Report on Fact-finding Meeting by Diablo Canyon Independent Safety Committee (DCISC) at Diablo Canyon Power Plant (DCPP) on September 6 & 7, 2006 by William F. Conway, Member and Sheila Sheinberg and R. Ferman Wardell, Consultants [17th Annual Report, Exhibit D.2]

1.0 Summary

The results of the September 6-7, 2006 Fact-finding Trip to the Diablo Canyon Power Plant in Avila Beach, CA are presented. The subjects addressed and summarized in Section 3 include:

  1. 12kV System Review with System Engineer
  2. Transmission Grid Reliability
  3. Reactivity Management
  4. INPO Mid-Cycle Self-Assessment
  5. Boric Acid Corrosion Control
  6. 4kV System Cable Degradation & Replacement
  7. Long Standing Equipment Problems & Attend Plant Health Committee Meeting
  8. Safety Culture and Safety Conscious Work Environment
  9. Equipment Qualification Program
  10. Corrective Action Program
  11. Quality Verification Audit of the Software QA Program
  12. Vendor Manual Program
  13. Unit 2 Reactor Vessel In-Core Instrumentation Thimble Tube Leak
  14. DCISC Member Meeting with DCPP Management

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.

3.0 Discussion

3.1 12kV System Review with System Engineer

The DCISC Fact-finding Team met with Joe Goryance, 12kV System Engineer, and Gregg Rimer, Electrical System Design Engineer, to review and tour the system. The DCISC last reviewed the 12kV System at a Fact-finding meeting in November 2003 (Reference 6.1) and a public meeting in January 2004 (Reference 6.2). In its Fact-finding Report on that meeting the DCISC concluded the following:

PG&E has been correcting the problems with the 12 kV system as they occur, but appears to be slow with correcting the long-term problems that have been identified. Even though the 12 kV system is not a safety related system, it has had impacts on unit availability. DCISC should continue to review the corrective actions taken with the 12 kV system and include it in a Fact-finding Meeting in the 3rd or 4th Quarter of 2004.

The DCISC had the following recommendation in its 2003-2004 Annual Report:

PG&E should decide when they are going to perform a life-cycle management study of the 12 kV System and complete it on schedule. In the interim, they should proceed with corrective actions on the items identified in the system health report.

PG&E responded that, although the 12 kV System is a non safety-related system, it can definitely impact plant reliability. PG&E had finished a life cycle study on all the System’s transformers, and the 12 kV System is, basically, a small system which had almost all of its significant portions inspected and, with the exception of the grounding system, recently replaced. The DCISC considered this acceptable but would review the results of the study of the grounding system and the underground loop.

The 12kV System is a non-safety-related system that provides power for the operation and control of 12kV motor loads and distributes power to the 4160V System and to the site 12kV Underground system. As the standby/startup distribution system for the plant, the 12kV System supplies power to electrical auxiliaries during plant startup and shutdown operating modes. The System provides one of the sources of power to the 4160V Vital System for safe shutdown. These power supply requirements make the function of the 12kV System important to plant availability; however, no plant loads operating at 12kV are classified as safety related and the 12kV System does not perform a safety related function. The 12kV System provides power to such loads as the four Reactor Coolant Pumps and the Circulating Water Pumps, among others. The Fact-finding Team reviewed the 12kV System Health Card. The system has been “Green” for the past year but was downgraded to “White” status due to the following adverse trends:

  1. Unit 1 and 2 Auxiliary Transformers 25/12kV have a type of bushing which has been degrading in industry applications. DCPP experienced the first signs of degradation in 2R13. Replacements of these bushings have been approved by the Plant Health Committee (PHC) for Outages 1R14 and 2R14.
  2. Oil leaks common to Unit 1 and 2 oil-filled transformer radiators due primarily to the corrosive salt-spray environment – the radiators have been repaired as leaks occurred but will now be replaced when approved.
  3. Start-Up Control Circuit Isolation problems – a design has been proposed to separate Unit 1 and 2 tripping circuits to add another barrier to prevent an unintended actuation of the Start-Up System when one unit is in a maintenance outage. The change has been approved for completion by the end of Outage 2R14.
  4. The 12kV Underground Loop (a non-power-block power circuit) has tripped twice since August 2005 due to the tendency of ground currents and arcs. System changes have been approved by PHC and are awaiting Plant Review Committee (PRC) approval.

12kV System Health Card

12kV System Health Card
Unit 1 Unit 2
System Color Indicator White White
Gate
- Items in MR (a)(1) Status 0 0
- PAOs 0 0 (Prompt Operability Assmnts)
- Critical Equipment Event Clock Reset 0 0
- Significant Adverse Trend 0 0
Operating & Design Margin
- Components in Alert 0 0
- Control Board ARs 0 0 (Action Requests)
- Critical Component Failure 0 0
- Corrective Maintenance Backlog 0 0
- Non-Green Performance indicators 4 4
- Operator Burdens/Workarounds 0 0
- Plant health Issues approved as threats 2 2

The 12kV System was in Maintenance Rule a2 status – no significant MR items. There has been one Maintenance Preventable Functional Failure (MPFF) for an inadvertent actuation of the Unit 1 sudden pressure relay which caused a loss of Unit 2 Start-Up power. Actions are being taken to correct this situation.

The Fact-finding Team toured the system with Mr. Goryance generally following his System Engineering Walkdown checklist. The tour consisted of observing significant subcomponents and instruments of the following pieces of equipment:

The 12kV System is experiencing many of the same problems the DCISC observed in 2003 and 2004; however, there are now specific plans approved to correct the problems by the end of Outage 2R14. The System Engineer expects the system to be Green by December 2011 (2R16). The DCISC should continue to review the system.

