21st Annual Report, Volume II, Exhibit D.6, Report on Fact-finding Meeting by Diablo Canyon Independent Safety Committee (DCISC) at Diablo Canyon Nuclear Power Plant (DCPP) on October 20–21, 2010 by Robert J. Budnitz, Member, and David C. Linnen, Consultant

1.0 Summary

The results of the October 20–21, 2010 Fact Finding trip to the Diablo Canyon Nuclear Power Plant in Avila Beach, CA are presented. The subjects addressed and summarized in Section 3 are as follows:

  1. Plant Health Committee
  2. Update on Potential Debris Blockage of Containment Sump
  3. Reactor Vessel Head Replacement Update
  4. Operations Revitalization Action Plan
  5. Status of Reducing Component Mispositionings
  6. Status of Performance Improvement Action Plan
  7. Meeting with Site Vice-President
  8. Potential for Pressurized Thermal Shock (PTS) and Implications for License Renewal

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 Plant Health Committee

The DCISC Fact Finding Team met with Karen Karner, Executive Assistant to the DCPP Station Director, to review the status of the functioning of the Plant Health Committee. The DCISC last reviewed this activity in December 2006 (Reference 6.1) when it concluded the following:

The Plant Health Committee (PHC) is part of the prescribed process to screen proposed changes to systems, structures and equipment to improve health. The process adds rigor and certainty to the way in which money is budgeted for plant improvement changes. The December 14, 2006 PHC meeting appeared to have been effectively run with good participation and questions by attendees.

Ms. Karner noted that the PHC is functioning more consistently and effectively than it had been several years ago. She cited two important factors for this improvement. The first is that the committee is now meeting with greater frequency. It now typically meets once per week whereas several years ago it had difficulty convening once per month. These more frequent regular meetings, however, are typically not held during outages. If an operational problem were to emerge in the operating unit while the other unit is in an outage, that operating problem would be treated through the Operational Decision Making process, in which an Emerging Issues Manager would be assigned to the problem. The problem would not be handled by the PHC.

The second reason cited by Ms. Karner for the Committee’s increased effectiveness is that it now focuses almost entirely on system health whereas several years ago it was frequently diverted from examining the health of plant systems by discussions regarding potential costs for system improvements and the station’s budget. In those prior years the PHC possessed budget authority to approve funding up to $50,000 for individual projects. However, since the station’s Project Review Committee has primary authority for project funding, this sometimes created situations where both committees were discussing the potential costs of the same projects. Moreover, having budget authority could serve to divert the PHC’s focus more to the financial aspect of a potential project and thereby to reduce the Committee’s focus on the physical impact of any system problem on the plant.

Ms. Karner also stated that the DCPP Operations Director serves as Chairman of the PHC, which provides a strong operational focus on system and program operations. Other station directors also serve on the Committee as voting members. Ms. Karner noted that the PHC reviews not only plant systems but also a number plant programs, such as:

The DCISC Fact Finding Team was provided with four sets of System Health Reports that are representative of the materials reviewed by the PHC. Each set consists of the review package (i.e. the System Health Reports) for a specific PHC meeting. The four meetings reviewed by DCISC were held in March, May, June, and July of 2010. The volume and structure of the review packages are very similar. Each package pertaining to a specific system provides an overall rating for the system (Green, White, Yellow, or Red where Green is satisfactory, and Yellow and Red signify that improvement is needed). Ms. Karner noted that although both the Red and Yellow ratings indicate that improvement is needed, the distinction between the two ratings is that a Red system becomes Yellow when an Action Plan for improvement is approved. She also noted that the PHC reviews each system that is rated Red or Yellow at least every six months.

An Executive Summary in each report provides a summary of the reason for the performance rating and a summary level discussion of other issues of concern. Another section of each report provides a focused rating (Green, White, Yellow, or Red) on each of a variety of performance indicators in the following categories:

Reliability– Critical Component Failures, Critical Equipment Clock Resets, Unplanned Entries into Limiting Conditions for Operation, Deficiencies Resulting in Unit Capacity Reduction, Reactor Trips

Maintenance Rule– Corrective Actions Under Development, Approved or Being Implemented, Monitored, Found Ineffective. Repeat Maintenance Rule Functional Failures. Risk Significant and Non-Risk Significant Functional Failures.

Material/Equipment Condition and Corrective Actions– Emergent Work Orders (WO), Prompt Operability Assessments (POA), POAs awaiting Corrective Action, Aging Issues Affecting Reliability

Operations Concerns– Operator Workarounds,/Burdens, Control Board Notifications, Operability Issues in the Past 180 Days

Performance Monitoring– Adverse Critical Equipment Trends, Adverse Equipment Trends

Any of the above individual performance factors that is rated Red in the report is then discussed in the body of that report to the PHC.

Another section of the report “Analysis” provides for written discussions on a number of other topics, as follows:

Each report also contains an Action Plan for each system that specifies planned actions, the action’s owners, due dates, tracking numbers (Notifications), the reason for each condition being addressed, and the status of actions.

Each monthly report package also contains a matrix for each unit listing each system that is rated Red or Yellow, the number of months during which the system has been rated Red or Yellow, and the expected time at which the system is expected to return to healthy status. Shown below are the most recent matrices (September 2010) for the Red/Yellow systems. All of the systems listed below were rated Yellow; none were Red.

