit–Aging Management Programs 04/12/10 04/12/10
Issue safety evaluation report (SER) with open items 12/10/10 01/10/11
Advisory Committee on Reactor Safeguards (ACRS) Subcommittee meeting 02/2011 02/09/11
Issue final SER 05/23/11  
Issue draft supplemental environmental impact statement (SEIS) 05/2011  
Publish EPA FRN–draft SEIS available for comments 05/2011  
Public Meeting–draft SEIS meeting 06/2011 or 07/2011  
ACRS Full Committee meeting 07/2011  
End of draft SEIS comment period 08/2011  
Issue final SEIS 01/2012  
Publish EPA FRN–availability of final SEIS 01/2012  
License Renewal decision TBD∗  

The following contentions by the San Luis Obispo Mothers for Peace (SLOMFP) have been accepted by the NRC for the upcoming hearing:

Contention TC-1
The applicant, Pacific Gas and Electric Company (PG&E), has failed to satisfy 10C.F.R. § 54.29’s requirement to demonstrate a reasonable assurance that it can and will “manage the effects of aging” in accordance with the current licensing basis. PG&E has failed to show how it will address and rectify an ongoing adverse trend with respect to recognition, understanding, and management of the Diablo Canyon Nuclear Power Plant’s design/licensing basis which undermines PG&E’s ability to demonstrate that it will adequately manage aging in accordance with this same licensing basis as required by 10 C.F.R. § 54.29.
Contention EC-1
PG&E’s Severe Accident Mitigation Alternatives (SAMA) analysis fails to satisfy 40 C.F.R. § 1502.22 because it fails to consider information regarding the Shoreline fault that is necessary for an understanding of seismic risks to the Diablo Canyon nuclear power plant. Further, that omission is not justified by PG&E because it has failed to demonstrate that the information is too costly to obtain. As a result of the foregoing failures, PG&E’s SAMA analysis does not satisfy the requirements of the National Environmental Policy Act (NEPA) for consideration of alternatives or NRC implementing regulation 10 C.F.R. §51.53(c)(3)(ii)(L).
Contention EC-2
PG&E’s Environmental Report is inadequate to satisfy NEPA because it does not address the airborne environmental impacts of a spent fuel pool accident caused by an earthquake adversely affecting DCNPP.
Contention EC-4
The Environmental Report fails to satisfy the National Environmental Policy Act (NEPA) because it does not discuss the cost-effectiveness of measures to mitigate the environmental impacts of an attack on the Diablo Canyon reactor during the license renewal term.

Note: On April 10, 2011, following the Fact-finding meeting, PG&E submitted a request to the NRC to defer its review of the DCPP license renewal until certain seismic reviews are completed in 2015.

Conclusions:
The DCPP License Renewal proceeding continues to progress with NRC’s draft Safety Evaluation Report (SER) having been released and the Advisory Committee on Reactor Safeguards (ACRS) Sub-Committee meeting completed. There are several open technical issues with the NRC, but these are being resolved, meaning that the technical portion of the application is being completed. The NRC has admitted four contentions by intervener San Luis Obispo Mothers for Peace. At the time of the Fact-finding meeting, it appeared that the license extension could be issued in early 2012, if the environmental review were to proceed on-schedule and the contentions were to be satisfactorily settled in the hearings; however, following the Fact-finding meeting, on April 10, 2011, PG&E submitted a request to the NRC to defer its review of the DCPP license renewal until certain seismic reviews are completed in 2015.

3.7 Foreign Material Exclusion (FME) Program

The DCISC Fact-finding Team met with Michael Gibbons, Mechanical Maintenance Manager and Acting Maintenance Services Manager (FME Program Manager); Rich Harvey, Outage Services Manager; and Craig Stolz, FME Program Manager, for an update on DCPP’s FME Program. The DCISC last reviewed FME at its June 13–14, 2007 Public Meeting (Reference 6.14) and its April 18–19, 2007 Fact-finding Meeting (Reference 6.15), when it concluded the following:

It appears that DCPP is taking appropriate actions to improve the Foreign Material Exclusion (FME) Program. Major changes will be made to the FME procedure after 1R14 and before 2R14 in Feb. 2008. Ms. Albin, the new FME Coordinator from outside DCPP, brings FME experience to DCPP. DCISC should review the FME program in the 4th quarter of 2007 after their procedure revision, assessment, Outage 1R14 results, and before Outage 2R14.

