25th Annual Report, Volume II, Exhibit D.8, Diablo Canyon Independent Safety Committee Report on Fact Finding Meeting at DCPP on April 21–22, 2015 by Peter Lam, Member, and R. Ferman Wardell, Consultant

1.0 Summary

The results of the April 21–22, 2015 fact-finding trip to the Diablo Canyon Power Plant in Avila Beach, CA are presented. The subjects addressed and summarized in Section 3 are as follows:

  1. Meeting with NRC Senior Resident Inspector
  2. Emergency Diesel Generator Status
  3. MIDAS (Meteorological Information and Dose Assessment System)
  4. Salt Deposition Rate Update
  5. Design Quality Status
  6. Spent Fuel Cooling System Review
  7. Attend Plant Health Committee Meeting
  8. FLEX Update
  9. Licensing Basis Verification Program Issues
  10. Pacific Ocean Winter Storm Experience
  11. Operational Decision Making
  12. Dr. Lam Meet with DCPP Site Vice-President

2.0 Introduction

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

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

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

3.0 Discussion

3.1 Meeting with NRC Senior Resident Inspector

The DCISC Fact-finding Team (FFT) met with Tom Hipshmann, NRC Senior Resident Inspector (SRI) at DCPP to share information on each organization’s reviews and findings. The DCISC last met with an NRC SRI in January 2015 (Reference 6.1) when it concluded the following:

DCISC meetings with the NRC Resident Inspector or Senior Resident Inspector continue to be beneficial with regard to sharing information and to understanding issues important to the NRC and to the DCISC.

The discussion centered on the following topics:

  1. The upcoming April 28, 2015 webcast NRC and PG&E joint panel discussion on PG&E’s March 2015 Fukushima-related seismic and flooding studies reports submittals
  2. The upcoming NRC Annual Assessment Letter for DCPP—there is the possibility of a White Finding on a DCPP self-identified Emergency Preparedness legacy issue for not having a formal procedure for surveillance of the ocean area near the plant. This could put DCPP into an augmented NRC inspection schedule with one additional annual inspection. DCPP-requested enforcement discretion on this issue was denied. As a result, DCPP initiated an Emergency Preparedness Licensing Basis Verification Project to assure its licensing bases were understood and appropriately met. The EPLBVP is scheduled to be completed by the end of 2015.
  3. Both the NRC and DCISC are following Emergency Diesel Generator issues. (The DCISC reviewed EDGs in this Fact-finding visit (see Item 3.2 below).
  4. The NRC will be looking into plant severe weather policies in the near future.
  5. The NRC is aware of some exceedences of the DCPP Hosgri Seismic Spectrum resulting from the recent seismic analyses and understand that PG&E may take credit for these with their Long-Term Seismic Program margin.
Conclusions:
The DCISC periodic meetings with the NRC Resident and/or Senior Resident Inspector continue to be beneficial for sharing of information on important DCPP issues.
Recommendations:
None

3.2 Emergency Diesel Generator Status

The DCISC Fact-finding Team met with Sean Dunlap, Supervisor of DCPP Balance of Plant Mechanical Systems Engineering, for an update on the status and health of the DCPP Emergency Diesel Generators (EDGs). The DCISC last reviewed the EDGs in March 2014 (Reference 6.2) when it concluded the following:

The six (three per unit) DCPP Emergency Diesel Generators (EGDs) are operable and able to perform their functions; however, system health is rated as Yellow (needs improvement) primarily because of the need to increase their rated loads to meet new demand conditions. Prompt Operability Assessments have been performed to support operation with the higher loadings. Testing has shown that the EDGs are able to perform at the higher loads. Calculations are being performed to support a License Amendment Request (LAR) for NRC review and approval prior to documenting the new loads in the Updated Final Safety Analysis Report. DCPP expects to return the EDGs to White (healthy) status in mid-2015. The DCISC should review the EDGs at that time.

The former EDG System Engineers (one mechanical engineer and one electrical engineer) have moved on to other assignments, leaving openings which the supervisor is currently in the process of filling and temporarily handling.

The EDGs are safety-related pieces of equipment whose functions are as follows:

The system has no direct non-safety related function.

The EDG fuel oil supply system has enough fuel capacity to provide seven days of onsite power generation in order to operate: (a) the minimum required Engineering Safety Features (ESF) equipment following a design basis loss-of–coolant accident (LOCA) for one unit, and the equipment in the second unit in either the hot or cold shutdown condition, or (b) the equipment for both units in either the hot or cold shutdown condition.

Each nuclear operating unit is supported by three EDGs. Each diesel-generator set is provided with two 100% capacity starting air trains, with each train having two starting air motors.

NRC Safety Guide (SG) 9 provides the basis for the design of the EDGs. Their ratings are as follows:

Each EDG is designed to start automatically on any of the following signals:

These automatic starts are to ensure that the EDGs are available with minimal delay to mitigate any operational or accident condition that may exist at the time of the signal. The Safety Injection signal, by itself, is an indication of an accident condition. The undervoltage signal from any vital bus is an indication of a loss of both onsite and offsite power sources.

Currently, the EDG Systems of both units are rated Yellow, as needing improvement, and have been Yellow for at least the previous four quarters. All of the EDGs are operable, but the following concerns appeared in the EDG System Health Report for each Unit:

License Amendment Request (LAR 14-001) to NRC for both units has been filed with the NRC for the following eight items. Corresponding calculations and implementation of LAR items are expected to be complete by July 1, 2015. The resolution of these loading issues will result in a healthy system color of White.

LAR 14-001 Issues

  1. Margin management issue: EDG time dependent dynamic load study showed that some EDGs are loaded above their continuous rating.
  2. Prompt Operability Assessment (POA): the Diesel Fuel Oil Day Tank low-level alarm is impacted by the higher EDG fuel consumption rates calculated.
  3. POA: EDG maximum calculated loads in Item 1 above are greater than the specified EDG full load rejection value.
  4. POA: EDG maximum calculated loads in Item 1 above are greater than the allowable Technical Specification (TS) upper frequency limit of 61.2 Hertz.
  5. POA: Current TS allow EDG testing below continuous and two-hour load ratings, which does not meet Regulatory Guide 1.108 requirements.
  6. POA: Sustained winds could impact the ability of the EDG radiators to cool the jacket water and engine compartment components.
  7. Engine Derate due to air inlet temperature being higher than ambient. This degraded condition is bounded by the POA for EDG loading.
  8. Engine Derate due to high jacket water intercooler inlet temperature, which is bounded by POA.

