Report on Fact-finding Meeting by Diablo Canyon Independent Safety Committee (DCISC) at Diablo Canyon Power Plant (DCPP) on May 20 - 22, 2008 by Robert J. Budnitz, Member and R. Ferman Wardell, Consultant [18th Annual Report, Exhibit D.10]

1.0 Summary

The results of the May 20-22, 2008 Fact-finding Trip to PG&E’s San Francisco Geosciences offices and to the Diablo Canyon Power Plant in Avila Beach, CA are presented. The subjects addressed and summarized in Section 3 include:

  1. Update on the December 22, 2003 San Simeon Earthquake
  2. DCPP Tsunami Potential
  3. Lessons Learned from the Japanese KKNPS Earthquake of July 2007
  4. Update to the Long-Term Seismic Program
  5. Boric Acid Corrosion Control Program
  6. Corrective Action Program
  7. System Review: Heating, Ventilation and Air Conditioning (HVAC) Systems
  8. Steam Generator Replacement Project
  9. Unit 2 Fuel Failure
  10. Containment Fan Cooler Unit Reverse Rotation
  11. Radiation Dose Projections During Plant Emergencies
  12. Outage 2R14 Containment Leak Rate Test
  13. Mid-Cycle INPO-Type Assessment and Status of INPO Initiatives
  14. Meteorological Tower Damage
  15. 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

Meeting at PG&E’s offices in San Francisco – Geosciences topics

On May 20 in the afternoon, R. Budnitz (DCISC Member) and F. Wardell (Consultant) met at PG&E’s offices in San Francisco with four members of PG&E’s geosciences group: Lloyd Cluff (Director of PG&E Geosciences Department), Norman Abrahamson (Senior Engineering Seismologist), Stuart Nishenko (Senior Seismologist), and Marcia McLaren (Senior Seismologist.) The two-hour meeting covered the following four technical topics in the geosciences:

3.1 Update on the December 22, 2003 San Simeon Earthquake

The DCISC has reviewed this earthquake and potential effects on DCPP in several Fact-finding and public meetings. Shortly after this earthquake, the DCISC received a briefing at a Fact-finding Meeting (April 2004) followed by another at a Public Meeting (June 2004) and most recently in December 2004 (Reference 6.1) at which time it concluded the following:

PG&E has completed its analyses of the December 22, 2003 San Simeon Earthquake and showed that the earthquake response is properly predicted by models and that the earthquake response exceedence at the top of containment satisfied applicable acceptance criteria. The earthquake response at DCPP was well within the plant design basis. The new Seismic Monitoring System has been installed and is fully operational. It replaces an outdated system and provides substantially improved data retrieval and analysis.

This May 2008 follow-up meeting, held after extensive field work and analysis has been done, was intended to assure that nothing important to DCPP safety was overlooked during the earlier DCISC reviews and to provide a status update.

Marcia McLaren led this part of the meeting. The 2003 San Simeon earthquake was a magnitude 6.7 earthquake about 50 km NNW of the Diablo Canyon site. The effects at the DCPP site itself were modest (accelerations were below 0.05g, less than one-tenth of the earthquake motion for which the plant’s nuclear safety functions are designed.) However, the PG&E staff, along with experts from the United States Geological Survey (USGS), performed an extensive evaluation of the earthquake, of the fault on which it was located, and of the seismic regime in which the source structure is embedded. The objective was to understand what lessons might be learned about the potential for future earthquakes from this source zone to affect DCPP. Sophisticated InSAR (Interferometric Synthetic Aperture Radar) data and analysis were used to supplement the usual seismographic records, and enabled the team to understand post-seismic deformation and other phenomena in ways that were not accessible earlier.

The dynamics of the earthquake are now well understood, as is the basis for a large number of minor aftershocks whose locations and sizes allow a better understanding of the event’s features and of the features of the fault.

Conclusion:
Based on an update on the December 2003 San Simeon Earthquake, there is nothing new that would cast doubt on the DCPP plant’s design basis or on its ability to withstand another earthquake similarly situated.

3.2 DCPP Tsunami Potential

Lloyd Cluff introduced this part of the meeting, followed by Stuart Nishenko (study of tsunami sources) and Norman Abrahamson (planned probabilistic analysis). The DCISC last reviewed tsunamis in April 2005 (Reference 6.2) when it concluded:

PG&E’s analysis of significant earthquake-caused tsunamis, including the December 2004 Sumatra event super-imposed on Alaska, indicates that none represents a threat that would exceed the maximum tsunami design basis events at DCPP. The DCISC should request this tsunami presentation be made at its June 1-2, 2005 Public Meeting.

Historically, the design basis for the DCPP plant to resist tsunami threats has been based largely on the threat from a possible large tsunami arising from a huge seismic event across the ocean, say from the seismic “ring of fire” around the Pacific Rim, such as from Alaska, Japan, or Chile. Another potential source could be a subduction-zone earthquake arising offshore of Oregon or Washington in the so-called Cascadia Subduction Zone (CSZ), about 1000 km north of DCPP. Recently, the possibility of a tsunami arising from a large offshore landslide relatively near to the site (a few to a few tens of km) has been receiving attention.

Cluff noted that a PG&E analysis demonstrates that a tsunami from the CSZ would be no larger than those arising from past large seismic events in Chile (1960) and Alaska (1964), neither of which would even come close to posing a threat to the DCPP plant.

Concerning nearby offshore landslides, Nishenko discussed what PG&E has been doing to understand the potential for such. An extensive survey has been conducted of the seabed offshore of DCPP, extending out to the sloping margin leading to the continental shelf. The work has concentrated on studying certain specific areas, several km in two-dimensional plan-view extent, where the seabed material’s composition might be susceptible to a large earthquake-induced landslide. Several such areas have been identified and their physical features are being characterized. Nishenko discussed interactions with the NRC staff, which has recently begun a broad study of tsunami potential from offshore landslides along the Atlantic coast. The NRC staff has been briefed about the PG&E work and is following it.

The next step in this project is to complete the work to characterize the several specific offshore areas, and then to develop a phenomenological model of how a landslide might develop as a function of the specific composition and features (thickness, slope, etc.) of each target area and of the earthquake sources that might trigger such a landslide.