Unit 1, red/yellow systems
Unit 1
System Months Unhealthy Expected Return to Healthy Status
Condensate 13 1R16
Reactor Coolant 15 1R17
Heating, Ventilation and Air Conditioning 17 1R16
12 kV 19 1R16
4 kV 6 1R17
230 kV 30 2R16
500 kV 9 1R16

Unit 2 red/yellow systems
Unit 2
System Months Unhealthy Expected Return to Healthy Status
Auxiliary Feedwater 7 3R16
Reactor Coolant 15 2R16
Heating, Ventilation and Air Conditioning 17 2R16
4 kV 6 2R17
230V 29 2R16

Ms. Karner also provided the Fact Finding team with System Health matrices from other months in 2010, the earliest of which were from February 2010. The Unit 1 matrix for February listed 10 unhealthy systems, compared to seven in September. Of the 10 in February, two were Red and eight were Yellow. The Unit 2 matrix for February listed eight unhealthy systems compared to five in September. Of the eight in February, two were Red and six were Yellow.

Conclusions:
The Plant Health Committee (PHC) appears to be employing an effective method for examining the status of plant operating systems, determining system health through its use of a logical set of performance indicators, and reviewing and tracking planned actions to completion. Increasing the frequency of Committee Meetings and deleting budgetary decisions from the Committee’s responsibilities appear to have allowed the PHC to examine DCPP systems more frequently and effectively. The number and significance of unhealthy plant systems were reduced during the period between February and September of 2010. DCISC should focus future reviews on the performance of individual systems and should conduct any future reviews of PHC activities as dictated by trends in overall station performance.

3.2 Update on Potential Debris Blockage of Containment Sump

The DCISC Fact Finding Team met with Dan Brosnan, Principal Electrical Engineer, to discuss the issue of debris blockage of the containment sump strainers during a potential loss of coolant accident. DCISC last reviewed this topic in January 2009 (Reference 6.2) when it concluded the following:

The Quality Verification Assessment of DCPP’s response to NRC’s Generic Letter 2004-02 (debris blockage of Containment sumps) was thorough and comprehensive. It found some errors early in project design and testing which were resolved. The overall conclusion was that DCPP response was “thorough, comprehensive, well documented, and technically correct.” A larger issue on engineering was identified in the GL 2004-02 assessment: weaknesses in engineering products. An Apparent Cause Evaluation has been initiated which the DCISC should follow.

The issue of potential debris blockage of the containment sump during a potential loss of coolant accident (LOCA) has been the subject of extensive research by the industry and the NRC. The issue pertains to the accumulation of debris in the containment sump which could potentially block the screens to the suction lines to pumps that draw water from the sump and recirculate the coolant back to the Reactor Coolant System (RCS) and ultimately to the Reactor Vessel to keep the fuel cooled during a LOCA. This debris could be generated in sufficient quantity by the jet impingement of coolant, escaping from the RCS at high temperature and pressure, on insulated and/or painted or coated piping, structures, and equipment in the Containment Building. The release of coolant in this type of situation is called a High Energy Line Break. The generated debris could thus consist of fragmented, shredded, fibrous, and chemically decomposed insulation and/or coatings. It could also accumulate as sludge. In 1985 the Nuclear Regulatory Commission (NRC) issued Generic Letter (GL) 85-22, “Potential for Loss of Post-LOCA Recirculation Capability Due to Insulation Debris Blockage.” Although the NRC’s regulatory analysis did not support imposing new sump performance requirements upon the licensees at that time, the NRC analysis found that the existing Regulatory Guide regarding sumps for Emergency Core Cooling Systems (ECCS) should be replaced with a more comprehensive requirement to assess debris effects on a plant-specific basis.

However, during the 1990s, several plants in the United States and overseas experienced the clogging of ECCS strainers. The plants were of the Boiling Water Reactor (BWR) design. During this period, the NRC issued several generic communications requesting that BWR licensees implement appropriate procedural measures, maintenance practices, and plant modifications to minimize the potential for the clogging of ECCS suction strainers by debris accumulation following a LOCA. However, findings from research to resolve the BWR strainer clogging issue also raised questions concerning the adequacy of Pressurized Water Reactor (PWR) sump designs.

During 2000 and 2001, prior to the NRC’s issuance of any directive to pressurized water reactors, DCPP proactively enlarged its approximately 30 sump screens to improve their design and increase debris removal capacity. At that time, PWRs like DCPP normally had on the order of 100 to 200 square feet of sump screens. DCPP’s proactive modifications increased the area of its screens to about 700 square feet for Unit 1 and 750 square feet for Unit 2.

In 2004, the NRC issued Generic Letter 2004-02: Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors. This Generic Letter established new requirements for PWR containment recirculation sump strainers. PWRs were requested to make a conservative evaluation of their current designs and to complete by the end of 2007 any necessary analyses and modifications, including upgrading the screens and increasing their size and testing. DCPP determined that its sump strainer capability should be improved using two possible strategies: 1) reducing the amount of material that could be damaged in an accident (and thus could contribute to clogging the strainer); and 2) providing a larger strainer. Debris material could be reduced by removing, encapsulating, or replacing fibrous insulation on piping and electrical cables, by installing interceptors to capture paint chips and reflective metal piping insulation and by opening flow paths to divert debris away from the strainer. These modifications, among other things, included enlarging the available surface area of the containment sump screens to 3,500-4,000 square feet and removing and replacing vulnerable debris and insulation material from containment. In its response to the NRC’s Generic Letter, DCPP determined that it would not be possible to complete the needed modifications in both Units by the end of 2007. Thus, DCPP applied for and received NRC approval to complete the necessary modifications beyond 2007. In July 2008 DCPP submitted a response to NRC Generic Letter 2004-02, stating that DCPP had met the requirements of the Letter.