Other EDG Issues

  1. Margin Management Issue: The EDG usable volume of fuel oil in each Day Tank has been recalculated, and new low-level alarm setpoints are required. Estimated completion for Unit 1 is August 31, 2015 and for Unit 2 is July 1, 2015.
  2. Margin Management Issue: EDG instrument channel loop uncertainty of +/− 90 kW is too large to comply with LAR 14-001 requirements, due to deficient margin in the instrument control loops. EDG watt transducers will be replaced to reduce the uncertainty to 24.5 kW. Completion is expected by August 31, 2015 for Unit 1 and July 1, 2015 for Unit 2.
  3. Margin Management Issue: EDG dynamic loading analysis determined engines were overloaded and margins deficient. Long-term corrective action is to restore margin by uprating the engines. Completion is expected by the end of 2019.
  4. The EDG control system components are over 40 years old and obsolete. Upgrades are planned for 2017—2020 (Outages 1R20, 1R21, and 1R22 for Unit 1 EDGs) and (2R20, 2R21, and 2R22 for Unit 2 EDGs).
  5. Oil leakage occurs at the cylinder head pushrod grommets. Grommet replacements will be performed as part of the EDG uprate project to be completed by the end of 2019.
  6. Lower the pre-circulation lube oil standby pressure alarm setpoint. Completion is planned for mid-2016.

The DCISC notes that many of the conditions in the above listing are “Conditions Requiring Prompt Operability Assessments (POA) with Compensating Measures.” Four POAs have been implemented to support continued operation while the problems are resolved. DCPP expects to achieve White (healthy) status by July 1, 2015 with approval of the NRC of EDG LARs. Green health is expected to be achieved for Unit 1 by September 1, 2015 with the implementation of the Day Tank setpoint changes, Watt transducer upgrades, and capscrew upgrades by the end of August 2015. Green health is expected to be achieved for Unit 2 by June 10, 2016 when the above upgrades are complete and when Unit 2 EDGs re-enters the Maintenance Rule monitoring phase.

DCPP EDG Unavailability Goal

The DCPP unavailability goal is no more than 230 hrs/yr, per EDG evaluated for a rolling 24 month period.

Current performance

This performance appears acceptable to the DCISC; however, It was learned that EDG 1-2 is on a trend to exceed its unavailability goal at the end of 2015. DCPP has entered this into the Corrective Action Program for evaluation and corrective action.

EDG 2-3 was also reported to be having performance problems, and a Reliability Action Plan is being developed for completion by April 30, 2015 after review by the Plant Health Committee. Review of these two issues should be done on one of the next two fact-finding meetings in September or October 2015.

MSPI Performance data (12-quarter rolling unavailability) for the DCPP EDGs are as follows:

<
Unit Actual DCPP GoalNRC “White” Threshold
1 8.4 x 10−10 < 3.0 x 10−7 < 1.0 x 10−6
2 6.7 x 10−8 < 3.0 x 10−7 < 1.0 x 10−6

Regarding its position in the industry, DCPP EDGs rank in the second quartile.

Conclusions:
The six (three per unit) DCPP Emergency Diesel Generators (EDGs) are operable and able to perform their functions; however, system health is rated as Yellow (needs improvement) primarily because of the need to increase their rated loads to meet new demand conditions. Prompt Operability Assessments have been performed to support operation with the higher loadings. Testing has shown that the EDGs are able to perform at the higher loads. DCPP is awaiting NRC review and approval prior to documenting the new loads in the Updated Final Safety Analysis Report. DCPP expects to return the all EDGs to White (healthy) status by July 1, 2015 and Green by September 1, 2015 for Unit 1 and June 10, 2016 for Unit 2. The DCISC should review the new DCPP EDG Reliability Action Plan in September or October.
Recommendations:
None

3.3 MIDAS (Meteorological Information and Dose Assessment System)

The DCISC Fact-finding team met with Curt Hansen, Emergency Preparedness Coordinator, for an update on DCPP’s MIDAS program. The DCISC last reviewed MIDAS in August 2014 (Reference 6.3), when it concluded the following:

DCPP appears to have successfully implemented the second version of the Meteorological Information and Dose Assessment System (MIDAS), utilizing seven meteorological towers and several sonic detection and ranging (SODAR) units, which provides more accurate offsite radiation release consequence predictions. DCPP will be implementing the third MIDAS version by the end of 2014 which will provide the capability to accommodate multi-point releases. The DCISC should review the use of the new system in early 2015 and at the next emergency exercise observed by the DCISC.

MIDAS is used to predict the path and magnitude of radiation releases to the surrounding environment caused by an accident at the plant, such that protective action (sheltering, evacuation, etc.) recommendations can be made to protect the public. Inputs to MIDAS include the concentration and height of radioactive releases at the plant, wind and temperature data from up to seven meteorological towers and several SODAR (Sonic Detection and Ranging) units. The predictions are compared to data from roving Field Monitoring Teams and by nine Pressurized Ionization Chambers (PIC radiation detectors) at fixed locations.

For practice emergency exercises or actual accidents involving radioactive material releases radioactive dose assessment begins in the Control Room (CR) (or Control Room Simulator for practice exercises). Operators in the CR originally used a program named “EPR2net” to make initial calculations of offsite radiological consequences as described in DCPP Procedure EP R-2, “Release of Airborne Radioactive Materials Initial Assessment.” A special Control Room version of MIDAS replaced EPR2net, and operators have been trained on its use. The backup for this process is a manual calculation of radiological consequences using templates and pre-determined formulas.