After that, the final aspect of the tsunami study, which was discussed by Norman Abrahamson, will be to perform a Probabilistic Tsunami Hazard Analysis (PTHA), using the well-known and often-used “SSHAC methodology” [NUREG-CR-6372, 1997] (Reference 6.3) originally developed for PSHA (S = Seismic instead of T = Tsunami.) The PG&E application of the SSHAC methodology for PTHA would involve the use of a few outside experts to supplement the basic PG&E analysis. Abrahamson stated that the SSHAC methodology has been endorsed by the NRC for general external-hazard-analysis use and is ideally suited for such an analysis. (The Fact-finding Team agrees.) Such a PTHA, which would be a first-of-a-kind analysis, requires developing a probabilistic description of the suite of initiating events (earthquakes of varying sizes), a probabilistic treatment of the response of the seabed leading to landslides of different sizes, and finally a probabilistic analysis of the effect of such landslides in terms of surface waves and surface surges at the DCPP site.

Abrahamson discussed how such a PTHA would be structured, how its inputs would be developed in probabilistic terms, how they would be combined together, how the use of experts would supplement the basic PG&E analysis, and how the results would be reported. He emphasized that using a PTHA approach would enable the PG&E team to capture the full uncertainty in what is known about tsunami hazard at the DCPP site, including both epistemic uncertainty due to imperfect data and modeling, and aleatory variability due to natural variations in the underlying phenomena.

Conclusion:
The proposed PG&E risk-based Probabilistic Tsunami Hazard Analysis (PTHA) to determine the landslide-caused tsunami risk to DCPP would provide a very advanced understanding of tsunami risks at DCPP arising from near-shore landslide hazard. This work is to be strongly encouraged.

3.3 Lessons Learned from the Japanese KKNPS Earthquake of July 2007

Lloyd Cluff and Norman Abrahamson led this part of the meeting. A large offshore earthquake in July 2007 struck almost directly beneath a coastal site in Japan where there are seven large BWR (boiling water reactor) units, known as the “Kashiwazaki-Kariwa Nuclear Power Station” (KKNPS). The earthquake’s size significantly exceeded the nuclear plants’ Design Bases in some plant locations by factors of two or more. In fact, this was the first earthquake that has ever struck a nuclear power station, worldwide, with ground motions whose size significantly exceeded the design basis. Hence it is the object of intense worldwide scrutiny.

Extensive investigations by Japanese experts, by an International Atomic Energy Agency (IAEA) team, and by several teams of foreign experts have found that no damage ensued to any of the essential safety systems of any of the seven BWRs. However, there was extensive damage to many non-safety-related systems, structures, and civil works such as roads and embankments. This damage led to the immediate shutdown of all seven of the nuclear units, a shutdown that has continued for 10 months and is likely to continue for many months more, at a cost well in excess of 2 billion dollars due to the 8,000-plus megawatts of power that is not being generated.

Cluff presented an update to a preliminary report that he and Abrahamson gave at the DCISC’s Public Meeting in October 2007 (Reference 6.4). PG&E has visited the KKNPS site, studied what has been learned, and is in the process of assimilating the insights. Cluff’s principal thrust during this Fact-finding meeting was to provide a status report on their work, which is still in an interim stage and will not be finalized for several more months. From the briefing, it seems clear that even though DCPP has the strongest seismic design of any nuclear power plant worldwide, and (like the Japanese plants) would likely suffer no safety-related damage if an earthquake of similar size were to strike DCPP, the specific technical insights from KKNPS are not likely to be very applicable to Diablo Canyon. This is because the frequency content of the energy in the KKNPS earthquake is very different from any earthquake that is likely to occur in coastal California, so the Japanese plants’ responses are not technically relevant.

However, some insights are definitely applicable, related to the damage to non-safety-systems. Like all nuclear plants worldwide including the seven at KKNPS, Diablo Canyon has numerous items of equipment, structures, and civil works that are not needed to assure nuclear safety and are hence not designed with the ultra-strong seismic basis of the safety-related items. Some of these would likely be damaged, to a greater or lesser extent, by an earthquake whose ground motion would exceed DCPP’s design basis by as much as the Japanese earthquake ground motion exceeded KKNPS’s design basis.

This topic is under scrutiny now at PG&E, and the outcome will certainly be of interest to the DCISC after the PG&E evaluation has been completed.

Conclusion:
PG&E’s Geosciences Group continues to study the July 2007 Japanese earthquake which struck near the Kashiwazaki-Kariwa Nuclear Power Station in which no safety-related components were adversely affected. When the study is completed, they will assess any recommendations for the non-safety-related portions of DCPP.

3.4 Update to the Long Term Seismic Program (LTSP)

The DCISC last reviewed the LTSP in December 2004 (Reference 6.1) when it concluded:

PG&E has completed its analyses of the December 22, 2003 San Simeon Earthquake and showed that the earthquake response is properly predicted by models and that the earthquake response exceedence at the top of containment satisfied applicable acceptance criteria. The earthquake response at DCPP was well within the plant design basis.

The new Seismic Monitoring System has been installed and is fully operational. It replaces an outdated system and provides substantially improved data retrieval and analysis.

Lloyd Cluff led this part of the meeting. The LTSP was an extensive program of seismic investigations and analyses performed by PG&E during the late 1980s and early 1990s (in the early years of DCPP’s operation), as a license condition incorporated into DCPP’s initial NRC license. It involved dozens of nationally known experts, an extensive array of both geosciences studies and engineering studies, the gathering of vast amounts of both earth-sciences and engineering data, the performance of what at the time was the most advanced site-specific probabilistic seismic hazard analysis ever done, and extensive peer review. At the time it was widely and justifiably hailed by the worldwide seismic-hazard and seismic-engineering communities as a groundbreaking effort.

Cluff explained that in the intervening years, much new information has been learned, some of it specific to DCPP and its site and equipment, but a lot of it more generic in nature. Studies around the world and specifically some major research work in California have allowed seismologists and engineers to understand earthquake phenomena and the response to large earthquakes in a way that was beyond the state-of-the-art 20 years ago. For example, a recent large project to understand western seismic ground-motions, in which PG&E has been a cooperating participant along with several major universities and the State of California, has considerably advanced the understanding of ground-motion propagation and attenuation. Also, several major projects have been successful in understanding better the nature of coastal-California faulting mechanisms. Advances have also been made in three-dimensional modeling of the response of structures to large earthquakes, and these methods have recently been applied to several complex non-nuclear structures.

These advances have motivated PG&E to undertake a so-called “update” of the LTSP. This update is being done on PG&E’s own initiative; it is not an NRC requirement, although the NRC staff will be following the progress eagerly. PG&E’s motivation is to demonstrate, using modern understanding, that DCPP remains more than adequately designed and operated to withstand the design basis earthquake ground motions that are an NRC license condition.