The objective of the FME program is to prevent the introduction of foreign material into plant systems or components. An FME program goal is to provide a focus on a preventive attitude among workers. This means workers should think through the activities they will perform in an FME area and take precautions to prevent introducing foreign material into plant equipment and systems.

DCPP had preventable FME events during Outage 1R16 and performed an Apparent Cause Evaluation (ACE) to identify causes and actions for improvement.

Outage 2R15 and 1R16 objectives were as follows:

Foreign Material Exclusion FME Program
FME Category 1R16 Actual (Goal) 2R15 Actual (Goal)
Threats/Vulnerabilities 9(6) 9(0)
Conditions 25(15) 22(0)

Of the total number of FME events identified in 1R16, ten events were preventable human performance errors in Maintenance (4), Radiation Protection (1), and Construction Services (5). Five of the ten were classified as FME Threats/Vulnerabilities, which could have had significant consequences or cause equipment damage if not detected. These five Threats/Vulnerabilities were 50% caused by in-house workers and 50% by supplemental workers.

The ACE described 46 Corrective Action Program (CAP) Notifications documenting FME events during 1R16 and compared these to FME events in Outage 2R15. These were very low-level incidents but were of concern to the plant. Of these 46:

∗ A separate ACE was performed for RCP seals. See Section 3.1 above.

Two apparent causes were identified:

  1. Organizational Weakness–awareness and FME prevention practices while working near or within FME areas have not been employed by supplemental and in0house personnel.
  2. Organizational Weakness–human performance tools for assisting workers preparing and performing work in high-risk areas are lacking.

Corrective actions include industry benchmarking to adopt good practices leading to reduced FME incidents and tightening up and better publicizing DCPP FME. DCPP FME is currently a Maintenance Department program but will become an official plant-wide “program” in mid-2011, which will raise its importance, visibility, and control. DCPP is updating its Job Hazards Analyses to include FME. There will be written outage FME plans beginning with Outage 2R16 in May 2011. DCPP is planning a post-Outage 2R16 FME self-assessment.

The DCISC Fact-finding Team reviewed the plant FME procedure (Reference 6.16) and concluded that it was appropriate to control FME effectively, if implemented properly. The procedure contains the following:

FME Program Health is shown in the following chart:

Foreign Material Exclusion Program Health

As shown in the chart, FME Program Health is Red (unhealthy) based on a rolling 6-month average of FME incidents. An improving trend exists (97+ scores for November, December, January and February as compared to the October 1R16 Outage score of -10), and DCPP expects program health to return to Green (healthy) in April 2011, barring no new events.

Conclusions:
DCPP’s Foreign Material Exclusion (FME) Program has shown degraded performance in the last two outages (2R15 and 1R16) but an improving trend since 1R16 in October 2010. DCPP is making improvements in the program to better address outage and non-outage FME performance. These improvements appear satisfactory, and the DCISC should continue to monitor DCPP’s FME performance.
Recommendations:
None

3.8 Engineering Evaluation Rigor Improvement Action Plan

The DCISC Fact-finding Team met with Susan Westcott, Director of Engineering, and Pat Nugent, Manager Technical Support Engineering, to review the status of DCPP’s Engineering Evaluation Rigor Improvement Action Plan. The DCISC last reviewed this item at the DCISC June 2–3, 2010 Public Meeting (Reference 6.17) when DCPP reported the following:

The latest [January 9, 2009] Quality Performance Assessment Report (QPAR) identified technical evaluation quality as a continuing challenge for DCPP. Training was conducted in 2009 on Licensing Basis Impact Evaluation (LBIE) process and quality evaluation and the issuance of a new procedure has resulted in increased quality of technical evaluations. A new challenge has been identified associated with the LBIE process and licensing basis documentation. In 2010, LBIE training and increased awareness of licensing basis issues, as well as on issues related to reliance on past assessments and evaluations were implemented as corrective actions including review by Engineering management. To improve performance additional oversight is being provided over the 10 CFR 50.59 process, which is a change process to the facility’s license. The QPAR also identified a lack of effectiveness in implementation of the PME Program.