When the Unified Dose Assessment Center (UDAC), a joint DCPP and San Luis Obispo (SLO) County team, is activated in a practice exercise or an actual emergency, they assume the duty of calculating offsite radiological consequences originally using EARS (Emergency Assessment Response System) and MIDAS. Now, the new MIDAS replaces EARS. Similarly, MIDAS replaces RASCAL (Radiological Assessment System for Consequence Analysis) previously used by San Luis Obispo County.

The purpose of the MIDAS third version was to enhance the capability of PG&E and the County for making appropriate Protective Action Recommendations (PARs) and decisions. Such decisions relate to the need to evacuate or shelter the population in various geographic sectors in the vicinity of DCPP in the event of an unplanned radiological release from the site. Typically, the most significant radioisotope initially from a radiological accident is Iodine-131 (with a half-life of approximately 8 days), which may be released in the form of small aerosol particles from fuel damaged in a severe accident, and can be ingested through breathing or eating contaminated food and then concentrated in the thyroid gland.

MIDAS has been verified by its developer and DCPP. There will be a self-assessment of MIDAS use with industry peers in June 2015 to prepare for an NRC inspection in August 2015. There is also an Emergency Preparedness exercise in June. The DCISC should follow up on these activities in the fourth quarter of 2015.

Conclusions:
DCPP has successfully implemented the third version of MIDAS (Meteorological Information and Dose Assessment System) for predicting the magnitude and path of radioactive plumes from the plant in the event of an emergency. This version will provide more accuracy and versatility than the previous version.
Recommendations:
None

3.4 Salt Deposition Rate Update

The DCISC Fact-finding team met with Ryan West, Manager, Electrical Engineering, to review data the plant has collected regarding the amount of salt deposition on plant equipment and components. The DCISC last reviewed this topic at its October 14-15, 2014 Public Meeting (Reference 6.4). At this meeting the DCISC reported the following:

Dr. Peterson reported the Evaluation considered the potential safety impact of using seawater for evaporative cooling in place of fresh water. He reported a study by the California Energy Commission reviewed the use and effect of high salinity water used in cooling towers on accelerated corrosion on unprotected metal surfaces on buildings and equipment. This report concluded that nearly all plants with high salinity cooling towers, both natural and forced draft, have encountered accelerated corrosion. Dr. Peterson reported that use of saltwater cooling towers with drift elimination at DCPP is expected to release approximately 830 metric tons of salt each year in aerosol form and a key question involves where that salt will be deposited on the plant site. Dr. Peterson reported data shows that the majority of the time the wind would carry a plume from southern-sited cooling towers to the south and away from the plant but 11% of the time the wind would carry the plume to the north and over the plant, while 23% of the time the plume would be expected to rise in light to no wind conditions. DCPP is once again collecting data on current salt deposition rates at various locations and it appears the current rate of deposition is approximately 1.5 or 2 metric tons per year. Dr. Peterson stated modeling tools could be used to develop more accurate projection for salt deposition which these would be important tools in reviewing the impact on systems and equipment which use large volumes of air such as the EDGs, the ventilation systems, and the dry cask spent fuel storage systems as well as upon the reliability of high voltage equipment including the switchgear in the 230 kV and 500 kV Switchyards where a simultaneous failure would lead to a loss of offsite power. Dr. Peterson observed that most of the flashover problems experienced by U-2 appear to be associated with drift from the Outfall which is pulled by the wind between the Administration and the Turbine Building and the use of freshwater could reduce or eliminate that issue. Use of saltwater cooling towers could increase deposition rates substantially from the present and periods of adverse weather with higher deposition rates could increase flashover events and this is subject to analysis through modeling. Dr. Peterson stated the Evaluation reviewed the use of high salinity cooling towers by the Palo Verde Nuclear Generating Station (Palo Verde) in Arizona which uses reclaimed water from the City of Phoenix in a desert environment with different wind and humidity than at DCPP and Palo Verde produces a lower salinity release, containing approximately one-half the amount of salt as is forecast for DCPP if saltwater cooling towers were built. Dr. Peterson stated the Evaluation concludes that more study concerning the implications of using saltwater cooling towers is required.

DCPP shared data for the following areas of the plant:

Plant Area Salt Contamination Level (ESSD)∗
230 kV Switchyard Buses Light
230 kV Switchyard Insulators Medium to Extra Heavy
230 kV Transformer Yard Insulators Light
500 kV Transformer Yard H0 Bushing (Unit 1) Heavy
500 kV Transformer Yard H1 Bushing (Unit 1) Medium to Extra Heavy
500 kV Transformer Yard H0 Bushing (Unit 2) Heavy
500 kV Transformer Yard H1 Bushing (Unit 2) Medium to Heavy

∗Where

  • Light = 0.03–0.08 mg/cm2 (Equivalent Salt Deposit Density)
  • Medium = 0.08–0.25
  • Heavy = 0.25–0.6
  • Extra Heavy = > 0.6

These data were measured in the February–March, 2015 time frame. The salt came from the Pacific Ocean spray, primarily from water exiting the plant discharge cascading down the discharge outfall. The level of deposition depended on the distance from the ocean and the exposure to the ocean.

The frequency and level of cleaning were directly proportional to the salt contamination level and other contaminants such as dirt and dust.

Conclusions:
Being an ocean-sited power plant, DCPP is susceptible to salt contamination from ocean spray. DCPP measurements of contamination levels on outdoor components showed what one would expect: contamination levels were directly proportional to the closeness and exposure to the ocean. Contamination levels ranged from Light to Extra Heavy.
Recommendations:
None

3.5 Design Quality Status

The DCISC met with Jacqui Hinds, Director, Quality Verification, for an update on QV’s assessment of DCPP Design Quality. The DCISC last reviewed Design Quality in August 2014 (Reference 6.5), concluding the following:

DCPP’s Design Quality measures show satisfactory performance based on scores of final designs released for installation. There was a small percentage (less than 10% ) which were problematic during Outage 1R18, and they have been corrected and evaluated for cause correction to prevent recurrence. The DCISC should continue to monitor design quality.