The briefing by Cluff laid out the plans and the scope of this update, which is just beginning. This is a 5-year effort with a budget of about $13 million. The US Geological Survey will be a partner in the study, under a recently signed cooperative research agreement. The DCISC looks forward to progress reports in the future as this work in undertaken.

Conclusion:
PG&E’s Geosciences Department is beginning an update of its existing Long-Term Seismic Program with a five-year effort, including the US Geological Survey as a partner. The DCISC should follow the progress of this work.

3.5 Boric Acid Corrosion Control Program

The DCISC Fact-finding Team met with Jim Hill of the Inservice Inspection (ISI) Group, Boric Acid Corrosion Control (BACC) Program Owner, and Chad Sorensen, ISI Engineer and BACC Data Manager, for an update of BACC. The DCISC last reviewed BACC in September 2006 (Reference 6.5), concluding:

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

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, AD4.ID2, “Plant Leakage Evaluation” 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 Program procedure ER1.ID2, “Boric Acid Corrosion Control Program,” 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 walkdowns.

The BACC Program health is currently reported as “White” based on individual measures and the following:

The BACC Program measures are as follows:

The last item was determined to be Yellow because “the large backlog of cleaning and repairs does not reflect best industry performance, but is stabilizing. Expert panel review scheduled items 1R15/2R15.”

The The Institute of Nuclear Power Operators (INPO) cited two BACC Areas for Improvement (AFIs) in its last evaluation. One was not using the Corrective Action Program (CAP) effectively on BACC issues in the Auxiliary Building, and the second was insufficient personnel sensitivity to BA leaks. Based primarily on the INPO AFIs and on a benchmarking trip to Beaver Valley, DCPP had made the following enhancements to its program:

Three formal Auxiliary Building walkdowns are performed each year by the ISI Group. Containment walkdowns are performed by ISI each Refueling Outage and in each unscheduled outage greater than 90 days after the previous in-Containment inspection. Additionally, plant personnel are charged to identify and report and document by Action Request (AR) BA leakage, no matter how small, when observed.

Improved results are being seen. Leak identification and reporting has increased. The backlog of identified leaks has been reduced. Many old BACC problems have been solved. An In-Containment INPO Team during Outage 2R14 reported good results. An NRC inspection reported “no findings of significance.” The DCISC reviewed a chart depicting the numbers of leak locations since January 2007, when the program changes were made. The numbers initially increased but then began decreasing as leaks were resolved. The current numbers of identified leaks at a given time have dropped from approximately 200 to 160. DCPP expects to reach its goal of 50 leaks [top industry quartile] in October for Unit 2 and at the end of Outage 1R15 for Unit 1 with its aggressive program. The enhanced valve packing program will go a long way in accomplishing the goal and eliminate many chronic valves leaks.

Conclusion:
DCPP has enhanced its already satisfactory Boric Acid Corrosion Control Program by better identifying and correcting boric acid leaks, increasing sensitivity of plant personnel, and developing an improved valve packing program. The plan’s goal is top industry quartile performance by Outage 1R15 (early 2009). The DCISC should review the Program in two years.

3.6 Corrective Action Program

The Fact-finding Team met with Chris Over, Corrective Action Program (CAP) Owner in the Performance Improvement Group, and Gerry Doyle from Constellation Energy who was an outside CAP expert reviewing DCPP’s program. The DCISC last reviewed the DCPP CAP (the Corrective Action Review Board – CARB) in June 2007 (Reference 6.6) when it concluded:

An agenda had been distributed and all participants had reviewed the actions to be taken at the Corrective Action Review Board (CARB) meeting. The members were well prepared to discuss each of these agenda items. CARB members discussed each of these items in detail and reached an agreement as to what actions needed to be taken. The CARB appeared to be performing their function well.

The CAP is a procedure-controlled program which plant personnel use to identify, document, correct and trend plant problems. It is an NRC-required program which NRC terms Problem Identification and Resolution (P&IR). CAP is computer-based. The basic document of CAP is the Action Request (AR) which is an electronic document used to initially identify and track problems. The program uses increasing levels to categorize and resolve more significant problems, i.e., A-Type (quality-related) ARs, Quality Problems, and Nonconformance Reports. More significant problems are analyzed with Apparent Cause Evaluations (ACEs) and Root Cause Evaluations (RCEs).

DCPP is performing an analysis of the CAP using the following 2007 RCEs:

The analysis is scheduled for completion in September 2008. To-date, three themes have surfaced: (1) employees are not always following standards or meeting management expectations, (2) early warning indicators did not always prevent problems, and (3) oversight bodies should do more but not dilute line ownership.

NRC similarly reported that DCPP had a high tolerance for problems and was not reporting them at the right level and noted a lag in identifying problems. Mr. Over believed that the solution was getting employees to report lower level problems.

The root cause identified in the Nonconformance Report (NCR) analysis is that “senior leadership has not performed effective oversight of CAP.” To resolve this cause, DCPP will (1) direct the Corrective Action Review Board (CARB) to monitor CAP health metrics and (2) revise the CAP procedure to reflect senior leadership’s definition of timely reporting and resolution. Other recommendations are that leadership (1) drive CAP with an intrusive approach and (2) increase its presence in the plant. Funding for corrective actions will be improved by (1) procedure modification and (2) Plant Health Improvement Project (PHIP) documents to flag corrective action funding.

The DCISC should follow up on this analysis.

The last NCR above, NCR 2221, “CAP Implementation Does Not Meet Management Expectations,” investigated areas in which the CAP was not effectively implemented. This was based on the following:

OM7.ID1 was revised to require problem reporting prior to leaving site. The other corrective actions were deferred for implementation until the results of a Strategic Teaming and Resource Support (STARS) CAP assessment were known. The corrective actions have not yet been implemented. (A0693360)

NCR 2221 Root Cause:
Senior leadership has not performed effective oversight of the corrective action program with respect to consistent problem reporting threshold and corrective action timeliness.
NCR 2221 Contributory Cause(s):
CC1: The CAP process does not adequately define what constitutes a problem or what timeliness is with respect to problem resolution.
CC2: CAP training is ineffective in that personnel do not understand the purpose and benefit of CAP.
CC3: Key performance indicators used to assess overall CAP health allowed deficiencies to exist in problem reporting threshold and timeliness of corrective actions without being detected.