Conclusion:
The 12kV System, a non-safety-related system supplying power to the Reactor Coolant Pumps and Circulating Water Pumps (among others), is currently in White health status (satisfactory with problems identified and being resolved). Many of the problems are long-standing ones; however, specific plans and funding have been approved for their correction. The system is expected to be Green by the end of 2011. The System Engineer appeared knowledgeable.

3.2 Transmission Grid Reliability

The DCISC Fact-finding Team met with Joe Goryance, 230kV and 500kV System Engineer, and Gregg Rimer, Electrical System Design Engineer, to review the reliability of the Transmission grid in supplying off-site power to DCPP in the event of a loss of station power. The DCISC last reviewed these systems in March 2006 (Reference 6.3). From that review the DCISC concluded the following.

The system health reports for both units are green (satisfactory performance) with repairs for the main transformer coolers scheduled for the next two outages (1R15 & 2R15). DCPP personnel are monitoring the work being conducted in the 500 kV switchyard and keeping the DCPP Control Room informed. The PG&E Operator in the 230/500 kV control room communicates with the Midway Switchyard Operator and the PG&E System Operator about transmission line outages and notifies the DCPP Control Room.

In February 2006 the NRC issued Generic Letter 2006-02: Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power. The purpose of the letter was to determine if compliance was being maintained with respect to grid reliability and the impact on plant risk and the operability of off-site power. The questions included the following subjects.

DCPP’s responses showed that their off-site power supplies were in compliance with NRC regulatory requirements regarding the capability of the transmission grid to reliably supply off-site powers.

Conclusion:
DCPP’s response to NRC’s generic letter on transmission grid reliability stated that their off-site power supplies were in compliance with NRC regulatory requirements regarding the capability of the transmission grid to reliably supply off-site power.

3.3 Reactivity Management

The DCISC Fact-finding Team met with Jim Welsch, Operations Manager, to review DCPP’s Reactivity Management (RM) Program. The DCISC last reviewed the Reactivity Management in April 2005 (Reference 6.4) at which time it concluded:

PG&E has made significant improvements in its Reactivity Management Program and organization and appears to be on a trajectory for an effective program. The DCISC should continue to monitor RM closely until DCPP Reactivity Performance Indicators show a sustained good performance.

The DCPP Reactivity Management Program was developed to assure conservative reactivity management by promoting a reactivity conscious culture for operating and maintaining the plant and to provide management expectations and standards for reactivity management. DCPP has an inter-departmental procedure (revised September 7, 2005) applicable to all of DCPP to provide heightened awareness for plant staff whose work has a potential to affect reactivity. The procedure assigns expectations for RM to those whose work could affect RM, specifically stating that:

“The operations manager is responsible for reactivity management, including the direct control of reactivity, and for ensuring conservative actions with regard to nuclear fuel integrity during operations, fuel handling, and storage. The operations manager has the single-point accountability for operational decision-making associated with reactivity management. The operations manager is responsible for the overall implementation of the Reactivity Management Program and the RMLT [Reactivity Management Leadership Team].”

and that

“The operator at the controls manages reactivity, but reactivity management is the responsibility of the entire licensed control room staff. Reactivity changes shall be conservative, deliberate and directly controlled.”

The procedure provides for and references other procedures controlling the operation of the following:

The procedure specifies use of pre-planned load reduction or increase ramps (based on recommendations from the Reactor Engineering Group), reactivity briefs by control room operators, oversight by Operations management, operator distractions, turnovers, boration/dilution monitoring, peer checks, control rod movement stop & check points, etc. The procedure requires use of conservative Operational Decision-Making when emergent issues result in the need to change unit load, especially at low reactor power. The DCISC Fact-finding Team believed the procedure was comprehensive and complete.

Operations performed a self-assessment of RM in January 2005. No findings were considered to be quality-related. Actions resulting from the self-assessment are as follows:

These items have been completed and are in-place at DCPP. Operations plans another self-assessment of RM later in 2006.

The DCISC Fact-finding Team reviewed the minutes from the August 9, 2006 and September 6, 2006 RMLT meetings. The meeting agendas consisted of the following:

Examples of RM Weaknesses were:

  1. Plant Process Computer (PPC)/plant data network reliability issues impact on RM – the PPC is being replaced.
  2. Complications with Reactor Coolant System (RCS) dilutions as a result of having the Units 1 and 2 primary water supplies cross-connected during replacement of the Unit 1 Primary Water Storage Tank (PWST) cover diaphragm. The cover has been replaced and the two units’ water supplies disconnected.
  3. Unit 1 manual and automatic rod control not working intermittently. Maintenance work has been performed and some circuit cards replaced with good results; however, monitoring is being continued.

Examples of RM Improvements were:

  1. Evaluate method of inserting Control Rods for reactor shutdown when entering a refueling outage.
  2. Provide Operations with simple calculations to predict the reactivity effects associated with swapping demineralizers and CVCS letdown filter changeout.
  3. Provide procedure guidance for delta-I control.
  4. Implement in BEACON a best-estimate Boron-10 methodology.
  5. Procedure improvements from Operation’s dropped rod training scenario on the simulator.
  6. Implement BEACON for core power distribution monitoring – it has been inoperable for performing Technical Specification power distribution surveillances because of the reliability concerns of the PPC.

Based on meeting minutes, the DCISC Fact-finding Team believed the RMLT is composed of the appropriate individuals and reviews the appropriate topics to assure DCPP RM is effectively implemented.