The Design Quality issue was about erroneous designs released for construction. During Refueling Outage 1R17 (Spring 2012), there were three major modification designs with errors released for implementation. The reason for the error determination was the large number of Field Changes required after design package release for the modifications to be implemented. Three design packages were issued incomplete (“managed exceptions” due to vendor issues and late scope additions, counting on the Field Change Process (FCP) to add information to complete the packages; however, the FCP did not include the same discipline and rigor as the full Design Change Process (DCP). Approximately one-third of the FCs were due to design errors. Adding to the problem was the fact that each of these designs was begun late and performed on a compressed time schedule.

DCPP had investigated the design quality problems and developed a plan of corrective action, which included, in addition to tighter controls of Field Changes, improved project communications, augmented pre-release design reviews, and additional training of engineers on the design change process. A Root Cause Evaluation (RCE) identified the root cause as “…the organization failing to recognize the risk and complexity of this first-time Process Control System (PCS) project, and therefore not assuring that an adequate organizational structure and project oversight were in place (i.e., did not designate it as a strategic project or Engineering major project). This ultimately created an environment that promulgated a human error-likely environment.”

Corrective actions were implemented and an effectiveness evaluation was performed following Outage 1R18 in June 2014. The conclusion stated, “A review of the performance of modification since implementation of the Process Control System (PCS) Root Cause Evaluation (RCE) has determined that the corrective actions have been effective.” This was based on the successful installation and one cycle of performance of the Process Control System (one of the problematic modifications on Unit 1) upgrade in Outage 2R17 as compared to its installation in Outage 1R17.

QV disagreed with the effectiveness review based partly on two problematic modifications out of ten completed for Outage 1R18: Unit 1 Containment Fan Cooler Unit Dampers and Single Point Vulnerability (SPV) on the Main Bank Transformers projects. Reviews of causes for these problems showed that they were unique to these projects and different than the previous 1R17 project problems. These were among the following Green-scoring projects:

Upon further analysis, Engineering agreed with QV and performed an additional evaluation of 64 major and minor projects and modifications over the course of the last three refueling outages and determined that approximately 92% were well-devised designs. When problems do occur, DCPP uses Root Cause Evaluations, Apparent Cause Evaluations, and Lessons Learned reviews to determine the causes for corrective actions and improvements.

Design Quality improved enough in Refueling Outage 2R18 that it is now off QV’s Site Status Report Top Issues List and Issues and Trends List; however, it remains a QV Concern, and QV is monitoring it. An Effectiveness Evaluation of Design Quality will be performed following Refueling Outage 1R19, which begins in October 2015. QV will be reviewing this evaluation, as should the DCISC. The plant’s Design Change Program health, a major measure of Design Quality, has been rated Green (good) since January 2015.

Conclusions:
DCPP Design Quality has been on Quality Verification’s top issues lists since its down-rating in Refueling Outage 1R17 which concluded in June 2012. Engineering has performed assessments and implemented corrective actions, which resulted in enough improvement in Outage 2R18 (Fall 2014) that QV changed from a top issue to monitoring. Since January 2014, the Design Change Program has shown Green (good) health. QV will perform an Effectiveness Evaluation following Outage 1R19 near the end of 2015. The DCISC should continue to monitor Design Quality.

3.6 Spent Fuel Pool Cooling System Review

The Fact Finding team met with Dan Hardesty, Senior Advising Engineer and System Engineer, for an update on DCPP’s Spent Fuel Pool 9SFP)Cooling System. The DCISC last reviewed this system in May 2011 (Reference 6.6), concluding the following:

Both Spent Fuel Pools and support systems appear to be in good condition. The system engineer continues to be knowledgeable and proactive. The two open issues noted during DCISC’s previous Fact-finding Visit, i.e. backup cooling for each pool and the need to inspect the heat exchangers, have been adequately addressed by DCPP. Based on several problems during the past year involving the incorrect placement of fuel assemblies in the SPFs, the DCISC should consider reviewing this process and DCPP’s evaluations and corrective actions resulting from the two problems identified in this report.

Also, the DCISC, at its October 2014 Public Meeting (Reference 6.5), heard a presentation from DCPP on improvements being made to the SFP level instrumentation.

Each of the two operating Units at DCPP has its own Spent Fuel Pool and SFP cooling system. Each SFP is an interim storage facility for fuel assemblies that have completed their useful cycles of producing power, hence the term “spent” fuel. However, even when the spent fuel assembly is removed from the reactor, it continues to produce heat due to radioactive decay which diminishes over time. When a spent fuel assembly’s heat production diminishes to an acceptable level, the assembly is then transferred from the pool, along with 31 other spent fuel assemblies, in a dry storage cask. This cask, containing the 32 spent fuel assemblies, is then transported to a secure dry storage area located on a hill above DCPP where the cask is bolted firmly to a strong, solid concrete and steel pad for dry storage. The Spent Fuel Pool is also the temporary storage facility for new fuel assemblies that have been delivered to the plant prior to loading them into the reactor during a refueling outage.

Because the fuel assemblies in the SFP continue to produce heat, it is important to keep the water in the pools cooled. The purpose of the SFP Cooling System is as follows:

The SFP Cooling System transfers decay heat from the SFP to the Component Cooling Water (CCW) System via the SFP heater exchanger. In addition, it maintains a water inventory in the SFP to provide radiation shielding for long-term storage of fuel assemblies in the SFP. It also purifies and demineralizes SFP water to maintain SFP water quality.

Each pool has two 100 percent capacity pumps provided with Class 1E electric power and one 100 percent capacity heat exchanger that is cooled by the Component Cooling Water (CCW). The SFP is designed with proper depth to provide a minimum of 23 feet elevation over the tops of the spent fuel assemblies. Each SPF has instruments that use floats to provide a high-level and low-level alarm locally and in the Control Room. Although the actual level in each SFP can be checked locally by observing level as marked on the wall of the pool, during normal operation there is no remote wide-range level indication that could be used to determine the pool water inventory from outside the fuel handling building. During outages a mounted camera is focused on the level-marking strip in the pool so that it can be read from the Control Room Annunciators in the Control Room. A new SFP water level instrumentation system is being installed, which will be connected to a readouts in the Control Room as described in the DCISC October 2014 Public Meeting minutes (Reference 6.6).