NCR 2221 had the following recommendations (two Corrective Actions to Prevent Recurrence [CAPR] and six Corrective Actions [CORR]:

  1. CAPR 1: Senior leadership to use CARB to monitor revised CAP metrics to assess health of timeliness of problem identification and resolution through use of the standard CARB agenda provided in OM4.ID15. (RC [Root Cause] and CC3 [Contributing Cause])
  2. CAPR 2: Revise OM7.ID1 to reflect senior leadership’s definition of timely problem reporting and resolution. (RC)
  3. CORR 1: Executive management communicates CAP expectations for timely problem reporting and resolution through department level meetings to initiate a CAP culture change. (CC1)
  4. CORR 2: Add an OM7 series procedure which provides working level direction for the CAP program. Include Appendices to provide examples of problem definitions for various departments. (CC1)
  5. CORR 3: Incorporate station expectations on problem reporting into a station standards handbook. (CC1)
  6. CORR 4: Implement CAP training based on line performance analysis (LPA). The LPA should consider the need for both initial and recurring training. (CC2)
  7. CORR 5: Develop CAP expectations and guidance for supervisors based on a line performance analysis. (CC2)
  8. CORR 6: Include standard agenda in revision of OM15.ID4 to assure the Self-Assessment Review Board (SARB) fulfills its responsibilities. (RC)

Action plans were created to implement these initiatives.

DCPP’s root cause evaluation of problems in the CAP has identified several areas needing improvement. DCPP is beginning to implement these changes. The DCISC should follow up when the report is completed in September 2008.

Conclusion:
DCPP’s Root Cause Analysis on the lack of effectiveness of its Corrective Action Program (CAP) is expected to be completed in September 2008. It has identified the preliminary root cause as “senior leadership has not performed effective oversight of CAP” in setting and communicating standards and expectations for employees for the identification of lower level problems and for the timeliness of actions. Steps are being made to correct this. This is an important plant program, and the DCISC should review the analysis and corresponding corrective actions in the fall of 2008.

3.7 System Review: Heating, Ventilating and Air Conditioning (HVAC) Systems

The DCISC Fact-finding Team met with Randy Allen, HVAC System Engineer, and Greg Porter, Backup HVAC System engineer, to review DCPP HVAC systems. The DCISC has not reviewed HVAC systems recently.

DCPP power block HVAC is comprised of the following systems for each unit:

The DCISC Fact-finding Team reviewed the health of each of the above systems using a new System Report which replaces the former System Health Card. The new report includes the same information as before and adds a system health numerical scoring system which is associated with a color typical of other DCPP measures. Systems are rated on the following attributes:

Overall HVAC system health was Green for 10 systems and White for four systems – both satisfactory ratings. There were no systems rated Yellow or Red (both unsatisfactory). The Fact-finding Team reviewed each system’s needed repairs/improvements/replacements which mostly appeared to be normal maintenance or wear items. One modification (for each unit) is to add anti-rotation devices [pawls] to the fan shafts to reduce maintenance requirements on dampers necessary to control reverse rotation (see Section 3.10 below)

The Fact-finding Team reviewed a completed System engineer walkdown checklist. The walkdown appeared to have been completed with no significant abnormal or problem items.

Conclusion:
The DCPP Heating, Ventilation and Air Conditioning (HVAC) systems were in satisfactory health, and the system engineers appeared knowledgeable.

3.8 Steam Generator Replacement Project

The DCISC Fact-finding Team met with Bob Exner, Steam Generator Replacement Project (SGRP) Manager, for a review of the large project under which four Unit 2 SGs were replaced during Outage 2R14. The DCISC last reviewed SGRP activities during the December 19-20, 2007 Fact-finding Meeting (Reference 6.7) which report concluded:

The four new Unit 2 Steam Generators (SGs) had been received at the plant and stored in proper storage facilities under limited access. The workers were preparing the new SGs for movement into the plant in Outage 2R14 and checking measurements to be sure the SGs will fit properly for welding to the piping in the plant.

The DCISC learned in the April 16-17, 2008 Fact-finding Meeting (Reference 6.7) that the Unit 2 SGRP went smoothly and was nearly on-schedule. The Fact-finding Team viewed videos taken during the outage as well as a pre-outage computer animation of the old SGs being removed from and the new SGs being moved into Containment. The videos showed the SGs being offloaded from a barge in the Intake Cove, moved up to the plant on a special multi-wheeled transport vehicle, stored, moved into the Containment, and welded in place. Although huge in scope and complexity, the project went smoothly.

Three types of tests were performed during re-start from the outage: (1) Functional, (2) Other and (3) Warranty Tests. There were elevated silica levels [as expected] during startup. The levels decreased to normal levels with continued SG blowdown. The following Functional Tests were performed:

  1. SG Water Level Transient – a test to demonstrate the ability of the SG Water Level Control System to respond appropriately to a mismatch between SG level and level setpoint. The test criteria were satisfied.
  2. Pressurizer Spray Continuous Spray Valves Adjustment – a test to determine the optimum positions for the Pressurizer continuous spray valves. This test was postponed and then eliminated due to complications with the spray system. This was justified because Pressurizer pressure had been stable at normal operating pressure with the proportional heaters on and the backup heaters off. The DCISC should look further into this.
  3. Adjustment of Full Load Reference Temperature – a test to determine T-Ref based upon optimal turbine governor valve position. The criteria were satisfied.
  4. SG Blowdown Piping Vibration – a test to verify that SG blowdown piping does not have abnormal or excessive vibration as a result of SG small bore piping modifications. No excessive vibration was experienced.
  5. Feedwater Pump Turbine Speed at Full Power – a test to verify the proper scaling for Feedwater Pump Turbine Speed/Delta-P (pressure change). The proper scaling was verified.

Other SG Replacement Tests:

These tests were satisfactorily performed.

The following Warranty Testing has been/will been done:

  1. Reactor Coolant System (RCS) Flow Rate – a test to verify that RCS flow is within the correct range. The acceptance criteria were met
  2. Primary-to-Secondary Leakage – a test to verify the integrity of the SG tubes and tubesheet. The criterion was met.
  3. SG Blowdown Flow Measurement – a test to verify that SG blowdown meets specification. The criterion was met.
  4. Water Level Fluctuations – a test to verify that SG water level fluctuations meet specification. The criteria were met.
  5. Moisture Carryover Test – a test to verify that high quality steam is produced at the outlet of the SG. This test is to be performed following 90 days of operation.
  6. Steam Pressure Test – a test to verify SG thermal and hydraulic performance. This test will be performed following eight months of operation to allow for completion of the wear-in period so steam pressure has stabilized.