DCPP RM Performance Indicators measure the health of the RM Program. In addition to reactivity events, RM deficiencies are factor into the PIs until they are resolved. Deficiencies include such items as Areas for Improvement (AFIs), self-assessment results, work-arounds, equipment issues, the need for desk guides, program/process weaknesses, etc. For August 2006, for example, the 98% score was due to 2% lost due to program weaknesses (PPC reliability and Pressurizer steam space venting frequency) whereas no points were lost for reactivity events. The PIs have been White and Green over the last year, and the rolling 12-month value has steadily improved; however, it is below the goal (96.8% vs. 98%).

Conclusion:
The DCPP Reactivity Management (RM) Program appears to be well-designed and effectively implemented in assuring proper control of plant reactivity.

3.4 INPO Mid-Cycle Self-Assessment

The DCISC Fact-finding Team met with Ken Langdon, Outage Manager (and soon to be Operations Director), to review the two-week DCPP July 2006 mid-cycle INPO self-assessment. The DCISC last reviewed DCPP INPO activities in January 2006 (Reference 6.5). In that meeting report, the DCISC concluded the following:

DCPP’s April 2005 INPO evaluation was positive overall and contained 13 Areas for Improvement (AFIs) which DCPP is pursuing. DCPP has developed a new position dedicated to coordinating actions on INPO initiatives. This is a constructive move. The DCISC should continue to follow up on DCPP’s progress on INPO issues.

The purpose of the mid-cycle assessment was to determine the progress DCPP was making in resolving the 13 Areas for Improvement (AFIs) in the prior April 2005 INPO evaluation. The overall result of the assessment was that “ . . . there has been significant improvement in plant performance since the last INPO evaluation” as indicated by the following:

Eight Areas for Improvement (AFIs), six Performance Deficiencies, and four previous AFIs were considered open with concerns. The most significant areas in need of improvement were identified as follows:

  1. Some improvement efforts were falling short of targets: industrial safety, human performance, and worker qualifications. This has been due to lack of workforce engagement by management in terms of problem-solving and reinforcement of standards in the field.
  2. Work order package instructions and overall quality continue to require improvement.
  3. Four prior 2005 AFI s remain partially unresolved:

DCPP has developed an action plan to address these shortfalls. The DCISC should follow up on these items in a future Fact-finding meeting.

Conclusion:
DCPP’s mid-cycle INPO self-assessment found a number of significant improvements in station performance and four prior Areas for Improvement needing resolution as well as several new deficiencies. These are being addressed in an action plan. The DCSIC should follow up on these action plans.

3.5 Boric Acid Corrosion Control

The DCISC Fact-finding Team met with Jim Hill, Program Manager of the Boric Acid Corrosion Control (BACC) Program, for an update on the Program. The DCISC last reviewed BACC in May 2005 (Reference 6.6). At that time, the DCISC concluded the following:.

With exception of former ineffective program management which has now been addressed with a new Program Manager, the DCPP Boric Acid Corrosion Control Program appears satisfactory. DCPP has found no significant boric acid leaks on the reactor vessel upper or lower head connections. DCPP has identified over 500 boric acid leakers throughout the plant. Although classified as minor leakers, this number seems high to the DCISC. The DCISC notes that actions have been begun to review the list as a result of a Quality Verification assessment.:

Leaks from nuclear systems containing boric acid can cause unwanted corrosion of carbon steel components. The industry experienced enough boric acid leakage issues prior to 1988 to cause NRC to issue Generic Letter 88-05. This prompted the first formal BACC Program at DCPP. This was followed by additional NRC bulletins, including those issued in 2003 following the Davis-Besse reactor vessel corrosion event and South Texas discovery of boric acid leakage in its reactor vessel bottom head in-core instrument lines.

DCPP developed its plant leakage procedure following leakage it discovered and NRC GL 88-05. It provides guidance for responses to leaks from the ECCS post-LOCA recirculation flow path outside of containment and responses to other leaks as well. Each leak is identified in an Action Request (AR) and evaluated and corrected with the Corrective Action Program (CAP).

DCPP’s BACC procedure provides a comprehensive BACC Program to address boric acid corrosion concerns associated with the reactor coolant pressure boundary and other primary systems containing boric acid. The procedure addresses the following:

Each leak is identified and tracked with an Action Request (AR) and is added to the Boric Acid Leaker List Database. The list includes the leaking component, applicable AR, system, location, leak rate, a contact, and, in most cases, a link to a photograph. Many leaks are tracked by periodic walk downs.

BACC Program overall health was just into the “Green” category. The individual health of the four program cornerstones was:

@#8226; Program Personnel – Green

@#8226; Program Infrastructure – Green

@#8226; Program Implementation – Green

@#8226; Equipment/Related Plant Performance – White

The primary reasons for the above White performance items were:

  1. Broken Rockwell-Edwards valve packing followers which were replaced in Outage 1R13 (no corrosion/damage but measure needs 18 months to roll off)
  2. Some 1R3 items returned to service with corrective action deferred (no evidence of corrosion)
  3. More industry participation needed
  4. Some engineers need visual inspection training
  5. No self-assessment performed in last 24 months (a self-assessment is planned for 2006)

These issues were known to the Program Manager, and corrective actions were being taken.

Conclusion:
The DCPP Boric Acid Corrosion Control (BACC) Program appeared well-designed and implemented. The BACC Program Manager appeared to be knowledgeable and proactive.