Using this material as history, the DCISC Fact Finding Team met with Dan Brosnan, Principal Electrical Engineer, in order to receive an update of DCPP status on the issue of potential containment sump blockage. Mr. Brosnan noted that DCPP has completed major plant modifications in which the average containment sump screen size is 32 times larger than the original configuration. He indicated that there are two aspects of how loose material created by a LOCA can pose a risk to the reactor core: 1) materials may clog the sump screens and restrict containment sump recirculation cooling to the fuel in the reactor vessel and 2) some materials may pass through the screens, may be pumped into the reactor vessel, and may collect on portions of the nuclear fuel. This could lead to local heating, deterioration, and failure of fuel cladding and release of fission products to the containment building. Some insulation materials inside containment can cause the first problem, and some others in containment can cause the second problem. Both are undergoing analysis. These problems can be solved by analyzing the risks and identifying the potential effects in order to determine whether the risks are acceptable or by replacing the existing insulation or coatings with acceptable materials. The second approach has been determined to be the preferred approach.

Mr. Brosnan further noted that the above two issues of potential risk to the nuclear fuel are continuing to be analyzed within the industry in general and by DCPP in particular. For example, in December 2009, the jet testing that DCPP had performed through a contractor and had used as a basis of its earlier submittal to the NRC was found to have some uncertainty. This jet testing used a nozzle with a 3.0 inch diameter opening, and this configuration was used as basis for the accident analysis. However, a restriction that reduced the effective diameter to 2.6 inches in the supply to the nozzle has created uncertainties and an accompanying need to either reanalyze or retest. Mr. Brosnan also said that the NRC has issued a set of 14 questions in a Request for Additional Information (RAI) and that 12 of the questions pertain to jet testing. Revised testing methods are being developed and test results are expected to be available by mid-year 2011.

Mr. Brosnan noted that DCPP has developed Computer Assisted Design (CAD) models of the interior of the Containment Building (CB) that assist in identifying Zones of Influence (ZOI). These ZOIs are particular areas in which a LOCA could damage insulation and coatings. The CAD models further aid the analysis of the extent of damage that could be experienced and the potential impact the debris could have on the fuel in the Reactor Vessel (RV). This can lead to the identification of a worst case scenario from the accident analysis.

In addition, during the current Unit 1 refueling outage, 1R16, a tightly woven fiberglass insulation called Temp-Mat was discovered in a tight configuration in the space between the reactor vessel and the biological shield in the Reactor Building. This condition was analyzed by DCPP, and the potential risk to the nuclear fuel from a LOCA in this area was found to be bounded by the effects of LOCAs in other areas of the containment building (CB).

To more effectively evaluate the potential effects of debris on nuclear fuel following a LOCA, DCPP is participating in a Pressurized Water Reactor Owners Group (PWROG) Project on “Debris Testing and Zone of Influence Definition.” DCPP’s share of the cost of this project is about $400,000. This testing will continue through 2011. The test facility is expected to be accepted in December 2010. Insulation tests should be complete in April 2011. A topical report should be provided to the NRC by October 2011, and it is expected that the NRC would have a Safety Evaluation completed in December 2011. DCPP is also using a separate contractor to evaluate PWROG results and to evaluate debris originating from branch lines compared to RCS loops. Potential plant modifications resulting from these tests and analyses are expected to be installed in 2R17 and 1R18.

Mr. Brosnan noted that the NRC Commissioners met with the NRC Staff on Generic Letter 2004-02 in September 2010, just a few weeks before this Fact Finding visit. Potential letters explaining any new requirements are expected to be issued by the NRC to utilities in November 2010.

Finally, Mr. Brosnan noted that DCPP has both the technical capability and a specific emergency procedure that enables either of its units to clear a blocked sump by forcing a backflow of water in the opposite direction, so that debris would be pushed out of the flow path of any of the blocked screens. Mr. Brosnan claimed that DCPP is unique in having this capability, which is apparently not present at any other nuclear plant. He noted, however, that the NRC has refused to allow the DCPP units to take any credit for this unique capability in its safety analyses on this issue.

Conclusions:
Extensive enlargements and modifications have been made to the containment sump screens in order to substantially reduce the risk of blocking recirculation to the Reactor Vessel during a Loss of Coolant Accident. Detailed examinations have been made of the Containment Building to identify and evaluate potential sources of debris that could be created by Loss of Coolant Accidents originating in various areas of the Containment Building. However, this problem has not been completely resolved either by DCPP or by the industry. DCISC should continue to follow this topic, and the next review should take place after the results of the Pressurized Water Reactor Owners Group Topical Report is issued in 2011.

3.3 Reactor Vessel Head Replacement Update

The DCISC Fact Finding Team met with Wayne Ginter, Strategic Projects Principal Project Manager for the DCPP Reactor Vessel Head Replacement Project. At the time of this meeting DCPP was in Day 17 of a planned 25 day refueling outage, 1R16, during which the station was in the process of replacing the Unit 1 Reactor Vessel Head and installing a new Integrated Head Assembly. The DCISC last reviewed this topic at its December 9–10, 2009 Public Meeting (Reference 6.3) during which Mr. Ginter discussed the nature of the project and the station’s performance regarding similar work that had been performed on Unit 2 during outage 2R15 in October/November 2009.