One parameter that did not meet specifications was Reactor Average Temperature (Tavg). The Tavg of 567ºF was 2ºF below the Reference Temperature of 569ºF, whereas it was expected to have been the same or a little higher. The root cause of this difference was determined to be the thermal/hydraulic design of the RCS. This is not a safety issue but an operating one as the core design was based on a 569ºF Tavg. DCPP was determining its next steps to rectify this situation at the time of the Fact-finding meeting. The DCISC should follow up on this issue.

The benefits of the new vs. old SGs are improved water level range, 10% tube plugging design margin [none before], higher pressure, and lower moisture carryover [0.1% vs. 0.4%] to the turbines. A major benefit is a reduction in tube inspections. The first tube inspection will be 100% at the first refueling outage, and 100% inspections at every third Refueling Outage thereafter.

The Unit 1 SGs will be replaced in Outage 1R15 in early 2009. Lessons learned from 2R14 SG replacements will be used to improve the process. Over 1100 improvement items have been identified. These are being processed for use in 1R15. Some of the more significant items are:

Conclusion:
DCPP’s Outage 2R14 replacement of Unit 2 Steam Generators, a large, complex process, went well, meeting almost all pre-established goals. Post-installation tests confirmed that the new generators were performing as expected, except for measured Reactor Coolant System (RCS) Average Temperature of 567ºF vs. 569ºF expected. DCPP is resolving this non-safety issue which DCISC should follow.

3.9 Unit 2 Fuel Failure

The DCISC Fact-finding Team met with Mark Mayer, Reactor Engineering Supervisor, to discuss the Unit 2 fuel failure found in Outage 2R14. The last DCPP fuel failure was in 2002 when Unit 2 operated with a single failed fuel rod in Cycle 11 from June 12, 2001 until the end of Cycle 11 on February 3, 2003. During 2R11, in-mast sipping and ultrasonic inspection identified a single failed rod, which was subsequently replaced with a stainless steel rod. The failure appears to have been manufacturing-related severe hydriding. The DCISC reviewed that failure in May 2003 (Reference 6.8) when it concluded:

PG&E has investigated the fuel failure to determine its cause and taken appropriate actions to repair and reuse the fuel assembly.

Based on December 18, 2006 radiochemistry data, Chemistry and Reactor Engineering determined that DCPP Unit 2 had developed a single fuel rod leak. The leak became apparent following two reactor trips, the first on December 10, 2006 while subcritical, and the second on December 12, 2006 from approximately 24% full power. The presence of Xenon-133 gas indicated the leak. It was confirmed by an increase in Iodine-131 from 1x10-4 to 4x10-4 microCuries/cc. Per DCPP Procedure TS6.ID1, “failed Fuel Prevention and Mitigation (FFPM) Program,” the FFPM Committee convened and began monitoring the leak. The leak did not adversely affect plant operations or safety during operation.

During Outage 2R14 core offload, in-mast fuel sipping and visual inspection revealed that once-burned Assembly NN66 had a single leaking rod due to a large hydriding defect between Grid 6 and the uppermost intermediate fuel mixing grid. A hydride blister was also identified above the defect between Grids 7 and 8. The leaking rod was a corner rod in the assembly which was located near the center of the core, the same location as the previous leak found in Outage 2R11. The fuel assembly was determined unfit for reuse and was placed into the Spent Fuel Pool. There was also more wear than expected inside the instrument guide tube of Assembly NN58, and that assembly was removed.

The fuel manufacturer, Westinghouse, was asked to investigate and report on the root cause of the failure. The investigation team includes a DCPP Reactor Engineer. This investigation is expected to be completed in mid-June 2008. DCPP noted that there was more debris than usual found in the bottom of the Reactor Vessel possibly from pump testing. No debris or abnormal wear was found in Assembly NN66. In the future DCPP will augment its fuel assembly bottom nozzle inspections for debris, purchase a new camera to provide more thorough inspections for debris under the core plate in the Reactor Vessel, and perform more extensive vacuuming of the vessel bottom.

The Unit 2 Cycle 15 core was subsequently redesigned to remove Assembly NN66 and seven additional once-burned assemblies and add eight twice-burned assemblies from Cycle 14 which had been intended for discharge. The redesign resulted in an energy reduction of about 4.5 Effective Full Power Days (EFPDs) which can be offset by an end-of-cycle coastdown, a peaking factor margin reduction of 1.7%, initial Axial Flux Distribution more negative by 0.6%, but no changes in design limits and no operational constraints other than the early coastdown.

Conclusion:
DCPP appears to have taken appropriate measures to investigate and compensate for a damaged fuel rod found in Refueling Outage 2R14. The plant has stepped up its Reactor Vessel debris removal techniques for future cycles. The DCISC should follow up on the fuel failure root cause when it is completed in mid-June 2008.

3.10 Containment Fan Cooler Unit Reverse Rotation

The DCISC Fact-finding Team met with Steve Zawalick, Regulatory Services Engineer, to review the Containment Fan Cooler Unit (CFCU) reverse rotation issue. The DCISC has reviewed this issue on numerous occasions, most recently in April 2008 (Reference 6.9) when it concluded:

DCPP resolved the reverse rotation concerns with the Containment Fan Cooler Units (CFCUs) in Outages 1R13 (November 2005) and 2R13 (May 2006). They are currently evaluating modifications to ease the outage maintenance requirements for adjusting the CFCU back flow dampers. The modifications are currently scheduled for 2010 but are under evaluation for earlier installation.

The purpose of this May 21, 2008 review was to follow up on DCPP actions regarding an allegation received by NRC and a May 15, 2008 e-mail received by the DCISC from a member of the public on this issue regarding a delay in installing anti-reverse rotation device modification. This modification is designed to reduce maintenance requirements on CFCU dampers and was delayed until 2010 because of budget constraints. The HVAC System Engineer had written an Action Request to revisit the decision to delay as follows:

. . . no reverse rotations have been identified since 2005. However, a back draft damper was recently [4/1/08] found stuck open . . . with this re-occurrence it would be prudent to evaluate if implementation of the project should be done sooner than 2010. . . . This presentation will be planned and presented to the PRC by 31May2008.

The 4/1/08 open backdraft damper was closed by starting up one of the CFCUs. The observed reverse rotation was evaluated by DCPP engineering and found to be acceptable with respect to the existing operability evaluation.