3.6 4kV System Cable Degradation & Replacement

The DCISC Fact-finding Team met with Ken Kaminiski, System Engineer for the 4kV System, and Issa Zakaria, Cable Component Engineer, to review system cable degradation. The DCISC last reviewed this subject at the February 15-16, 2006 Public Meeting (Reference 6.7).

The 4kV System was in “Yellow” status due to the following two cable degradation issues:

4kV System Health Card

4kV System Health Card
System Color Indicator Unit 1 Yellow Unit 2 Yellow
- Components in Alert 0 0
- Control Board ARs 0 0 (Action Requests)
- Temporary Modifications 0 0
- Degraded Reactivity Control Compts 0 0
- Operator Burdens/Workarounds 0 0
- PAOs 0 0 (Prompt Operability Assmnts)
- Adverse Trends 0 0
- Leak Repairs 0 0

There were two issues common to both units responsible for the Yellow system status:

  1. Contaminants may have been introduced into medium voltage cables during the original cable manufacturing process prior to 1974. Based on this, DCPP identified an adverse trend of suspected insulation degradation of cables installed in underground conduits. There have been 10 cable failures. Corrective action is to replace all safety-related cables. About half of the cables have been replaced, and the remainder for both units are to be replaced by Outage 1R15 in May 2009
  2. Exposure to water trapped behind the conduit seals or sitting in dips in the 4kV duct bank conduits is resulting in accelerated aging of medium voltage cables in the form of lower insulation resistance, damage to the cable jacket, and corrosion of the shield. Corrective actions are to remove the conduit seals, inspect the conduits for water, and remove any water that is found. The bulk of inspections will occur in Outages 1R14 and 2R14 with final completion scheduled for Outage 1R17.

An as-found DC hi-pot (high potential) test to failure (5kV increments up to 80kV maximum) was performed on three of the 4kV bus H cables prior to being pulled out for replacement in 1R13. The CSP cables were tested to 80kV and did not fail. Both CCW cables failed to reach the final 80kV test value and failed at 14kV and 20kV; however, they showed acceptable test results higher than the 10.5kV maintenance test value and would have performed satisfactorily in service.

DCPP expects no imminent risk of cable failure, and replacements are planned on a risk-based approach such that a minimum of one train of safe shutdown equipment for each unit receives top priority. The health indicator will be changed to “White” upon replacement of cables to a complete train of safe shutdown equipment and inspection and removal of any water found in conduits. “Green” will be achieved when all safety-related cables are replaced.

Conclusion:
The DCPP 4kV System has been experiencing some insulation degradation in its underground in-conduit cables due to contaminants possibly introduced during manufacturing and due to water intrusion. DCPP has a satisfactory inspection, test and replacement program underway, although it may take until Outage 1R17 to complete all corrective actions for both units.

3.7 Long-standing Equipment Issues & Attend Plant Health Committee Meeting

The Fact-finding Team met with Bob Oldenkamp, Work Control Manager, to review the status of DCPP longstanding equipment issues. The DCISC has followed long-standing DCPP equipment issues via the The Institute of Nuclear Power Operators (INPO) evaluations, NRC reports, and Quality Verification (QV) Quality Performance Assessment Reports (QPARs). In its 2005 evaluation INPO identified long-standing issues as an Area for Improvement (AFI). In 2004 NRC identified a substantive cross-cutting issue in problem identification and resolution (it was removed in august 2005). DCPP QPARs have identified similar issues. DCPP developed a “zero tolerance” policy for long-standing equipment issues and took actions to address them. One of these actions was creation of the Plant Health Committee (PHC) and associated process for reviewing and approving funding for issues recognized as threats to safe plant operation in a disciplined, fact-based approach. The PHC can approve projects of $50,000 or less, the Project Review Committee (PRC) can approve levels of $1 million, and larger amounts must go to the corporate office.

The DCISC attended and observed a Plant Health Committee meeting during this Fact-finding meeting. The meeting was chaired by Jack Purkis, Maintenance Director and Plant Health Committee Chairman. Attendance is required for all line Directors and selected Managers. The agenda consisted of the following:

  1. Emergent Issues (Unit 1 Condensate Polishers in this case)
  2. Work Control Status Update
  3. PHC Update
  4. PHC Checkbook and Budget
  5. System Health Review (varies for each meeting)
  1. Main Feedwater System
  2. Main Steam System
  3. Extraction Steam System
  4. Auxiliary Steam System
  1. Outage 2R13 Bubble Chart
  2. Action Item Review

The meeting was well-planned and proceeded crisply; it was informative with good decision-making and questions; and participation was good. The process and Committee appeared to be effective.

The NRC removed the substantive cross-cutting issue in 2005 citing improvements in DCPP’s Corrective Action Program (CAP) and a reduction in long-standing equipment issues. QPARs no longer carry long-standing equipment issues as top quality problems. INPO’s next evaluation is not until 2007; however, the DCPP mid-cycle assessment (see item 3.4 above) found significant improvement in the area. DCPP’s List of [Resolved] Issues in History Status and List of Top Issues [“Threats”] demonstrate that substantial progress has been made in funding and resolving long-standing equipment problems. One possible exception is the issue of Containment Fan Cooler Unit Reverse Rotation Elimination which appears to have been put off until Outages 2R14 and 1R15, although considered significant by NRC. The DCISC should follow up on this item.

Conclusion:
DCPP’s actions to address and resolve long-standing equipment issues, including the Plant Health Committee and associated approval process, appear to be effective in approving, funding, and implementing equipment corrective actions.