In the August 11–12, 2009 Fact-finding Meeting (Reference 6.18) the DCISC concluded:

DCPP appears to have properly addressed the problem of inadequate technical evaluations related to its licensing and design bases; however, results are yet to be achieved, and the DCISC should monitor the effectiveness of corrective action.

NRC identified a significant cross-cutting aspect in it 2009 End-of-Cycle Letter of March 2010 for the lack of thoroughness in engineering evaluations in the P.1.c cross-cutting area described as follows:

The NRC staff has identified a substantive crosscutting issue in the area of problem identification and resolution associated with the thoroughness of problem evaluation. The staff first identified this item in the 2008 annual assessment letter, dated March 4, 2009. This theme continued through the 2009 mid-cycle assessment as discussed in our September 1, 2009 letter. The staff has concluded that this theme continued again through the current 12-month assessment period with six Green findings documented with this crosscutting aspect. Recent examples include: the failure to perform an adequate evaluation for damping values for the Unit 2 replacement reactor vessel head; the failure to identify and correct a degraded fire door latching mechanism; and an inadequate evaluation of operator actions related to the steam generator tube rupture accident analysis. While you have implemented a range of substantial corrective actions to address the crosscutting theme, these actions have yet to prove effective in mitigating the continuing trend. It is not apparent that you have fully evaluated the depth and breadth of the issue to ensure the effectiveness of your corrective actions. The NRC has concluded that you should assess why your past corrective actions have not been effective in mitigating the trend and make adjustments as appropriate to ensure that you achieve results in correcting the trend. We will monitor your progress in addressing this crosscutting issue through baseline inspections, including semi-annual trend reviews and the biennial problem identification and resolution team inspection. The substantive cross-cutting issue will remain open until we determine that corrective actions have resulted in sustained improved performance as demonstrated by no safety significant findings and a reduction in the number of findings with the same causal factor, specifically focusing on the most recent 6-month period reviewed in the assessment period.”

As of the date of this Fact-finding meeting (March 1, 2011), the NRC identified significant cross-cutting aspect was still outstanding.

Since the above reviews were released, DCPP has developed a formal “Evaluation Thoroughness Action Plan”. The plan is designed for DCPP engineering personnel to “ … perform rigorous evaluations using industry leading programs to analyze and resolve problems. “ These programs will be periodically assessed and updates using industry best practice. The Plan contains the following strategies:

Performance will be measured with the following:

∗ The licensee thoroughly evaluates problems such that the resolutions address causes and extent of conditions, as necessary. This includes properly classifying, prioritizing, and evaluating for operability and Issue reportability conditions adverse to quality. This also includes, for significant problems, conducting effectiveness reviews of corrective actions to ensure that the problems are resolved.

The Fact-finding Team requested the above self-assessment for review; however, it had been improperly performed, was not complete as of this meeting date, and a definitive completion date was not provided. This is a concern to the DCISC because this was to have been the first significant measure of a significant problem at DCPP. The DCISC should recommend that this self-assessment be promptly completed.

The Action Plan consisted of the following Objectives, each with multiple action items:

  1. Communicate the urgent need for change throughout the Station and align the leadership team. (All eight actions have been completed.)
  2. Develop and communicate a clear vision and strategy relative to evaluation thoroughness and leadership program governance and oversight. (All four actions have been completed.)
  3. Engage the workforce for broad-based action to resolve the issue(s) associated with thoroughness evaluations and other potential cross-cutting issues. (All seven actions have been completed.)
  4. Create short-term actions to provide interim improvements for program gaps identified. (All five actions have been completed. Except the Licensing Verification Project, a long-term project.)
  5. Monitor performance and provide feedback to fully ingrain the new methods and standards of performance into the way the Station does business. (All 13 actions have been completed.)
  6. Leverage LVBP [Licensing Basis Verification Project] to improve evaluation thoroughness and knowledge transfer. (All 11 actions are “on track” for completion on schedule before the end of 2011.)
  7. Utilize the systematic approach to training to identify gaps and leverage training to improve evaluation thoroughness. (All eight actions are “on track” for scheduled completion or have been completed.)
  8. Effectively identify non-conformances and ensure appropriate and thorough evaluations. (All four actions are “on track” for scheduled completion.)
  9. Monitor performance and provide feedback to fully ingrain the new methods and standards of performance into the way the Station does business. (All 13 actions are in progress.)