In recent years a number of nuclear plants have elected to replace the reactor vessel heads due to their susceptibility to primary water stress corrosion cracking in welds connecting components to the head. Although some plants have chosen to replace only the heads, DCPP decided to include in this project the addition of an integrated head assembly (IHA) as part of the new replacement head. The differences between DCPP’s original head configuration and the new configuration with an IHA are as follows:

Together with the new forging of the head itself, the above enhancements are expected to lead to greater plant and personnel safety, more efficient performance of maintenance and refueling, lower radiation dose, reduced frequency of required inspections of CRDM penetration tube-welds and tube base metal (from every outage to every 10 calendar years), and decreased likelihood of reactor coolant leakage. At the same time, the combination of the new Reactor Vessel Head and its Integrated Head Assembly creates a heavier load than the prior Reactor Vessel Head. Therefore, the increased static and dynamic loads that will be imposed on both the Polar Crane and the Reactor Vessel required analysis, which was done and which found that the cranes are acceptable.

Mr. Ginter provided the DCISC an update on how the Unit 1 head replacement was progressing and how the station had been able to apply lessons learned from the Unit 2 head replacement. Many of the lessons directly affected outage length because the head replacement project is the “Critical Path” activity throughout virtually the entire time that head replacement activities are occurring. This means that if something delays the head replacement project, it also delays the entire outage. One important example is that the Containment Building polar crane is being used by the head replacement project 80 percent of the time during which this project is active in containment.

Mr. Ginter said that better coordination of human resources has been achieved compared to 2R15 while at the same time increasing the number of project workers. Three major contract groups are involved in this effort: PG&E with about 25 personnel, Barnhart with about 40, and AREVA, a French firm, with about 50. AREVA has supported other American utilities in their reactor vessel head replacements. During the current outage, the project is using a “hot turnover,” (i.e. a two hour overlap between shifts) to achieve better coordination of activities during shift transition. Improved teaming has also been achieved between the various project work groups. A teaming event for this purpose was held prior to the outage, which allowed project groups and individual team members to better understand each other’s roles. Other improvements have been achieved simply from having encountered unanticipated situations during the work on Unit 2, which have now been planned for–such as difficulties in removing some components from attachments to the old head and some interferences that were previously encountered. The cumulative effect thus far has been a savings 3 days in outage time compared to 2R15 last year. To help reduce radiation doses, DCPP also hired an ALARA (As Low As Reasonably Achievable) engineer after outage 2R15.

Mr. Ginter said that the NRC has been primarily interested in fabrication and welds, and that they have been performing surveillances on site. Their focus during this project has been on Non Destructive Examinations (NDE), welding, configuration of the head, the conduct of heavy rigging, and the licensing basis for the replacement head and integrated head assembly.

Mr. Ginter said that currently the Integrated Head Assembly is installed with all fit-ups completed. Key remaining work to be performed involves connections of electrical equipment and piping.

Conclusions:
The Unit 1 Reactor Vessel Head Replacement Project appears to be progressing smoothly during outage 1R16. Lessons learned from the Unit 2 head replacement during 2R15 have been applied and have resulted in better teamwork, improved efficiencies, and reduction in project duration thus far, while maintaining project quality.

3.4 Operations Revitalization Action Plan

The DCISC Fact Finding Team met with Jan Nimick, Manager, Nuclear Operations. Although the DCISC has not previously reviewed the subject action plan, this action plan stemmed from Operator Concerns, which were last reviewed by the DCISC in August 2009 (Reference 6.4) when it concluded the following:

It appears that DCPP Operations management and represented operators have resolved their major concerns, grievances, and contract disputes. This has been achieved through a series of face-to-face meetings. There has been no apparent negative effect on the DCPP safety culture caused by operators’ concerns and issues.

Nevertheless, operator concerns continued to linger and to affect the relationship between the operators and management. This resulted in the development of an Action Plan to address the lingering issues. The DCISC conducted this review to identify progress being made and to examine the extent to which this situation may be affecting plant operations.

Relevant portions of the Overview to this DCPP Operations Revitalization Plan are quoted below from the October 4, 2010 version of the Plan:

“Overview: In 2009 it was recognized that the Operation department relations between employees and management had declined. Communication, collaboration, and teamwork had suffered. An action plan was developed to focus on three broad areas that, when addressed with integrity and trust, would significantly contribute to improved employee relations and department performance. These three areas are:

  1. Clarify the contract: Low mutual agreement between labor and management on the interpretation of the IBEW contract
  2. Reconnect and rebuild teamwork: Inadequate lines of communication resulting in low perceived trust between management and operations employees
  3. Eliminate distractions: Lingering complaints and organizational distractions contribute to current conditions of ambiguity, distrust, and poor communication”

Early in 2010, a fourth action area was added to provide a “world class working environment.” The Plan Overview also notes that: “Overall, communications, collaboration, and teamwork have improved.” and that “shift leadership has been engaging with employees to add new actions to any of the previously identified problem statements or identify new issues, develop an associated problem statement, and partner to develop meaningful action(s) to continually improve the working environment.”