3.8 Safety Culture and Safety Conscious Work Environment

The DCISC Fact-finding Team had a discussion with Rick Burnside, Supervisor of the Diablo Canyon Employee Concerns Program (ECP), to discuss Safety Culture and Safety Conscious Work Environment (SCWE) at Diablo Canyon. The DCISC last reviewed Safety Culture in September 2004 (Reference 6.8) and DCPP culture as a learning organization January 2006 (Reference 6.9) when it concluded the following:

DCPP has examined safety culture in the past through the use of a Synergy Survey, which resulted in the “WE Culture.” The DCISC believes that DCPP plans in 2005 to do a Safety Culture Assessment. DCPP recognizes that safety culture is an important issue. It was encouraging to see the Manager of the Employee Concerns Program (ECP) assume some responsibility for safety culture at DCPP.

and

DCPP has put additional focus on progressing as a Learning Organization through initiatives on improving the performance of its “learning programs” such as Corrective Action, industry Operating Experience, Self-Assessment, Management Observation, Benchmarking, etc.

DCPP has a new Program Directive on Nuclear Safety Culture (Reference 6.10) and a new Administrative Procedure on SCWE (Reference 6.11). The Program Directive sets forth the commitment to maintain a healthy nuclear safety culture, and a SCWE. The document defines Organizational Culture, Safety Culture, and SCWE.

Safety Culture is defined as “An organization’s values and behaviors – modeled by its leaders and internalized by its members – that serve to make nuclear safety the overriding priority.” SCWE is defined as “An environment in which employees feel free to raise concerns to their management, the Employee Concerns program (ECP), and the Nuclear Regulatory Commission (NRC) without fear of harassment, intimidation, retaliation, or discrimination. A SCWE is a critical element of a healthy Safety Culture.” The eight INPO Safety Culture Attributes are adopted verbatim in the directive.

It identifies the attributes of SCWE, as described by the Nuclear Regulatory Commission (NRC), the Principles for a healthy Safety Culture as described by the Institute of Nuclear Power Operations (INPO), Program Objectives and Program Requirements and specifies Program Responsibilities from Nuclear Executives, Managers and Supervisors to Contract Managers and Contract Supervisors, and Employee and Supplemental Personnel.

The Administrative Procedure focusing on Safety Culture and SCWE applies to Nuclear Generation Business Unit Employees and Supplemental Personnel working at Diablo Canyon. It covers:

  1. The roles and responsibilities for leadership, management, individual contributors, and supplemental personnel in supporting and maintaining a healthy Safety Culture and SCWE.
  2. Requirements for performing biennial Self-Assessments to determine management’s effectiveness in fostering a healthy Safety Culture and a SCWE.
  3. Training for employees and supplemental personnel in Safety Culture and in SCWE.

In addition to the definitions of Organizational Culture, Safety Culture, and Safety Conscious Work Environment (SCWE) found in the Program Directive, the Interdepartmental Administrative Procedure also includes definitions for Employee Concerns Program (ECP), Protective Activities, Chilling Environment or Chilling Effect, Contract Manager, and Supplemental Personnel.

The Interdepartmental Administrative Procedure defines responsibilities for Station Vice Presidents and/or Directors, the Self-Assessment Review Board, the Management Review Meeting, Managers and Supervisors, Contract Mangers and Contract Supervisors, the ECP Supervisor, and Individuals. Specifically, the Interdepartmental Administrative Procedure identifies the Employee Concerns Program (ECP) group, as the coordinator and monitor for Safety Culture and SCWE Surveys. In that role Mr. Burnside described himself as the “safety culture subject matter expert and program facilitator.” Jim Becker, Vice-President and Plant Manager, is the officer responsible for DCPP safety culture.

DCPP plans to conduct employee surveys on plant safety culture – the surveys will be conducted quarterly probably beginning in October 2006 and will each sample 10-20% of the plant population. The surveys will be based on the eight INPO Safety Culture Attributes. A test survey has been completed. Survey results will be discussed with managers and likely be put into the Corrective Action Program for action. Mr. Burnside has been involved in the development and administration of the USA Safety Culture Assessment which will be administered January 2008.

Mr. Burnside provided NRC data regarding Reactor Allegations received by NRC from 2002 to 2006. During this period, there were no Reactor Discrimination Allegations at Diablo Canyon, and there were no Reactor Open Allegations for Diablo Canyon. There was one Reactor Allegation Sustained with Violation Enforcement, occurring in 2003. Total Reactor Allegations received were: four in 2002; five in 2003; four in 2004; five in 2005; and one in 2006. Reactor Allegations sustained over this time period were: two in 2002; two in 2003; zero in 2004; one in 2005; and zero in 2006. Comparative data was also provided in each area for all Nuclear Power Plants, and Diablo Canyon was in the quartile with the fewest Reactor Allegations in all categories.

NRC, based on interviews conducted during its June 2006 Biennial Problem Identification and Resolution Inspection and Assessment of Safety Conscious Work Environment, concluded that “. . . a positive safety conscious work environment existed at Diablo Canyon Power Plant. The [NRC] team determined that employees felt free to raise safety concerns to station managers and supervisors, the employee concerns program, and the NRC. However, the team noted two isolated incidents regarding the environment that did not foster openly raising safety concerns. The licensee [DCPP] had already taken actions to address these concerns. All interviewees believed that potential safety issues were being addressed.”

The Diablo Canyon Independent Safety Committee should continue to monitor the effectiveness of both the Nuclear Safety Culture Program Directive, and the Interdepartmental Administrative Procedure for Safety Culture and SCWE.

Conclusion:
DCPP has formalized its Safety Culture and Safety Conscious Work Environment (SCWE) with a Program Directive and an Administrative Procedure defining safety culture and SCWE and defining roles and expectations of plant management and employees and specifying safety culture self-assessments and surveys. This should provide basis and discipline for a healthy safety culture.