This Action Plan appears comprehensive and complete, and it contains appropriate measures of performance to gauge whether improvement is being achieved. The DCISC should periodically monitor the performance measures and assessments. Applicable assessments are as follows:

Conclusions:
DCPP has responded aggressively to the significant performance gaps identified in its engineering evaluation thoroughness and rigor. DCPP has developed a detailed, comprehensive Evaluation Thoroughness Action Plan. The Plan should be effective if implemented well; however, DCPP has not satisfactorily completed its first significant measure of corrective action: a self-assessment to have been performed in 2010. The DCISC should closely monitor the actions and performance measures in the Plan.
Recommendations:
The DCISC recommends that DCPP initiate and promptly complete its first self-assessment of the significant gap in engineering evaluation thoroughness, which was to have been completed by the end of 2010.
Basis for Recommendation:
The gap in engineering evaluation thoroughness at DCPP is a significant problem. It was recognized as such by DCPP Quality Verification in early 2009, by INPO in mid-2009, and by NRC in late 2009. DCPP has since performed an effective cause analysis and developed a comprehensive action plan to correct the problem; however, the first significant measure of corrective action effectiveness was to have been a self-assessment completed in 2010; however, this was apparently improperly performed and thus not useful as originally intended. The DCISC believes this self-assessment would have provided a substantially useful measure of progress and should be given high priority.

3.9 DCISC Member Meeting with DCPP Site Vice-President

DCISC Member Dr. Robert J. Budnitz met with DCPP Site Vice-President, Jim Becker, to discuss topics from this Fact-finding meeting and other subjects of interest.

3.10 Outage Safety Plan for Outage 2R16

The DCISC Fact-finding Team met with David Williams, Senior Reactor Operator and Operations Shift Foreman, to review the outage safety plan for Outage 2R16. The DCISC last reviewed an outage safety plan at its October 7–8, 2008 Public Meeting (Reference 6.19).

The purpose of the Outage Safety Plan is to provide information on outage safety requirements and highlight risk areas to plant staff. In order to assess outage safety impact, referral to the Outage Safety Plan and Outage Safety Schedule is to be made prior to making major schedule changes. The intent of the Outage Safety Plan is to provide a concise document to use in evaluating plant conditions during Modes 5 & 6 and Defueled to ensure the key safety functions are satisfied, while maintaining consistency with the Technical Specifications and Equipment Control Guidelines. DCPP’s outage safety program is designed around three major concepts:

  1. Prevention of any accident-initiating event.
  2. Mitigation of an accident before it potentially progresses to core damage.
  3. Control of radioactive material if a core damage accident should occur.

The Outage Safety Plan is based on the following:

The outage safety plan provides background information for the logic contained in the outage safety checklists. The checklists provide the logic used to develop the outage safety schedule. The schedule and checklists ensure that the equipment and plant conditions assumed in the shutdown abnormal procedures are met. These procedures contain guidance for providing passive core cooling and key system restoration.

Outage safety planning is based upon the assumption of a worst-case event, which is a loss of all AC power.

ORAM-Sentinel, a probabilistic risk analysis tool, was used to analyze the risk of boiling and core damage risk while fuel is in the reactor vessel based upon the outage schedule information. The boiling and core damage risk profiles are shown below.