Because each Spent Fuel Pool has only one heat exchanger, the need for a second exchanger for each pool has been examined. DCPP has purchased and maintains one portable system consisting of hoses and three pumps. In situations where the cooling system for one of the SFPs becomes disabled, the portable system is set up to transfer the cooler water from the SFP with the operational cooling system into the second SFP, whose cooling system is inoperable, and then to recirculate water from the second SFP back to the SFP with the operational cooling system. In effect, each SFP cooling system can now serve as a backup for the other. It has been demonstrated that this portable system can be made operational within the minimum time-to-boil time frame for a Spent Fuel Pool, which would occur when the pool contains a full and recently offloaded reactor core. The installed heat exchangers have recently undergone eddy current examinations, and were found to have no significant tube indications.

The SPF Cooling System health is Green (good) overall for each Unit with no major problems outstanding. The System Engineer appeared knowledgeable and proactive about the System.

Conclusions:
DCPP’s Spent Fuel Pool (SFP) Cooling System is currently rated to be in Green (good) health with no major outstanding issues.
Recommendations:
None

3.7 Attend Plant Health Committee Meeting

The DCISC Fact-finding Team attended the April 22, 2015 Plant Health Committee (PHC) meeting. The DCISC last attended a PHC meeting in September 2013 (Reference 6.7), when it concluded the following:

DCPP’s Plant Health Committee meetings continue to be effectively and efficiently managed. Actions to regain the health of unhealthy systems are addressed swiftly and concretely.

The PHC is governed by DCPP Procedure OM4.ID16, “Plant Health Committee” and is a management team responsible for:

Membership and expected attendance is as follows:

Others are invited to the meetings as appropriate.

Plant health issues that require PHC review include:

The agenda for this meeting included the following:

  1. Safety Minute
  2. Reviewed Purpose and Desired Outcomes
  3. Assign a Scorecard Scribe
  4. Review and Approve Minutes from last meeting
  5. System Review: 480 Volt Vital and Non-Vital Systems—presentation of the System Health Report by the System Engineer (see below for a description of system health)
  6. Preventive Maintenance Deferral on Various Electrical Panels
  7. Action Item Review—all actions had been completed
  8. Meeting Evaluation

The system health for both units of 480 Volt System was White (healthy). It had been changed from Green (good) in the third quarter of 2012 due to a lack of compliance with a Westinghouse Technical Bulletin which requires that Westinghouse circuit breakers greater than 20 years old be cycled each refueling outage (RFO) to maintain their qualification or be replaced. DCPP had been cycling these breakers every third RFO. DCPP was in the process of re-scheduling breaker testing to meet the Westinghouse requirement. Green health was expected to be achieved again in late 2018.

DCPP considered the most significant challenge to system health to be the age of breakers, some of which are approximately 30 years old. There were also some seismic concerns about breakers for motor-operated valves, which could cause the valve to move to an undesired position. These issues are being managed through a program of breaker/bucket replacement, routine maintenance, and corrective action program.

The PHC meeting was run effectively and efficiently. Presentations were well prepared, discussions were focused, and decisions well founded. There is one new aspect of the PHC, which is their ability to now approve funding of up to $1 million per year and $100,000 each for expense items which affect safety and reliability.

The chart below shows system health from the standpoint of the number of systems with Red or Yellow health for longer than one refueling cycle. There are currently eight unhealthy Unit 1 and five unhealthy Unit 2 systems of which the three below in the table have been unhealthy for greater than one refueling cycle. The schedule for regaining health is as follows:

System Return to Health Schedule
EDG (Increase Load Margin) November 2015
Containment Fan Cooler Unit SI Timer Changes March 2016
Vital Inverter Output Breakers 2R19/1R20

System Health, Average Age, red / yellow systems

The PHC tracks these on a regular basis.

At the end of the PHC meeting, both Dr. Lam and Mr. Wardell were invited to provide comments about the meeting. Dr. Lam indicated that the meeting was conducted efficiently with focus and clarity. Mr. Wardell agreed and stated that the DCISC appreciated the purpose and actions of the PHC to keep systems healthy.

Conclusions:
The April 22, 2015 DCPP Plant Health Committee (responsible for plant system health), meeting was focused on improving the system health of the 480 Volt Vital and Non-Vital systems. The meeting was conducted crisply and effectively. The DCISC should observe these meetings regularly.
Recommendations:
None

3.8 Fukushima/FLEX Update

The DCISC Fact-finding Team met with Pat Nugent, Fukushima/FLEX Program Manager, for a report on the progress of the DCPP FLEX project. The DCISC last reviewed FLEX in January 2015 (Reference 6.8), concluding:

DCPP appears to have satisfactorily performed its Quick Hit Self-Assessment of its FLEX Program and Spent Fuel Pool Instrumentation Project. The overall conclusion was that the FLEX Program was in compliance with industry and NRC guidance with specific recommendations for program enhancements and remaining work. The DCISC Fact-finding Team concluded that the Assessment and resulting action plans were appropriate. The DCPP FLEX program is on-schedule for on-time completion.