3.9 Equipment Qualification Program

The DCISC Fact-finding Team met with Paul Johnson, Equipment Qualification (EQ) Program Manager, for an update on the program. The DCISC last reviewed this program in July 2003 (Reference 6.12) at which time it concluded the following:

The Corrective Action Plan for the EQ program seems thorough and complete. There are no remaining questions about the suitability of equipment now in service.

The EQ Program was rated “Green” overall with the following specific cornerstone ratings:

@#8226; Program Personnel – Green

@#8226; Program Infrastructure – Green

@#8226; Program Implementation – Green

@#8226; Equipment/Plant Performance – Green

A non-conformance report (NCR) was initiated in 2003 on the loss of configuration control in the EQ Program due primarily to the diversity and inconsistency of files and file formats resulting in questionable equipment qualifications. This has been rectified with an ordered approach more clearly documenting qualifications. The Plant Information Management System (PIMS) was updated to assure that it included the correct maintenance activities and replacement durations for EQ equipment. Additionally, the Purchasing Department reviewed all EQ file purchasing requirements against the inventory of plant parts and certifications supporting the EQ Program.

The Steam Generator (SG) Replacement Project (SGRP) will change the temperature profiles for the LOCA, MSLB Inside Containment and MSLB Outside Containment. Currently 45 files are scheduled for revision in the remainder of 2006 and a few devices have been identified as not meeting the new profiles. This equipment will be replaced with qualified equipment during the SGRP upgrade.

An audit of EQ files was completed in February 2006. Numerous problems with references being incomplete and page order issues were documented. These are being corrected. A self-assessment is planned for November 2006.

Conclusion:
The DCPP Equipment Qualification Program has made major progress in addressing weaknesses identified in 2003. Corrective actions are essentially complete, and the program appears healthy. Equipment replacements are planned along with the Steam Generator (SG) replacements because of changed temperature profiles as a result of the new SG design.

3.10 Corrective Action Program

The DCISC Fact-finding Team met with Chris Over, head of the DCPP Corrective Action Program (CAP), for an update on the Program. The DCISC last reviewed the DCPP CAP at a Fact-finding meeting in September 2005 (Reference 6.13) and a public meeting in October 2005 (Reference 6.14). At the Fact-finding meeting the DCISC concluded the following:

Overall, the DCISC Fact-finding Team considers the 2005 Quality Verification Corrective Action Program (CAP) Assessment and NRC’s removal of its substantive cross-cutting issue to be indicators of substantial progress in DCPP’s CAP improvement efforts. The DCISC agrees with their conclusions but will continue to closely follow the DCPP CAP improvement initiatives.

DCPP had made extensive change to its CAP following the 2005 INPO Evaluation and NRC Substantive Cross-cutting Issue. These included the following:

  1. Improve Senior Management oversight of the CAP
  2. Simplify the Corrective Action process
  3. Improve the quality of Root Cause Analyses to prevent recurrence
  4. Formally define and implement an Apparent Cause Evaluation process
  5. Clarify and formalize CAP implementation Roles and Responsibilities
  6. Improve plant general knowledge of CAP requirements
  7. Strengthen the Operability Determination Process and implementation
  8. Improve the Trending Program
  9. Improve metrics to more effectively measure the health of the CAP
  10. Establishment of the Corrective Action Review Board
  11. An independent review of past root cause analyses
  12. Additional training for root cause analyses
  13. Improvements to the Operability Determination Program
  14. CAP training for more than 1000 plant staff
  15. Apparent cause evaluation training for more than 230 individuals
  16. Establishment of cause, quality, timeliness metrics
  17. Improved metrics for program monitoring
  18. Establishment of governance to ensure sustainability.

These initiatives resulted in NRC removing its Substantive Cross-cutting Issue on Problem Identification and Resolution in August 2005. NRC performed its Biennial Identification and Resolution of Problems Inspection in June 2006. The NRC concluded that:

“ . . . in general, your processes to identify, prioritize, evaluate, and correct problems were effective; thresholds for identifying issues remained appropriately low and, in most cases, corrective actions were adequate to address conditions adverse to quality. Notwithstanding the above, a relatively high number of self-revealing and NRC identified findings were noted at your site during the assessment period. Ineffective and incomplete actions led to a number of repeat problems that could have been prevented, with a notable number of repeat findings of previously documented NRC-identified and self-revealing findings. Overall however performance had improved in all areas of your corrective action program since the last problem identification and resolution inspection.”

The NRC had no findings of significance in this inspection.

Mr. Over reported that there were three Root Cause Evaluations (RCEs) active at the time of the meeting. These were:

  1. Operator throughput – only 56% of the current new operator license class remained
  2. Individuals working without qualifications (the RCE included two union members)
  3. Reactor Vessel Thimble Tube Rupture – (see Item 3.13 below)

Mr. Over believed the CAP was getting good management support; however, DCPP needed better line involvement and a higher quality of resolution of corrective actions. These two items were to be part of benchmarking trips (including two union members) to North Anna Power Station and South Texas Nuclear Plant.