Draft ORAM Safety Profile

Core Damage All Inits

The Outage Safety Plan identifies all “infrequently performed tests or evolutions.” For Outage 2R16, these are the following:

Additionally, there are several modifications for which contingencies are planned because of the potential for loss of some phases of electric power. These are:

As noted above, outage safety planning is based upon the assumption of a worst-case event, which is loss of all AC power. Backup decay heat removal capability is maintained during most of the outage by ensuring that if RHR or SFP cooling is lost, the natural physical laws will work to maintain passive cooling. When passive decay heat cooling is not available, a “High Risk Evolution” transition period is entered. The bulk of the Outage Safety Plan discusses what passive cooling is available during these periods.

The Outage Safety Plan also includes descriptions of recent DCPP and industry outage events in the Operating Experience Section. These are presented as lessons-learned to inform and prepare personnel for potential problem, which may arise.

Conclusions:
The DCPP Outage 2R16 Outage Safety Plan is a comprehensive and detailed document describing the schedule and steps in the outage, which are identified as high risks of core boiling or damage as a result of losing electric power and/or cooling to the reactor core and Spent Fuel Pool and what backup systems are available. The emphasis is on prevention of incidents, mitigation of accidents and control of radioactive material. The 2R16 Outage Safety Plan appears well designed to achieve outage safety.
Recommendations:
None

4.0 Conclusions

4.1
DCPP Reactor Coolant Pumps (RCPs) have performed well without significant problems. The RCP seals, which are sensitive to debris and thermal transients, are receiving proper attention in the form of periodic inspections, flushing of upstream seal water injection lines, and regular replacements.
4.2
The action plan to increase visibility of the DCPP Employee Concerns Program appears to be appropriate.
4.3
The DCPP I&C Obsolescence Management Program, which replaces obsolescent analog process control and/or monitoring systems with digital systems is impressive in its design, implementation, and accomplishments to date. One significant part of this program is the replacement of the Eagle 21 Reactor Process Protection System, the primary system used to monitor process variables and take actions to trip the Reactor and actuate Engineered Safety Features, as needed. This project is undergoing NRC review, and DCPP expects to complete installation in 2014. The DCISC should continue to monitor this project.
4.4
It appears DCPP has taken a pro-active approach to its transformer leaks and has them under control.
4.5
Improvements in the System Engineering Program combined with those in the Plant Health Committee process to achieve a better focus on system health have good potential for maintaining DCPP systems healthy. DCPP system health has improved since these changes were made.
4.6
The DCPP License Renewal proceeding continues to progress with NRC’s draft Safety Evaluation Report (SER) having been released and the Advisory Committee on Reactor Safeguards (ACRS) Sub-Committee meeting completed. There are several open technical issues with the NRC, but these are being resolved, meaning that the technical portion of the application is being completed. The NRC has admitted four contentions by intervener San Luis Obispo Mothers for Peace. At the time of the Fact-finding meeting, it appeared that the license extension could be issued in early 2012, if the environmental review were to proceed on-schedule and the contentions were to be satisfactorily settled in the hearings; however, following the Fact-finding meeting, on April 10, 2011, PG&E submitted a request to the NRC to defer its review of the DCPP license renewal until certain seismic reviews are completed in 2015.
4.7
DCPP’s Foreign Material Exclusion (FME) Program has shown degraded performance in the last two outages (2R15 and 1R16) but an improving trend since 1R16 in October 2010. DCPP is making improvements in the program to better address outage and non-outage FME performance. These improvements appear satisfactory, and the DCISC should continue to monitor DCPP’s FME performance.
4.8
DCPP has responded aggressively to the significant performance gaps identified in its engineering evaluation thoroughness and rigor. DCPP has developed a detailed, comprehensive Evaluation Thoroughness Action Plan. The Plan should be effective if implemented well; however, DCPP has not satisfactorily completed its first significant measure of corrective action: a self-assessment to have been performed in 2010. The DCISC should closely monitor the actions and performance measures in the Plan.
4.9
The DCPP Outage 2R16 Outage Safety Plan is a comprehensive and detailed document describing the schedule and steps in the outage, which are identified as high risks of core boiling or damage as a result of losing electric power and/or cooling to the reactor core and Spent Fuel Pool and what backup systems are available. The emphasis is on prevention of incidents, mitigation of accidents and control of radioactive material. The 2R16 Outage Safety Plan appears well designed to achieve outage safety.