DCPP Regulatory Services was preparing the history and current status of various issues the NRC has recently questioned, including CFCU reverse rotation. Although the CFCU reverse rotation safety concern has been resolved, the DCISC should continue to follow the issue up to and following the modification to add the anti-rotation devices to the CFCU fan shafts. In the long-term this would be a better reverse rotation solution.

The CFCU reverse rotation problem is an example of a larger issue that the DCISC has been following for some time, namely the issue of how DCPP copes more generally with long-standing equipment problems. Regarding long-standing issues, in its 2005-2006 Annual Report (Reference 6.10) the DCISC reported that [excerpts]:

In previous period the DCISC concluded that in the two previous reporting periods [2003-2004 and 2004-2005], there had been lapses in DCPP’s promptly identifying and correcting significant system and equipment problems. This had resulted in reduced System Health in certain areas, and some long-standing equipment issues remain open. Aggressive changes have been made, including augmenting the Corrective Action Program and developing a Trouble-shooting Program. Although beginning to yield some positive results, progress has been slow in raising the health of some important systems to expected levels.

In its 2006-2007 Annual Report (Reference 6.11) the DCISC reported the following [excerpts]:

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 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 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.

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.

The DCISC believes that DCPP, in working to correct earlier deficiencies in resolving long-standing equipment issues, has made major and positive changes, among the most important of which is institutionalizing a method for addressing them by having established the Plant Health Committee.

Conclusion:
DCPP had satisfactorily resolved the Containment Fan Cooler Unit reverse rotation issue in Outages 1R13 (November 2005) and 2R13 (May 2006) with backdraft damper modifications and enhanced maintenance. The plant is currently evaluating its schedule to install anti-rotation devices on the fan shafts which would be a better long-term resolution. The DCISC should continue to follow this issue up to and following implementation and testing of these devices.

3.11 Radiation Dose Projections During Plant Emergencies

The DCISC Fact-finding Team met with Dr. Mark Somerville, Radiation Protection Manager, to discuss the process by which DCPP would make radiation dose projections during and following a plant emergency. The DCISC last reviewed this topic in April 2005 (Reference 6.12) when it concluded:

PG&E makes its radiological protective action recommendations to the County based on documented computer-modeled projections using information from the plant radiation monitors and radioactive material release rate data. The DCISC should inquire further into the workings, documentation and experimental validation of these models, and on the appropriate role, if any, for FMT [Field Monitoring Team] data in affecting protective action recommendations.

DCPP employs three methods of determining offsite radiation dose projections:

  1. The primary tool used for projections, EARS (Emergency Assessment and Response System) is the computer system that obtains and processes plant meteorological and radiological data to determine release rates for use in dose assessment calculations. EARS employs MIDAS (Meteorological Information and Dose Assessment System), a proprietary dose assessment program, to perform atmospheric dispersion and dose assessment calculations. EARS is used by the Emergency Supervising Engineer or Health Physicist. Procedure EP RB-16, “Operating Instructions for the EARS Computer System,” Revision 1, 12/26/07, describes the use of EARS.
  2. A Microsoft Excel-based application, QUICKDOSE, is used for faster, general dose projection calculations.
  3. There are two procedures, EP RB-11, “Emergency Offsite Dose Calculations,” Revision 12, 12/20/01 and EP RB-9, “Calculation of Release Rate,” Revision 12, 04/05/08, which are used for manual calculations to back up EARS and QUICKDOSE.

This Fact-finding review focused on EARS/MIDAS. EARS & MIDAS contain the following attributes/options:

There is another level of options for each of the above (e.g., type/duration of filtration, water levels, containment spray status, radiation monitor availability, etc.). EARS/MIDAS appeared comprehensive and competent. Dr. Somerville reported that dose projections calculated with the above tools are accurate and that the two programs are the proven industry standards for radiation dose projections.

The DCISC plans to observe the next DCPP emergency exercise on October 29, 2008 and should pay particular attention to radiation dose projections and radiation field monitoring teams and information.

Conclusion:
The radiation dose projection programs used by DCPP, EARS (Emergency Assessment and Response System) and MIDAS (Meteorological Information and Dose Assessment System) appear to be comprehensive, accurate, and reliable. DCPP had had good experience using these proven industry standard programs.

3.12 Outage 2R14 Containment Integrated Leak Rate Test

The DCISC Fact-finding Team met with Meagan Wilson, Associate Engineer and Containment Integrated Leak Rate Test (ILRT) Day Shift Test Lead, to review the ILRT completed in Outage 2R14. This is the DCISC’s first review of this test.

The DCPP Containment, like all nuclear power containments, is designed to provide near-leak-tight containment of any radiological materials in the building which might otherwise escape during normal, off-normal or accident conditions. NRC regulation 10CFR50, Appendix J contains requirements for containment leak rate testing generally on a ten-year basis; however, certain exceptions are permitted. The last test of DCPP Unit 2 was 15 years ago due to a five-year extension by NRC. NRC is considering going to a standard 15-year period based on the good performance of the industry in maintaining containment leak tightness. The test was performed in accordance with industry standard ANSI/ANS (American National Standards Institute/American Nuclear Society) 56.8-1994, “Containment system leakage Testing Requirements (Absolute Method, Mass Point Analysis, Leakage Stabilization Criteria, Termination Criteria).”

The DCPP Containment contains a net free volume of 2.55 million cubic feet and has a design pressure of 47 psig. The Containment has a Technical Specification maximum design basis leak rate of 0.1 weight %/day used for accident calculations.

The ILRT was performed by ILRT, Inc., a specialist in ILRT testing, and required 42 hours (vs. a projected 36 hours) and included the following steps:

ILRT Steps
Step Time Required (hours)
Pressurization 7.5
Stabilization/Troubleshooting 16.08
ILRT itself 10.00
Verification Test 4.00
Depressurization delay 0.75
Depressurization 3.00
Unrestricted access restored 0.66

Pressurization was begun at 1810 hours on April 2, 2008 at an average pressurization rate of 8 psi/hour using 17 compressors with a rated capacity of 27,500 cfm. The test was performed at almost 46 psig (end of test) with the following results:

The DCISC Fact-finding Team received a copy of the test report “Periodic Reactor Containment Building Integrated Leakage Rate Test Final Report,” dated April 3&4, 2008. The report was thorough and informative. The test team generated many lessons-learned to improve the Unit 1 ILRT in early 2009.

Conclusion:
The DCPP Outage 2R14 Unit 2 Containment integrated Leak Rate Test (ILRT) was performed successfully. All test acceptance criteria were met. The measured leak rate was approximately one-sixth of the acceptance criterion.