Conclusion:
It appears DCPP continues to make good progress in improvements to its Corrective Action Program (CAP). The biggest challenges include improved line involvement and better quality of resolution of corrective actions. The DCISC should continue to follow DCPP’s progress in its CAP improvements

3.11 Quality Verification Audit of the Software Quality Assurance (QA) Program

The Fact-finding Team met with Dave Taggart, Manager, Quality Verification (QV); Bob Prigmore, Supervisor of Quality Assessments; and Kathleen Hubbard, Lead Auditor; to review the DCPP Software QA Program (SQAP) QV audit. The DCISC last reviewed Software QA in October 2003 (Reference 6.15) and concluded the following:

Based on results of a self-assessment and an audit, the DCPP Software Quality Assurance Program appeared to be implemented satisfactorily but with some needed changes to make it more understandable and easier for personnel to implement.

SQA is a DCPP program intended to provide uniform requirements for preparing and maintaining computer software, applications and systems that are used to produce or manipulate data used directly in the design, analysis, and operation of plant structures, systems and components. The program is controlled by a plant procedure. The program applies to computer systems that are under complete plant control as well as those that are proprietary and maintained by vendors who are themselves required to have a similar SQA Program. There is a separate program for other business-related software.

The Fact-finding Team reviewed the July/August 2005 audit of the SQAP. The audit team concluded that overall the SQA activities assessed during the audit exhibited satisfactory performance. Additionally, the SQA Program Owner was found to be proactive in overseeing the program and driving beneficial enhancements such as the upgrade to the Application Index. Overall control and implementation of the SQA was satisfactory. Enhancements made to SQA procedures have resulted in clarity and ease of understanding.

The audit team initiated two Quality Problem Action Requests (ARs): (1) Voice Activated Notification System (VANS) SQA Plan and (2) Maintenance Rule SQA Plan, both plans being out-of-date and neither in compliance with the governing procedure “Software Management for Business Information Computer Systems.” The prior SQA self-assessment in 2003 had identified five Areas for Improvement and two Recommendations. Six of these had been completed. The seventh, enhancement of the Application Index, was on hold due to resource restraints but had the attention of the program owner.

Conclusion:
The Quality Verification of the DCPP Software Quality Assurance (SQA) Program concluded that the program was satisfactory overall. There were two Areas for Improvement regarding two outdated plans and some minor issues. These items are being tracked on Action Requests. The audit appeared thorough, and the SQA Program appeared sound.

3.12 Vendor Manual Program

The Fact-finding Team met with Larry Lodolo, Back-up Vendor Manual Program (VMP) Owner, to review the Program. This was the DCISC’s first review of this program.

The VMP is governed by Procedure CF7.ID4, “Processing of Documents Received from Vendors,” Revision 7, dated December 21, 2005. The procedure provides responsibilities, instructions, and controls for reviewing and/or processing incoming supplier documents that are new, revised, or supplemental to existing documentation. Control of vendor documents is important to assure that design, installation and maintenance on vendor-supplied components is performed in accordance with the most up-to-date, applicable document.

In November 2004 an Action Request (AR) was written to document two problems with the VMP:

  1. Vendor documentation (outline drawings, installation instructions, maintenance manuals, etc.) for newly-purchased components was not readily available to users because it was not properly documented and traceable to the component. The needed information was often found in procurement files instead of in the controlled document library.
  2. Existing vendor maintenance manuals were always not kept up-to-date.

Corrective actions for the above included the following:

  1. A meeting was held with Procurement, Engineering, and Maintenance Work Planners. The program procedure was revised to include an improved vendor manual review and control process.
  2. A new procedure CF7.ID5, “Vendor Manual Review Program,” was developed to identify previously-received safety-related equipment vendor manuals, contact applicable vendors, and incorporate the latest manual available applicable to DCPP equipment. The 790-manual review is being performed by a consultant jointly with other plants in the Utilities Service Alliance (USA) to be completed by 2008. DCPP personnel are performing a similar review for Westinghouse, GE and Barton equipment. The cycle will be repeated every three years.

The Vendor Manual Program health is currently White. DCPP believes is will return to Green in 2007. The health card is summarized below.

Vendor Manual Program Health

@#8226; Program Personnel – Green

@#8226; Program Infrastructure – Green

@#8226; Program Implementation – Green

@#8226; Equipment/Plant Performance – Green

Conclusion:
The DCPP Vendor Manual Program was determined in 2004 to have problems with manual control and disposition such that manuals were not always up-to-date and contained in the appropriate files. This is being corrected with a three-year review and update program. An improved control procedure has been developed to help assure proper manual control in the future.

3.13 Unit 2 Reactor Vessel In-Core Instrumentation Thimble Tube Leak

The DCISC Fact-finding Team arrived at DCPP on September 6, 2006 about a week after a one-to-two gallon per minute primary system leak inside Containment caused operators to ramp the Unit 2 reactor down on August 31, 2006 for investigation. The leak was from one of the Reactor Vessel In-Core Instrumentation Thimble Tubes and was stopped by closing an isolation valve. Unit 2 returned to full power on September 1 at about 5:30 am. Repairs to the thimble tube will occur during the next Unit 2 Refueling Outage (2R14) beginning in February 2008. There was no need for declaration of an unusual event and no radioactive discharge to the environment because of the leak.

The Fact-finding Team reviewed the leak investigation and photographs of the seal table area.

Conclusion:
It appeared that DCPP had successfully identified and isolated the source of a small leak of primary water from the Unit 2 Reactor Vessel In-Core Instrument Thimble Tube Table. Repairs will be made during Outage 2R14 in beginning February 2008.

3.14 DCISC Member Meeting with DCPP Plant Management

DCISC Member Bill Conway met separately with Jack Keenan, Senior Vice-President Generation and Chief Nuclear Officer, and with Donna Jacobs, Vice-President Nuclear Services to discuss items reviewed in this Fact-finding meeting and other items of interest to the Committee.