5.0 Recommendations

5.1
The DCISC recommends that DCPP initiate and promptly complete its first self-assessment of the significant gap in engineering evaluation thoroughness, which was to have been completed by the end of 2010. (Section 3.8)

6.0 References

  1. 6.1 NRC Inspection Report
  2. 6.2 “Diablo Canyon Independent Safety Committee Twentieth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2009–June 30, 2010”, Approved November 17, 2010, Volume II, Exhibit B.6, Section 3.4, “DCPP Employee Concerns Program.”
  3. 6.3 Ibid., Exhibit D.6, Section 3.1, “Review of the DCPP Employee Concerns Program.”
  4. 6.4 “Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007–June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit B.1, “Instrumentation & Controls (I&C) Obsolescence Program Update Including Completed & Proposed Projects and Digital Systems Plans, Challenges, and NRC Initiatives.”
  5. 6.5 Ibid., Exhibit D.2, Section 3.4, “Instrumentation & Control (I&C) Long-Term Obsolescence Program.”
  6. 6.6 “Diablo Canyon Independent Safety Committee Seventeenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2006–June 30, 2007”, Approved October 15, 2007, Volume II, Exhibit D.9, Section 3.9, “Feedwater Control System.”
  7. 6.7 “Diablo Canyon Independent Safety Committee Twenty-First Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2010—June 30, 2011”, Approved October 11, 2011, Volume II, Exhibit D.7, Section 3.4 “Software Quality Assurance.”
  8. 6.8 Ibid., Exhibit B.3, “Transformer Update.”
  9. 6.9 “Diablo Canyon Independent Safety Committee Twentieth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2009–June 30, 2010”, Approved November 17, 2010, Volume II, Exhibit D.1, Section 3.1, “Adverse Trends with Transformer Oil Leaks.”
  10. 6.10 Ibid., Exhibit D.8, Section 3.5, “Status of Transformers and Associated Equipment and Components.”
  11. 6.11 “Diablo Canyon Independent Safety Committee Twentieth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2008–June 30, 2009”, Approved October 15, 2009, Volume II, Exhibit D.7, Section 3.3, “System Engineering Program and System Health.”
  12. 6.12 “Diablo Canyon Independent Safety Committee Twenty-First Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2010—June 30, 2011”, Approved October 11, 2011, Volume II, Exhibit D.7, Section 3.2, “Plant Health Committee.”
  13. 6.13 Ibid., Exhibit D.5, Section 3.5, “License Renewal.”
  14. 6.14 “Diablo Canyon Independent Safety Committee Seventeenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2006–June 30, 2007”, Approved October 15, 2007, Volume II, Exhibit B.9, “Foreign Material Exclusion Program.”
  15. 6.15 Ibid., Exhibit D.8, Section 3.1, “Foreign Material Exclusion Program.”
  16. 6.16 Diablo Canyon Nuclear Power Plant Interdepartmental Administrative Procedure AD4.ID6, “Foreign Material Exclusion Program,” Revision 15, February 22, 2011.
  17. 6.17 “Diablo Canyon Independent Safety Committee Twenty-First Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2010—June 30, 2011”, Approved October 11, 2011, Volume II, Exhibit B.9, “Overview of the Engineering Department.”
  18. 6.18 “Diablo Canyon Independent Safety Committee Twentieth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2009–June 30, 2010”, Approved November 17, 2010, Volume II, Exhibit D.2, Section 3.2, “Gap to Excellence in Engineering.”
  19. 6.19 “Diablo Canyon Independent Safety Committee Twentieth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2008–June 30, 2009”, Approved October 15, 2009, Volume II, Exhibit B.1, “1R15 Outage Scope and Safety Plan.”

For more information contact:

Diablo Canyon Independent Safety Committee
Office of the Legal Counsel
857 Cass Street, Suite D, Monterey, California 93940
Telephone: in California call 800-439-4688; outside of California call 831-647-1044
Send E-mail to: dcsafety@dcisc.org.