3.13 Mid-Cycle INPO-Type Assessment and Status of INPO Initiatives

The DCISC Fact-finding Team met with Jacquie Hinds, Business Planning Manager, to review plans for the upcoming mid-cycle assessment and the status of DCPP INPO Areas for Improvement (AFIs) from the previous 2007 INPO evaluation. The DCISC last reviewed DCPP INPO Items in August 2007 (Reference 6.13). At that meeting the DCISC concluded:

DCPP regained its “Excellent” rating in its February 2007 The Institute of Nuclear Power Operators (INPO) evaluation. The evaluation identified strengths and Areas for Improvement (AFIs). The DCISC Fact-finding Team reviewed DCPP’s responses to the AFIs and found them to be satisfactory. The DCISC should follow up on implementation of DCPP’s corrective actions in late 2007 or early 2008.

INPO performs a graded plant evaluation of DCPP [and each US nuclear power plant] usually every two years. DCPP performs a comprehensive INPO-style self-assessment during the off year, the purpose of which is to determine progress in resolving any INPO Evaluation Areas for Improvement (AFIs), to assess performance against current industry standards and to identify gaps and craft plans to close the gaps.

DCPP’s Team, led by Jacquie Hinds, consists of 12 DCPP personnel, ten industry peers from other nuclear plants, and an INPO Advisor. Jim Becker, Site Vice-President and Station Director, is the Management Sponsor. A pre-assessment analysis was performed the week of April 28, resulting in a Problem Development Sheet (PDS) for each potential issue. These PDSs will be included in the self-assessment scope. The Team began with on-site analysis May 5, 2008 and will perform its actual on-site assessment June 16 – 26, 2008. The report will be sent out internally for comment June 26 and will be finalized July 9, 2008.

The Team will assess performance in the following traditional INPO functional areas:

Nuclear Safety Culture, Industrial Safety, and Organizational Effectiveness will be assessed by the team as a whole with overall responsibility being with the OR Lead. A streaming analysis will be performed to assist in identifying potential Organizational Effectiveness issues.

The Team will place emphasis on the following Areas for Improvement (AFIs) from the previous INPO evaluation performed in 2007 [except as noted]:

Areas for Improvement from previous INPO Evaluation
AFI No. Functional Area Status
OP 1-1 Plant Status Control Not Resolved
OP 1-2 Tech Spec and ECG Tracking errors Not Resolved
RP 1-2 RP Practices and Policies Resolved
MA 1-3 Maintenance Work Practices Not Resolved
ER 1-1 Long-standing Degraded Equipment Not Resolved
ER 2-2 Single Point Vulnerabilities On Track for resolution
ER 2-3 Boric Acid Control Not Resolved
ER 3-1 Ineffective Chemical Treatment Not Resolved
ER 3-2 Aggregate Secondary Plant Equip Deficiencies Not Resolved
CM 3-1 Vendor Supplied Design Errors Not Resolved
CM 4-1 Reactor Engineering Errors Resolved [Not included because QV Assessment evaluated resolution of AFI. A later Training self-assessment will Address the item.]
TR 1-2 Initial Licensed Operator Training On track for resolution. [Not included – awaiting results of current license class.]
PI 1-2 CAP Program and Self-Assessments Not Resolved
OR 2-2 Management Persistent Problems Not Resolved
OR 6-1 Worker Safety Behaviors Resolved

The following Significant Operating Experience Reports (SOERs) will be assessed as well as selected INPO Review and Assistance Visit recommendations:

Significant Operating Experience Reports (SOERs)
SOER No. Description Last Effectiveness Evaluation
88-1 Instrument Air System Failures 2/2008
90-2 Nuclear Fuel Defects 12/2006
94-1 Nonconservative Decisions and Equipment Performance Problems Result in a Reactor Scram, Safety Injections, and Water Solid Conditions 12/2006
96-1 Control Room Supervision, Operational Decision-Making, and Teamwork 1/2007
96-2 Design and Operating Considerations for Reactor Cores 8/2007
98-2 Circuit Breaker Reliability 10/2007
01-1 Unplanned Radiation Exposures 12/2006
02-4 Reactor Pressure Vessel Head Degradation at Davis-Besse 7/2006
06-1 Rigging Lifting and Material Handling Outage 2R14
07-01 Reactivity Management New SOER
07-02 Intake Cooling Water Blockage New SOER
Conclusion:
DCPP’s plans for performing its mid-cycle INPO (Institute of Nuclear Power Operations)-type self-assessment appear satisfactory. The DCISC notes that 12 of the 15 Areas for Improvement (AFIs) from the 2007 INPO evaluation are unresolved, but it is expected that the self-assessment report will highlight these areas and bring increased attention to them for resolution well before the 2009 INPO evaluation. The DCISC should continue monitoring the status of these AFIs and review the results of the mid-cycle assessment.

3.14 Meteorological Tower Damage

While the DCISC Fact-finding Team was onsite at DCPP, the meteorological tower between the Training Building and the Intake Structure sustained damage. A mobile crane hit and damaged one of the multiple guy wires that support the tower. The tower was visibly bent as a result and was determined to be at risk of failure. Personnel and vehicles were subsequently moved away from the tower. An Incident Command Team was established to respond.

A large crane will be used to stabilize the tower to allow removal of the damaged structure. Once wind speeds decrease, a second crane will be used to lift personnel to secure the primary crane to the tower. DCPP Staff and Transmission personnel are developing a plan for removal and replacement of the tower later in 2008. Compensatory arrangements are being made for former tower communications and meteorological functions. DCPP’s actions to respond to the meteorological tower damage appeared appropriate.

Conclusion:
The DCPP meteorological tower sustained damage from a mobile crane and was as risk of failure. It appeared to the DCISC that DCPP personnel took prompt and appropriate action to protect plant equipment, personnel and vehicles until the tower could be removed and replaced.

3.15 DCISC Member Meeting with DCPP Management

DCISC Member Robert Budnitz met separately with Ken Peters, Senior Director of Engineering Services, to discuss items reviewed in this Fact-finding meeting and other items of interest to the Committee.