4.0 Conclusions

4.1
The 12kV System, a non-safety-related system supplying power to the Reactor Coolant Pumps and Circulating Water Pumps (among others), is currently in White status (satisfactory with problems identified and being resolved). Many of the problems are long-standing ones; however, specific plans and funding have been approved for their correction. The system is expected to be Green by the end of 2011. The System Engineer appeared knowledgeable.
4.2
DCPP’s response to NRC’s generic letter on transmission grid reliability stated that their off-site power supplies were in compliance with NRC regulatory requirements regarding the capability of the transmission grid to reliably supply off-site power.
4.3
The DCPP Reactivity Management (RM) Program appears to be well-designed and effectively implemented in assuring proper control of plant reactivity.
4.4
4.4 DCPP’s mid-cycle INPO self-assessment found a number of significant improvements in station performance and four prior Areas for Improvement needing resolution as well as several new deficiencies. These are being addressed in an action plan. The DCSIC should follow up on these action plans.
4.5
The DCPP Boric Acid Corrosion Control (BACC) Program appeared well-designed and implemented. The BACC Program Manager appeared to be knowledgeable and proactive.
4.6
The DCPP 4kV System has been experiencing some insulation degradation in its underground in-conduit cables due to contaminants possibly introduced during manufacturing and due to water intrusion. DCPP has a satisfactory inspection, test and replacement program underway, although it may take until Outage 1R17 to complete all corrective actions for both units.
4.7
DCPP’s actions to address and resolve long-standing equipment issues, including the Plant Health Committee and associated approval process, appear to be effective in approving, funding, and implementing equipment corrective actions.
4.8
DCPP has formalized its Safety Culture and Safety Conscious Work Environment (SCWE) with a Program Directive and an Administrative Procedure defining safety culture and SCWE and defining roles and expectations of plant management and employees and specifying safety culture self-assessments and surveys. This should provide basis and discipline for a healthy safety culture.
4.9
4.9 The DCPP Equipment Qualification Program has made major progress in addressing weaknesses identified in 2003. Corrective actions are essentially complete, and the program appears healthy. Equipment replacements are planned along with the Steam Generator (SG) replacements because of changed temperature profiles as a result of the new SG design.
4.10
It appears DCPP continues to make good progress in improvements to its Corrective Action Program (CAP). The biggest challenges include better line involvement and better quality of resolution of corrective actions. The DCISC should continue to follow DCPP’s progress in its CAP improvements.
4.11
The Quality Verification of the DCPP Software Quality Assurance (SQA) Program concluded that the program was satisfactory overall. There were two Areas for Improvement regarding two outdated plans and some minor issues. These items are being tracked on Action Requests. The audit appeared thorough, and the SQA Program appeared sound.
4.12
The DCPP Vendor Manual Program was determined in 2004 to have problems with manual control and disposition such that manuals were not always up-to-date and contained in the appropriate files. This is being corrected with a three-year review and update program. An improved control procedure has been developed to help assure proper manual control in the future.
4.13
It appeared that DCPP had successfully identified and isolated the source of a small leak of primary water from the Unit 2 Reactor Vessel In-Core Instrument Thimble Tube. Repairs will be made during Outage 2R14 in beginning February 2008.
5.0 Recommendations:
None

6.0 References

6.1
“Diablo Canyon Independent Safety Committee Fourteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2003 – June 30, 2004”, Approved October 12, 2004, Exhibit D.6, Section 3.5, “12kV System Corrosion & Other Problem Corrective Actions and DCPP Response to Recommendation R02-12.”
6.2
Ibid., Exhibit B.6, “Status Report on the 12kV System” System.
6.3
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Exhibit D.7, Section 3.4, “Tour 230 and 500 kV Switchyard and Discuss Operations of Transmission Lines, Including Loss of 230 kV Power During 1R13 Relay Testing.”
6.4
“Diablo Canyon Independent Safety Committee Fourteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Exhibit D.8, Section 3.3, “Reactivity Management.”
6.5
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Exhibit D.6, Section 3.2, “INPO Evaluation, DCPP Responses and Actions.”
6.6
“Diablo Canyon Independent Safety Committee Fourteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Exhibit D.10, Section 3.4, “Boric Acid Corrosion Control Program.”
6.7
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Exhibit B.3, DCPP Plans for Outage 2R13.
6.8
“Diablo Canyon Independent Safety Committee Fourteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Exhibit D.3, Section 3.3, “Safety Culture”.
6.9
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Exhibit D.6, Section 3.4, “Overview of DCPP Culture as a Learning Organization.”
6.10
Pacific Gas & Electric Company, Nuclear Power Generation, Program Directive OM16, “Nuclear Safety Culture”, July 21, 2006.
6.11
Pacific Gas & Electric Company, Nuclear Power Generation, Inter-Departmental Administrative Procedure OM16.ID1, “Safety Culture and Safety Conscious Work Environment (SCWE)”, July 21, 2006.
6.12
“Diablo Canyon Independent Safety Committee Thirteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2003 – June 30, 2004”, Approved October 16, 2003, Exhibit D.2, Section 3.10, “Actions to Prevent Recurrence of EQ Problems”.
6.13
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Exhibit D.3, Section 3.1, “Quality Verification (QV) Assessments of Corrective Action Program.”
6.14
Ibid., Exhibit B.3, “Corrective Action Program (CAP) Improvements”
6.15
“Diablo Canyon Independent Safety Committee Thirteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2003 – June 30, 2004”, Approved October 16, 2003, Exhibit D.3, Section 3.5, “Software Quality Assurance Program.”

For more information about DCISC contact:

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