One of the major influences on the relationship between operators and management was the most recent revision to the union contract. The prior contract required that longevity, rather than competence or qualifications determined who would be selected to attend senior reactor operator (SRO) license classes, and the contract specified how many operators would attend an SRO class. Management maintained that operator qualifications, not seniority should be the determining factor in selecting SRO candidates, and that class size should be flexible, rather than predetermined. The revised contract, effective January 1, 2009, incorporated management’s requests, and the contract was accepted by a vote of the operators; but some operators remained opposed to its provisions.

Mr. Nimick noted that the relationship between operators and management was driven to some extent by the above change to the union contract. However, other factors involve the need for shift managers to engage operators more routinely regarding issues of significance to them, and for information to be provided more effectively to operators on topics of interest to them. He has met with the Communications Department regarding communications tools to use in regard to interacting with workers. Supervisors have received training in communicating and maintaining relations with working level personnel.

Mr. Nimick also stated that it is not unusual for workers to receive incorrect pay, and he has been in contact with Payroll to get this situation remedied. This has been an important source of worker frustration, and it affects their relationship with management.

A review of the Operations Revitalization Plan revealed that 53 of 70 action items are complete. Six of the remaining 17 involve improving furniture, storage, and the kitchen. Those actions and the 11 others do not appear to be items that would significantly affect operator attitudes toward management.

The DCISC Fact Finding Team examined operations-related performance factors to determine any weak areas that could then be examined for ties to operator attitudes:

The above indicators reveal no areas of concern regarding the performance of station operators.

Conclusions:
With its Operations Revitalization Plan DCPP management has taken a considerable number of actions to address operator concerns and revitalize the relationship with station operators. Performance indicators that are influenced by the actions of station operators reveal no potential areas of concern. A slight declining trend in the Operations Protective Tagging Index from April through August 2010 may, however, be worth examining. The station and PG&E need to promptly resolve the continuing and significant problem of operators not being correctly paid.

3.5 Status of Reducing Component Mispositionings

The DCISC Fact Finding Team met with Jan Nimick, Manager, Nuclear Operations, on Day 17 of Unit 1 Refueling Outage 1R16 to discuss the station’s performance with respect to component mispositionings and actions being taken to improve performance. The DCISC last reviewed this topic in April 2010 (Reference 6.5), when it concluded the following:

Although mispositioning performance slipped during Refueling Outage 2R15, the performance trend has been positive since 2006. Planned Actions for achieving continued improvement appear appropriate. However, since this is a long-standing issue and since the next refueling outage will be another major undertaking, DCISC should perform another review in 2011, after the conclusion of Refueling Outage 1R16. Also, DCPP needs to resolve the differences between the definitions of mispositioning significance levels in the monthly performance indicator sheet and Procedure OP1.ID6, Definition and Measurement of Mispositioned Plant Components.

A “Mispositioned Plant Component” is defined by Procedure OP1.ID6, Definition and Measurement of Mispositioned Plant Components, as follows:“Any positionable component placed or left out of the required position for existing plant conditions when the component’s required position is tracked by one or more of the following status control tools: procedures, clearances, work management process (e.g. orders), other similar authorizing documents that align or re-align components, any positionable component placed or left out of the required position or existing plant conditions due to inadequate or incorrect status control tools described above. This includes situations where a lack of process exists that should have controlled the configuration of the component.”

A tabulation of the number of mispositionings for the past five years is shown below. It should be noted that over the past few years, the station has become more conservative with regard to what constitutes a non-consequential mispositioning. This category now includes those that have minimal or no impact on the station and that were immediately identified and corrected (Level 4). It also includes those where a component mispositioning was imminent or possible, but averted through the use of error prevention tools (Level 5). The above two classifications have been added since 2007.

Non-consequential Mispositioning
  2006 2007 2008 2009 2010 (thru IR16)
Consequential 8 2 3 0 0
Non-consequential
(includes Levels 3,4,&5 for 2008 and beyond)
32 21 48 35 19

Note: Using the less conservative definition from 2007 and earlier, the number of non-consequential mispositionings in 2009 would be 19 and the number in 2010, through the end of refueling outage 1R16, would be 9.

Mr. Nimick noted that an intensified focus has been placed on mispositioning reductions during the past 12 months, especially due to the relatively high number of mispositionings that occurred during refueling outage 2R15 in the last quarter of 2009. During the first nine months of 2009, 18 mispositionings occurred (all were non-consequential and nine were Level 3). However, 13 more non-consequential mispositionings (8 were Level 3) occurred during the 35 day refueling outage 2R15, and after that outage four more occurred prior to end of 2009.

To address these performance issues a Common Cause Evaluation was performed after 2R15 by a combined Operations and Maintenance team. It was determined that the Maintenance mispositionings were largely due to very basic and simple mistakes that could be corrected by self-verification. Maintenance corrective actions involved performing Just-In-Time/Tailboard Training just prior to the outage. The causes of mispositionings by Operations personnel were more complex and often related to weaknesses in the application of operator fundamentals when using procedures. Corrective actions to address the Operations issues involved the following:

Prior to outage 1R16, presentations were made and discussions conducted with Operations and Maintenance personnel. The following topics were covered:

In addition, an “observation blitz” was conducted just prior to refueling outage 1R16. Every manager in Operations performed field observations on Maintenance and Operations work activities, focusing on pre-job briefings, on adherence to the 2-minute rule (a period at the work site prior to commencement of work during which the workers are expected to view the work area and review the activities to be conducted while looking for possible situations where mispositionings could occur), and on worker adherence to the STAR rule (Stop, Think, Act, Review). Seventy observations were conducted in one week. Mr. Nimick felt that the combination of the remedial activities discussed above has had a positive impact on worker performance. At the time of DCISC’s discussion with Mr. Nimick, DCPP was in Day 17 of the planned 25 day outage, and only one mispositioning (a Level 3) had occurred during the outage. Mr. Nimick noted that special care will need to be devoted by workers as the station staff prepares to shift to readying the unit for return to power operation. He also noted that top plants in the industry incur only about 3 to 5 total mispositionings per unit per year. (Subsequent to this Fact Finding visit, DCISC was informed that DCPP incurred 5 more mispositionings during refueling outage 1R16 for a total of 6, compared to 13 mispositionings incurred during refueling outage 2R15. Three of the six were Level 3, one was Level 4, and two were Level 5. None of these mispositionings occurred during the last few days of the outage.)

Finally, the DCISC Fact Finding Team noted that differences still exist between the definitions of mispositioning significance levels in the monthly performance indicator sheet and in Procedure OP1.ID6, Definition and Measurement of Mispositioned Plant Components.

Conclusions:
DCPP has devoted substantial attention and effort to reducing component mispositionings. Significant improvement was achieved during refueling outage 1R16. Inconsistencies between the definitions of mispositioning significance levels in the monthly performance indicator sheet and in Procedure OP1.ID6, Definition and Measurement of Mispositioned Plant Components, still need to be resolved.

3.6 Status of Performance Improvement Action Plan

The DCISC Fact Finding Team (FFT) met with Joe Ferguson, Manager of Problem Prevention and Resolution. This is DCISC’s first review of DCPP’s Performance Improvement Action Plan. Prior to arriving on-site, the team reviewed the Action Plan. The Plan’s problem statement reflected the nature of the remaining contents of the Plan in that the Plan was focused on the nature of and methods used by the station’s performance improvement activities rather than focusing on specific improvements that are needed in aspects of plant operation and performance. The Plan’s Problem Statement reads as follows:

“DCPP’s use of performance Improvement (PI) programs lags the industry with the result that performance shortfalls continue to occur and performance relative to the industry is declining.”

The Plan focuses on improving methods, techniques and tools for identifying, measuring, and assessing gaps between actual DCPP performance and desired performance. Specific methods, techniques and tools discussed in the Plan include: benchmarking, self-assessing, performance indicators, gap analysis, Corrective Action Program (CAP) procedures, Apparent Cause Evaluations (ACE), Root Cause Analyses (RCA), reviews of plant and industry operating experience, and reviews by external groups. It does not discuss specific actions that were felt to be needed to actually improve specific areas of plant performance but rather addresses the performance improvement process in general.

The objectives of the above Plan are as follows:

  1. Integrate industry best practices for performance improvement processes into station core business.
  2. Improve the use of industry best practices and operating experience in performance improvements and corrective action activities.
  3. Strengthen the performance improvement oversight committees to reinforce the integrated use of performance improvement process to improve station performance.
  4. Enhance appreciation of the value the performance improvement processes bring to employees and the station.
  5. Improve employee proficiency in performance improvement activities.

The Fact Finding Team also reviewed station procedure OM15.ID5, DCPP Performance Improvement Program. This procedure basically explains various organizational tools and methods for assessing and tracking performance such as department quarterly performance improvement rollups, Performance Improvement Challenge Committee meetings, the Performance Improvement Review Board comprised of senior management, Plant Health Committee meetings, departmental Performance Improvement Integrated Matrices, and departmental Performance Improvement Coordinators.

Mr. Ferguson stated that the Performance Improvement Action Plan stemmed from the 2009 plant evaluation conducted jointly by the Institute of Nuclear Power Operations (INPO) and the World Association of Nuclear Operators (WANO). He stated that another performance improvement tool is a Health Report for self-assessments–a single sheet template that a department would fill out quarterly and would be submitted to the Self Assessment Review Board.

Mr. Ferguson stated that three to four years ago his department was staffed with 22 people; two years ago it had 15, and currently there are five. During the past few months another two positions have been authorized. When the department was larger, its personnel were trained in and performed RCAs and ACEs for the station. Now those reviews are performed by personnel in the affected departments, with the potential problem that these individuals have other primary responsibilities and therefore do not necessarily have the same skills as would individuals who perform these analyses as a significant portion of their job. Currently personnel in Problem Prevention and Resolution serve as coaches to the other departments whose personnel perform the evaluations.

Mr. Ferguson estimated that the station ideally should have about 20 personnel who are trained in and are capable of performing causal analyses. Currently there are six such individuals, two of whom are in Problem Prevention and Resolution. Further, departments have Performance Improvement Coordinators, whose focus is supposed to be on self-assessments, benchmarking, RCAs, and ACEs. However, they are devoted largely to managing the corrective action backlogs and performing other departmental duties.