The status of individual Fukushima/FLEX initiatives is as follows:

  1. Seismic and Flooding Hazard Re-evaluation
  1. Flooding and Seismic Re-evaluation Reports were submitted to NRC on March 12, 2015. NRC has separated these results from the plant design basis.
  2. Results of analyses using Local Intense Precipitation and Probable Maximum Flood show some ponding in areas around the Turbine and Auxiliary Buildings, which can be mitigated by use of sandbags. There were no other exceedences.
  3. Results of tsunami analyses show a one foot decrease in tsunami wave height, which is bounded by the original design basis.
  4. Two exceedences, drawdown for the Auxiliary Saltwater (ASW) Pump and run-up/scouring above the ASW Bypass Piping, do not affect current designs.
  5. New seismic analysis are generally bounded by existing Hosgri analysis with some exceedences in high and low frequency ranges.
  1. No safety-related equipment is susceptible to the high and low frequencies in question
  2. New ground motion spectra are bounded by the Long-Term Seismic Program spectra.
  3. All equipment meets both spectra.
  1. Seismic and Flood Walkdowns
  1. No issues
  2. No further work expected in this area at this time
  3. Potential flood seal issue in ASW Pump Vault, which plant is reviewing
  1. New NRC Station Blackout Rule underway—draft expected Summer 2015 earliest. DCPP will use Licensing Basis Verification Project to handle.
  2. FLEX Strategy Design Packages
  1. SFP Cooling—issued
  2. Raw Reservoir—issued
  3. Primary Storage in Warehouse—issued
  4. Emergency Auxiliary Feedwater (EAFW)—issued
  5. Emergency Reactor Coolant System (ECRS) Make-up—issued
  6. Safety Function Support—April 17, 2015
  7. Emergency Auxiliary Saltwater (EASW)—issued
  8. Debris Mitigation—May 15, 2015
  9. Units 1 and 2 Mechanical and Electrical Modifications—issued
  10. Communications Modifications—issued
  1. Storage Locations
  1. Primary On-site Storage—begin moving in June 1, 2015
  2. Secondary On-site Storage (near ISFSI)—design to be issued May 15, 2015
  1. Equipment Procurement
  1. Front-end loaders and ERCS pumps on-site
  2. Mobile generators and EASW pump stored off-site until air permits received
  1. FLEX Support Guidelines drafted and ready for training
  2. National SAFR Response Center—design to be issued by June 15, 2015
  3. NRC Pre-Implementation Audit—week of August 17, 2015
  4. Spent Fuel Pool Instrumentation
  1. Design to be issued by April 23, 2015
  2. Equipment delivery scheduled for June 30, 2015
  3. Installation scheduled for July 15—September 15, 2015
  1. On-Site Emergency Response Center Staffing Study
  1. Phase 1 study completed in 2013
  2. Phase 2 study begun April 2015—possibly need one engineering position filled.
  3. Report to NRC by May 26, 2015
  1. Emergency Preparedness
  1. Final multi-unit dose assessment program complete
  2. MIDAS software enhancement underway
  1. INPO review visit scheduled for first week of June 2015
Conclusions:
The DCPP Fukushima/FLEX modifications, analyses, equipment, procedures and training appear to be on-schedule.
Recommendations:
None

3.9 Licensing Basis Verification Project

The DCISC Fact-finding team met with Eric Nelson, Project Manager for the Licensing Basis Verification Project (LBVP), and Christen Zaitz, NSSS (Nuclear Steam Supply System) Structural and Licensing Engineer, for an LBVP update. Mr. Nelson had presented an update at the June, 2015 DCISC Public Meeting (Reference 6.9).

The purpose of the Licensing Basis Verification Project (LBVP) is to perform an objective evaluation to ensure the DCPP’s licensing basis has been adequately maintained, and to resolve any identified discrepancies. This is a voluntary effort by PG&E to ensure safe and reliable continued operations, and in this effort the LBVP is aligned with NRC. The goal is to provide the best possible Final Safety Analysis Report (FSAR) and the most accurate current licensing basis (CLB) determination to enhance technical evaluations going forward. Additional key goals are to provide and enhance knowledge transfer of the CLB. The FSAR is a summary document of DCPP’s commitments to the NRC which documents the plant’s design basis. When changes are made to DCPP they are reviewed against the licensing basis and the FSAR to ensure continuing compliance. The FSAR is required to be updated and the updated FSAR is submitted to the NRC at the conclusion of each U-2 refueling outage.

The main scope of the LBVP is as follows:

DCPP has made a commitment to the NRC to complete the LBVP by December 31, 2015. Completion of the LBVP includes:

The DCISC was interested in one particular LBVP issue in this meeting: the Hosgri seismic and LOCA (Loss of Reactor Coolant Accident) load requirements for the new Reactor Vessel Head and new DCPP Steam Generators. Apparently, the DCPP-specific requirements for procurement of these components had been overlooked when ordered as replacements; however, the components had been designed to generic industry requirements. This discrepancy was originally identified by the LBVP Project as reported to the DCISC in its November 20–21, 2013 Fact-finding meeting (Reference 6.10). As reported at that time, a Prompt Operability Assessment (POA) was completed permitting continued operation and a seismic re-analysis was initiated. This work is expected to be completed and approved by September 30, 2015, and the related Westinghouse concrete load report by October 20, 2015.

Regarding the overall status of the LBVP, the following was reported to the DCISC:

  1. System reviews and FSAR updates are to be completed by June 30, 2015
  2. All FSAR reviews and section updates (excluding corrective actions) are to be completed by December 31, 2015
  3. All corrective actions are to be completed in 2016
Conclusions:
DCPP’s Licensing Basis Verification Project (LBVP) continues to progress on schedule with a completion date of year-end 2015. An issue identified by the Project, incorrect specification of the seismic and loss-of-coolant accident loads on the new reactor vessel heads and steam generators, is being re-analyzed, and is expected to be completed by September 2015.
Recommendations:
None

3.10 Pacific Ocean Winter Storm Update

The DCISC Fact-finding Team met with Paula Gerfen, Director of Operations, for an update on 2014–2015 winter storm impact on DCPP. The DCISC last reviewed this topic in April 2014 (Reference 6.11) when it concluded the following:

DCPP’s winter 2013–2014 storm experience was moderate with respect to its impact on intake equipment, resulting in a single rampdown of Unit 2 to 28% power for about 18 hours. Substantial improvements have been made, such as to traveling screens and screen wash pumps at the plant intake, particularly the addition of a new “Bubble curtain” system, which can be expected to improve the reliability of the cooling water system and the electric generating plant.

Station Procedure OP O-28, “Intake Management,” provides direction with respect to mitigating the effects of short-term debris loading on the intake traveling screens and condensers. The procedure directs appropriate Operations, Maintenance and Security personnel to the intake to evaluate whether systems and equipment are operating at maximum capacity. Engineering may be directed to develop a plant rampdown plan, and Learning Services may prepare for training for Operations to practice ramping down the units on the Plant Simulator.