4.0 Conclusions

4.1
Based on an update on the December 2003 San Simeon Earthquake, there is nothing new that would cast doubt on the DCPP plant’s design basis or on its ability to withstand another earthquake similarly situated.
4.2
The proposed PG&E risk-based Probabilistic Tsunami Hazard Analysis (PTHA) to determine the landslide-caused tsunami risk to DCPP would provide a very advanced understanding of tsunami risks at DCPP arising from near-shore landslide hazard. This work is to be strongly encouraged.
4.3
PG&E’s Geosciences Group continues to study the July 2007 Japanese earthquake which struck near the Kashiwazaki-Kariwa Nuclear Power Station in which no safety-related components were adversely affected. When the study is completed, they will assess any recommendations for the non-safety-related portions of DCPP.
4.4
PG&E’s Geosciences Department is beginning an update of its existing Long-Term Seismic Program with a five-year effort, including the US Geological Survey as a partner. The DCISC should follow the progress of this work.
4.5
DCPP has enhanced its already satisfactory Boric Acid Corrosion Control Program by better identifying and correcting boric acid leaks, increasing sensitivity of plant personnel, and developing an improved valve packing program. The plan’s goal is top industry quartile performance by Outage 1R15 (early 2009). The DCISC should review the Program in two years.
4.6
DCPP’s Root Cause Analysis on the lack of effectiveness of its Corrective Action Program (CAP) is expected to be completed in September 2008. It has identified the preliminary root cause as “senior leadership has not performed effective oversight of CAP” in setting and communicating standards and expectations for employees for the identification of lower level problems and for the timeliness of actions. Steps are being made to correct this. This is an important plant program, and the DCISC should review the analysis and corresponding corrective actions in the fall of 2008.
4.7
The DCPP Heating, Ventilation and Air Conditioning (HVAC) systems were in satisfactory health, and the system engineers appeared knowledgeable.
4.8
DCPP’s Outage 2R14 replacement of Unit 2 Steam Generators, a large, complex process, went well, meeting almost all pre-established goals. Post-installation tests confirmed that the new generators were performing as expected, except for measured Reactor Coolant System (RCS) Average Temperature of 567ºF vs. 569ºF expected. DCPP is resolving this non-safety issue which DCISC should follow.
4.9
DCPP appears to have taken appropriate measures to investigate and compensate for a damaged fuel rod found in Refueling Outage 2R14. The plant has stepped up its Reactor Vessel debris removal techniques for future cycles. The DCISC should follow up on the fuel failure root cause when it is completed in mid-June 2008.
4.10
DCPP had satisfactorily resolved the Containment Fan Cooler Unit reverse rotation issue in Outages 1R13 (November 2005) and 2R13 (May 2006) with backdraft damper modifications and enhanced maintenance. The plant is currently evaluating its schedule to install anti-rotation devices on the fan shafts which would be a better long-term resolution. The DCISC should continue to follow this issue up to and following implementation and testing of these devices.
4.11
The radiation dose projection programs used by DCPP, EARS (Emergency Assessment and Response System) and MIDAS (Meteorological Information and Dose Assessment System) appear to be comprehensive, accurate, and reliable. DCPP had had good experience using these proven industry standard programs.
4.12
The DCPP Outage 2R14 Unit 2 Containment integrated Leak Rate Test (ILRT) was performed successfully. All test acceptance criteria were met. The measured leak rate was approximately one-sixth of the acceptance criteria.
4.13
DCPP’s plans for performing its mid-cycle INPO (Institute of Nuclear Power Operations)-type self-assessment appear satisfactory. The DCISC notes that 12 of the 15 Areas for Improvement (AFIs) from the 2007 INPO evaluation are unresolved, but it is expected that the self-assessment report will highlight these areas and bring increased attention to them for resolution well before the 2009 INPO evaluation. The DCISC should continue monitoring the status of these AFIs and review the results of the mid-cycle assessment.
4.14
The DCPP meteorological tower sustained damage from a mobile crane and was as risk of failure. It appeared to the DCISC that DCPP personnel took prompt and appropriate action to protect plant equipment, personnel and vehicles until the tower could be removed and replaced.
5.0 Recommendations:
None

6.0 References

6.1
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Volume II, Exhibit D.5, Section 3.5, “Seismic Program.”
6.2
Ibid., Volume II, Exhibit D.8, Section 3.4, “Update on Tsunamis.”
6.3
SSHAC Methodology Report: “Recommendations for Probabilistic Seismic Hazard Analysis: Guidance on Uncertainty and Use of Experts”, R.J. Budnitz, G. Apostolakis, D.M. Boore, L.S. Cluff, K.J. Coppersmith, C.A. Cornell, and P.A. Morris, Report NUREG/CR-6372, Lawrence Livermore National Laboratory, sponsored by the U.S. Nuclear Regulatory Commission, U.S. Department of Energy, and Electric Power Research Institute (1997)
6.4
“Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007 – June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit B.3, “Presentation on PG&E’s Review of the Kashiwazaki-Kariwa Earthquake in Japan.”
6.5
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Volume II, Exhibit D.5, Section 3.5, “Seismic Program.”
6.6
“Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007 – June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit D.2, Section 3.5, “Boric Acid Corrosion Control Program.”
6.7
“Diablo Canyon Independent Safety Committee Seventeenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2006 – June 30, 2007”, Approved October 24, 2007, Volume II, Exhibit D.1, Section 3.6, “Attend Corrective Action Review Board (CARB) Meeting.”
6.8
“Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007 – June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit D.5, Section 3.3, “New Steam Generator Status & Tour Current Storage Area.”
6.9
“Diablo Canyon Independent Safety Committee Thirteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2002 – June 30, 2003”, Approved October 2, 2003, Volume II, Exhibit D.8, Section 3.4, “Nuclear Fuel System Review & Status of Issues.”
6.10
“Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007 – June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit D.9, Section 3.5, “Containment Fan Cooler Modifications.”
6.11
“Diablo Canyon Independent Safety Committee Sixteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2005 – June 30, 2006”, Approved October 18, 2006, Volume I, Section 4.15, System and Equipment Performance/Problems.”
6.12
“Diablo Canyon Independent Safety Committee Seventeenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2006 – June 30, 2007”, Approved October 24, 2007, Volume I, Section 4.15, “System and Equipment Performance/Problems.”
6.13
“Diablo Canyon Independent Safety Committee Fifteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2004 – June 30, 2005”, Approved October 12, 2005, Volume II, Exhibit D.8, Section 3.5, “Accident Radiation Exposure Projection Models.”
6.14
“Diablo Canyon Independent Safety Committee Eighteenth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2007 – June 30, 2008”, Approved October 7, 2008, Volume II, Exhibit D.2, Section 3.7, “DCPP Response to 2007 INPO Evaluation.”

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