The Fact Finding Team examined the most recently provided (August 2010) Plant Performance Indicator Report (PPIR) from the standpoint of highlighting potential problem areas to management’s attention. At the very beginning of the PPIR, the report highlights those Performance Indicators that have improved during the past month and those that have declined. What is not shown are those indicators that have remained in Red and/or Yellow Status from month to month. The Fact Finding Team identified the following performance indicators in that status during August:

Conclusions:
The DCISC does not typically review organizational and process related areas unless considered warranted to examine aspects that could be tied to specific plant performance issues related to safety. Organizational structure and management methods are considered to be the purview of the utility. This, however, was DCISC’s first review of the Performance Improvement Action Plan, and it became apparent that the Plan is almost exclusively organizational and process-oriented in nature. Therefore, DCISC will refrain from further reviews of this Plan unless certain aspects can be clearly tied to station performance issues related to safety.
However, the DCISC recognizes through earlier Fact Finding Meetings and reports that DCPP has had difficulties with evaluating and addressing station problems, including the area of engineering evaluations. Additionally, the NRC has issued DCPP a significant cross-cutting aspect for deficiencies in its Corrective Action Program, a major program included in DCPP’s Problem Prevention and Resolution area. The DCPP Performance Improvement Action Plan is an appropriate vehicle for helping to correct and improve DCPP’s performance. DCISC concludes from this review that some causal factors related to this problem may be due to an inadequate number of trained and qualified personnel as well as to a lack of clarity in personnel responsibilities. DCISC also concludes from its review of the Plant Performance Indicator Report that performance indicators that have remained Red or Yellow from month to month are not being highlighted to the same degree as those that have improved or declined in the most current month.

3.7 Meeting with Site Vice-President

Dr. Budnitz met with Jim Becker, DCPP Site Vice-President, to discuss items from the fact-finding meeting and other items of interest.

3.8 Potential for Pressurized Thermal Shock (PTS) and Implications for License Renewal

The DCISC Fact Finding Team met with William Bojduj of the Reactor Engineering Group on the issue of the threat posed by a potential Pressurized Thermal Shock (PTS) at DCPP. DCISC last reviewed this topic in September 2010 (Reference 6.7) when it concluded:

DCPP has preliminary results from a Westinghouse (DCPP reactor vessel vendor) that there are no adverse effects on vessel pressurized thermal shock from the combined Shoreline/Hosgri Fault earthquake during a 20-year extended operating life. The DCISC expects the final result to be available for presentation by PG&E at its November 16, 2010 Public Meeting.

PTS is a concern when a Reactor Vessel is pressurized during power operation and experiences an injection of relatively cool water contacting its hot steel walls, or experiences rapid repressurization after a depressurization event. The cool water shock or repressurization could cause small cracks to enlarge and the vessel to rupture. This phenomenon is a concern only for vessels embrittled by years of high-energy neutron flux. An earlier meeting with Mr. Bojduj had occurred during the March 2010 Fact Finding meeting, and this was a brief follow-up.

The meeting began with the FF Team explaining again the specific request to the DCISC from the California Energy Commission, related to pressurized thermal shock (PTS) over the postulated 60-year extended period of operation, the newly discovered Shoreline Fault feature, and the nexus between PTS and this seismic hazard. The DCISC’s also discussed its plan to do a broader evaluation of safety issues related to the license renewal application and life extension. Specifically, the purpose of the meeting was for the DCISC team to discuss with Mr. Bojduj their work to date on the technical issues related to PTS, and to assure that the information being relied upon was complete and up-to-date. The DCISC team also explained the interim conclusions that were emerging from the DCISC’s studies, and to ascertain whether any of the information being relied on was incomplete or incorrect.

Based on the discussions with Mr. Bojduj, the DCISC team believes that it has not overlooked any technical information that might be needed to support its own review, nor has it somehow misunderstood any of the principal conclusions that the DCPP group has arrived at in support of its license-extension application to the NRC. Apparently, there are no misunderstandings, nor is there any information that the DCISC team is not already aware of.

Mr. Bojduj clarified one additional important point that had been unclear. Every operating reactor uses a set of small metallic specimens (so-called coupons) placed inside the vessel, that can be removed periodically for examination, to study how radiation damage affects the metal in the vessel itself. These metallic coupons are made from the exact same material as the vessel itself. The DCISC was concerned that perhaps the plant does not have enough coupons to provide high assurance about vessel radiation damage for use over an extended operating life. However, Mr. Bojduj explained that the DCPP plant possesses enough metallic coupons, either in the reactor itself or now in the spent-fuel pool, to support the plant’s need to understand potential radiation damage to the reactor vessel out for the full 60-year proposed lifetime of the plant if NRC grants a license extension.

Specifically, Mr. Bojduj stated that the irradiation experience from the coupons they already have in-hand at DCPP goes out in some cases to the equivalent fluence of 55 or so EFPY (effective full power years), close to what they need for a 60-year operating lifetime. The coupons with the highest neutron fluence exposures get to 55 EFPY by having been placed in a higher neutron flux field inside the reactor core than the fluence that the vessel walls have experienced. If these coupons have valid exposures, the DCPP plant already has close to enough irradiation experience with the coupons in-hand to support their need out to 60 years with 20 more years of irradiation available, as necessary, if the license extension is granted.

Conclusions:
DCPP has a sufficient number of reactor vessel surveillance coupons to support the station’s monitoring of the effects of neutron radiation on the reactor vessels of Units 1 and 2 throughout the full 60-year proposed lifetime of the plant. The DCISC Fact Finding Team’s conversation with Mr. Bojduj verified DCISC’s understanding of DCPP’s principal conclusions in support of the utility’s life-extension application to the NRC for both units. From the conversation, DCISC also believes that it has not overlooked any existing technical information needed to support its own review of the effects of pressurized thermal shock coupled with seismic effects upon the reactor vessels during the full 60-year proposed lifetime of the plant. Further, DCISC recognizes that analyses of seismic effects of the Shoreline Fault are not fully complete at this time, though PG&E’s initial conclusion indicates that its effects are within the current seismic capability of the plant.