The procedure defines and addresses high swell forecasting, high swell warning, and Operations response to high swell warning. Pre-job briefs would be conducted for the Control Room operators as well as for the intake operators who would be expected to monitor intake conditions frequently. Maintenance and Security personnel would be directed to the intake along with Operations personnel to help ensure that systems and equipment (e.g. intake screens and wash pumps) are able to be operated at maximum capacity. Engineering could become involved, as appropriate, in developing a plant ramp plan and Learning Services could prepare training in which operators could practice ramping the units on the plant simulator. The response, when appropriate, would include operating the intake screens manually, controlling the screen speed appropriately, and manning the intake with two operators.

During this past winter, there were no Pacific Ocean winter storms which impacted DCPP.

Conclusions:
During this past winter (2014–2015), there were no Pacific Ocean winter storms which impacted DCPP.
Recommendations:
None

3.11 Operational Decision Making

The DCISC Fact-finding Team met with Paula Gerfen, Director of Operations, to review DCPP’s Operational Decision Making (ODM) Process and review several recent examples of its application. The last DCISC review of ODM was in March 2012 (Reference 6.12), concluding the following:

The DCPP Operational Decision Making process appeared sound and effective for solving problems, which affect plant operability and safety. Two example ODMs reviewed were performed satisfactorily.

The DCISC Fact-finding Team (FFT) reviewed DCPP Procedure OP1.ID7, “Operational Decision Making,” Revision 10, November 10, 2014. This is the controlling procedure for ODM. The FFT concluded that the procedure was satisfactory. According to the procedure, the purpose of ODM is to “provide a systematic method for evaluating technical and operational issues at the station and making effective decisions that affect plant operations, safety, reliability, and material condition when faced with degraded conditions.”

Degraded conditions may involve reductions in operating/safety margins or encroachment on system/component reliability that occur over days or weeks. Examples include:

The Station Director is the Decision Maker (or assigns a Decision Maker) for decisions that involve outage extensions of >24 hours, potential NRC Notice of Enforcement Discretion, decisions that involve changes in mode or power level, short duration action statements, or changing curtailment schedules. The Decision Maker typically assigns a Decision Team, which is composed of individuals with expertise in diverse areas applicable to the decision at hand. For evolutions that involve a significant reduction in reactor safety, an individual with a Senior Reactor Operating License will be designated to lead the Decision Team.

The Decision Team meets and follows a prescribed process to collect and analyze data and formulate a decision using/considering the following:

When its decision is made, the Decision Team obtains final approval from the Station Director who reports the decision to the Site Vice-President. The decision is communicated to plant personnel and is implemented. An effectiveness review is performed about six months after completion of the ODM.

The DCISC reviewed the following three ODMs:

  1. Pressurizer Power Operated Relief Valves (PORVs) are required to be stroked once per calendar quarter. One PORV had its block valve closed due to hydrogen leakage through its associated PORV. Based on experience, stroking the PORV would introduce a pressure transient, causing excessive hydrogen leakage while the block valve is opened and may cause increased Pressurizer safety valve leakage of hydrogen after the block valve is stroked. The Decision Team considered six solutions, including doing nothing, before deciding on the action to declare the block valve inoperable due to excessive leakage and enter Technical Specification 3.4.11, Action A, which states that when one or more PORVs is inoperable and capable of being manually cycled, close and maintain power to associated block valve. This would temporarily remove the stroke test requirement and leave the PORV available if needed. The valves would remain in this state until repairs were made in an outage.
  2. Unit 2 experienced a reactor trip due to tie-line differential relay operation. The cause of the differential relay operation was a single line-to-ground fault on the A Phase CCVT (Capacitive Controlled Voltage Transformer) due to an insulator flashover. The components, along with their lightning arrestors and main bank phase A and B high voltage bushings have an insulating system of silicone polymer rather than porcelain for personnel safety. The Decision Team was asked to consider options with a goal to develop a way to ensure that Unit 1 can operate safely without flashover until the next refueling outage. The solution was to continue to monitor the CCVTs performance with high power optics and camera during the next rain storm and plan for a unit curtailment later for contaminant cleansing.
  3. It was determined that Unit 2 Reactor Coolant System (RCS) leakage was increasing slowly. A Trouble-shooting Team was initiated to determine the location. The leak was in the Reactor Coolant Pump 2-3 seal leak-off lines. A Decision Making Team was assembled to determine a course of action, including shutting down the unit to repair the seal. The Team decided to continue to monitor the leakage, and if leakage were to increase beyond 0.4 gallons per minute (gpm), then the unit would be shut down for repair. Reducing the seal flow injection stabilized the leak to an acceptable < 0.1 gpm.

The DCISC FFT also reviewed the three following effectiveness evaluations for other ODMs which were more than six months old:

  1. Unit 1 Condenser delta-P (pressure drop) exhibited an increasing trend, which signified that intake tunnel cleaning would be needed sooner that originally scheduled. An ODM Decision Making Team convened and reviewed the situation. It decided to move the tunnel cleaning up one week. This was performed successfully. An effectiveness evaluation was later performed by an Operations Shift Foreman. The evaluation concluded that the ODM was effective in that the tunnel cleaning was performed in a timely manner to avoid unit curtailment and did not result in any reactor scrams or transients; challenges to nuclear safety or related systems, structures or components; increase in area radiological dose rates or any elevation in offsite dose; or any unplanned entry into Equipment Control Guidelines or Technical Specifications.
  2. An ODM was performed to assess and decide what course of action to take for a grounding problem in the Plant Process Control System. This problem could have adversely affected the plant’s Appendix R Fire Protection analysis. The ODM selected having a temporary modification made to correct the ground problem. The temporary modification would be in place until a permanent modification could be implemented. An effectiveness evaluation concluded that this ODM was effective because there were no shorts or other plant problems due to the temporary grounding modification.
  3. An ODM was written to install the salp bubble curtain in June 2014 to prevent jellyfish-like salp from entering the plant intake during high salp months of July and August and cause plant power curtailment or shutdown. The effectiveness evaluation concluded the ODM was effective because no significant amount of salp entered the intake and there were no other adverse impacts on the plant.
Conclusions:
DCPP appears to have performed its Operability Decision Making satisfactorily. Follow-up effectiveness evaluations were performed appropriately concluding that the ODMs were effective.
Recommendations:
None

3.12 Dr. Lam Meeting with DCPP Site Vice-President

Dr. Lam met with DCPP Site Vice-President Barry Allen to discuss items from this fact-finding and other items of mutual interest.