4.0 Conclusions

4.1
The Plant Health Committee (PHC) appears to be employing an effective method for examining the status of plant operating systems, determining system health through its use of a logical set of performance indicators, and reviewing and tracking planned actions to completion. Increasing the frequency of Committee Meetings and deleting budgetary decisions from the Committee’s responsibilities appear to have allowed the PHC to examine DCPP systems more frequently and effectively. The number and significance of unhealthy plant systems were reduced during the period between February and September of 2010. DCISC should focus future reviews on the performance of individual systems and should conduct any future reviews of PHC activities as dictated by trends in overall station performance.
4.2
Extensive enlargements and modifications have been made to the containment sump screens in order to substantially reduce the risk of blocking recirculation to the Reactor Vessel during a Loss of Coolant Accident. Detailed examinations have been made of the Containment Building to identify and evaluate potential sources of debris that could be created by Loss of Coolant Accidents originating in various areas of the Containment Building. However, this problem has not been completely resolved either by DCPP or by the industry. DCISC should continue to follow this topic, and the next review should take place after the results of the Pressurized Water Reactor Owners Group Topical Report is issued in 2011.
4.3
The Unit 1 Reactor Vessel Head Replacement Project appears to be progressing smoothly during outage 1R16. Lessons learned from the Unit 2 head replacement during 2R15 have been applied and have resulted in better teamwork, improved efficiencies, and reduction in project duration thus far, while maintaining project quality.
4.4
With its Operations Revitalization Plan, DCPP management has taken a considerable number of actions to address operator concerns and revitalize the relationship with station operators. Performance indicators that are influenced by the actions of station operators reveal no potential areas of concern. A slight declining trend in the Operations Protective Tagging Index from April through August 2010 may, however, be worth examining. The station and PG&E need to promptly resolve the continuing and significant problem of operators not being correctly paid.
4.5
DCPP has devoted substantial attention and effort to reducing component mispositionings. Significant improvement was achieved during refueling outage 1R16. Inconsistencies between the definitions of mispositioning significance levels in the monthly performance indicator sheet and in Procedure OP1.ID6, Definition and Measurement of Mispositioned Plant Components, still need to be resolved.
4.6
The DCISC does not typically review organizational and process related areas unless considered warranted to examine aspects that could be tied to specific plant performance issues related to safety. Organizational structure and management methods are considered to be the purview of the utility. This, however, was DCISC’s first review of the Performance Improvement Action Plan, and it became apparent that the Plan is almost exclusively organizational and process-oriented in nature. Therefore, DCISC will refrain from further reviews of this Plan unless certain aspects can be clearly tied to station performance issues related to safety.
However, the DCISC recognizes through earlier Fact Finding Meetings and reports that DCPP has had difficulties with evaluating and addressing station problems, including the area of engineering evaluations. Additionally, the NRC has issued DCPP a significant cross-cutting aspect for deficiencies in its Corrective Action Program, a major program included in DCPP’s Problem Prevention and Resolution area. The DCPP Performance Improvement Action Plan is an appropriate vehicle for helping to correct and improve DCPP’s performance. DCISC concludes from this review that some causal factors related to this problem may be due to an inadequate number of trained and qualified personnel as well as to a lack of clarity in personnel responsibilities. DCISC also concludes from its review of the Plant Performance Indicator Report that performance indicators that have remained Red or Yellow from month to month are not being highlighted to the same degree as those that have improved or declined in the most current month.
4.7
DCPP appears to have a sufficient number of reactor vessel surveillance coupons to support the station’s monitoring of the effects of neutron radiation on the reactor vessels of Units 1 and 2 throughout the full 60-year proposed lifetime of the plant. The DCISC Fact Finding Team’s conversation with Mr. Bojduj verified DCISC’s understanding of DCPP’s principal conclusions in support of the utility’s life- extension application to the NRC for both units. From the conversation, DCISC also believes that it has not overlooked any existing technical information needed to support its own review of the effects of pressurized thermal shock coupled with seismic effects upon the reactor vessels during the full 60-year proposed lifetime of the plant. Further, DCISC recognizes that analyses of seismic effects of the Shoreline Fault are not fully complete at this time, though PG&E’s initial conclusion indicates that its effects are within the current seismic capability of the plant.
 

5.0 Recommendations:

None

6.0 References

  1. 6.1 “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 November 20, 2007, Volume II, Exhibit D.5, Section 3.4, “Plant Health Committee Meeting.”
  2. 6.2 “Diablo Canyon Independent Safety Committee Nineteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2008–June 30, 2009”, Approved December 9, 2009, Volume II, Exhibit D.7, Section 3.4, “QV Assessment of DCPP Response to NRC Generic Letter 2004-02, ‘Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at PWRs”
  3. 6.3 “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 November17, 2010, Volume II, Exhibit B.3, Section XVIII, “Replacement of Unit–2 Reactor Head during 2R15”
  4. 6.4 “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 3.6, “Operators’ Concerns and Issues.”
  5. 6.5 “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.8, Section 3.27, “Component Mispositionings”
  6. 6.6 “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.4, Section 3.8, “Pressurized Thermal Shock and Shoreline Fault Analysis”

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.