4.0 Conclusions

4.1
The DCISC periodic meetings with the NRC Resident and/or Senior Resident Inspector continue to be beneficial for sharing of information on important DCPP issues.
4.2
The six (three per unit) DCPP Emergency Diesel Generators (EDGs) are operable and able to perform their functions; however, system health is rated as Yellow (needs improvement) primarily because of the need to increase their rated loads to meet new demand conditions. Prompt Operability Assessments have been performed to support operation with the higher loadings. Testing has shown that the EDGs are able to perform at the higher loads. DCPP is awaiting NRC review and approval prior to documenting the new loads in the Updated Final Safety Analysis Report. DCPP expects to return the all EDGs to White (healthy) status by July 1, 2015 and Green by September 1, 2015 for Unit 1 and June 10, 2016 for Unit 2. The DCISC should review the new DCPP EDG Reliability Action Plan in September or October.
4.3
DCPP has successfully implemented the third version of MIDAS (Meteorological Information and Dose Assessment System) for predicting the magnitude and path of radioactive plumes from the plant in the event of an emergency. This version will provide more accuracy and versatility than the previous version.
4.4
Being an ocean-sited power plant, DCPP is susceptible to salt contamination from ocean spray. DCPP measurements of contamination levels on outdoor components showed what one would expect: contamination levels were directly proportional to the closeness and exposure to the ocean. Contamination levels ranged from Light to Extra Heavy.
4.5
DCPP Design Quality has been on Quality Verification’s top issues lists since its down-rating in Refueling Outage 1R17 which concluded in June 2012. Engineering has performed assessments and implemented corrective actions, which resulted in enough improvement in Outage 2R18 (Fall 2014) that QV changed from a top issue to monitoring. Since January 2014, the Design Change Program has shown Green (good) health. QV will perform an Effectiveness Evaluation following Outage 1R19 near the end of 2015. The DCISC should continue to monitor Design Quality.
4.6
DCPP’s Spent Fuel Pool (SFP) Cooling System is currently rated to be in Green (good) health with no major outstanding issues.
4.7
The April 22, 2015 DCPP Plant Health Committee (responsible for plant system health), meeting was focused on improving the system health of the 480 Volt Vital and Non-Vital systems. The meeting was conducted crisply and effectively. The DCISC should observe these meetings regularly.
4.8
The DCPP Fukushima/FLEX modifications, analyses, equipment, procedures and training appear to be on-schedule.
4.9
DCPP’s Licensing Basis Verification Project (LBVP) continues to progress on schedule with a completion date of year-end 2015. An issue identified by the Project, incorrect specification of the seismic and loss-of-coolant accident loads on the new reactor vessel heads and steam generators, is being re-analyzed, and is expected to be completed by September 2015.
4.10
During this past winter (2014–2015), there were no Pacific Ocean winter storms which impacted DCPP.
4.11
DCPP appears to have performed its Operability Decision Making satisfactorily. Follow-up effectiveness evaluations were performed appropriately concluding that the ODMs were effective.
5.0 Recommendations:
None
6.0 References
6.1
“Diablo Canyon Independent Safety Committee Twenty-Fifth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2014—June 30, 2015”, Approved October 21, 2015, Volume II, Exhibit D.6, Section 3.10 “Meeting with the NRC Senior Resident Inspector.”
6.2
“Diablo Canyon Independent Safety Committee Twenty-Fourth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2013—June 30, 2014”, Approved October 22, 2014, Volume II, Exhibit D.7, Section 3.10 “Emergency Diesel Generator Review.”
6.3
“Diablo Canyon Independent Safety Committee Twenty-Fifth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2014—June 30, 2015”, Approved October 21, 2015, Volume II, Exhibit D.2, Section 3.1, “MIDAS (Meteorological Information and Dose Assessment System).”
6.4
Ibid., Exhibit B.1, “Salt Deposition Rate Update.”
6.5
“Diablo Canyon Independent Safety Committee Twenty-Fifth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2014—June 30, 2015”, Approved October 21, 2015, Volume II, Exhibit D.2, Section 3.5, “Design Quality Effectiveness Evaluation.”
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 9, 2011, Volume I, Exhibit D.11, Section 3.5, “Spent Fuel Pool System Review.”
6.7
“Diablo Canyon Independent Safety Committee Twenty-Fourth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2014—June 30, 2014,” Approved October 22, 2014, Volume II, Exhibit D.3, Section 3.9, “Attend Plant Health Committee Meeting.”
6.8
“Diablo Canyon Independent Safety Committee Twenty-Fifth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2014—June 30, 2015”, Approved October 21, 2015, Volume II, Exhibit D.6, Section 3.1, “FLEX Quick Hit Self-Assessment.”
6.9
Ibid., Exhibit B.9, “Licensing Basis Verification Project.”
6.10
“Diablo Canyon Independent Safety Committee Twenty-Fourth Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2013—June 30, 2014,” Approved October 22, 2014, Volume II, Exhibit D.4, Section 3.3, “Licensing Basis Verification Project.”
6.11
Ibid., Exhibit D.8. Section 3.2, “2013–2014 Winter Storm Update.”
6.12
“Diablo Canyon Independent Safety Committee Twenty-Second Annual Report on the Safety of Diablo Canyon Nuclear Power Plant Operations, July 1, 2011—June 30, 2012,” Approved October 22, 2012, Volume II, Exhibit D.7, Section 3.6, “Operational Decision Making.”

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.