Exhibit C, Volume 2, Diablo Canyon Power Plant (DCPP) Operations, DCISC 17th Annual Report - July 1, 2006 thru June 30, 2007
1.0 PG&E/DCPP Organizations
PG&E Generation organization charts, including the DCPP organization, are included as attachments to Exhibit C.
2.0 Summary of Diablo Canyon Operations
2.0.1 Operating Capacity Factor
During the assessment period of July 1, 2006, through June 30, 2007, Diablo Canyon’s operating performance was a combination of superior and challenging operations, including one scheduled refueling outage in Unit 1 in April/May 2007 and two forced outages in Unit 2. Total plant Operating Capacity Factor during this 12-month period averaged 99.8% (Net Maximum Dependable Capacity). Operating Capacity Factor (OCF) is the Capacity Factor excluding refueling outage periods.
Unit 1 Operating Summary
During the 12-month period ending June 2007, Unit 1’s operation was excellent with an average Operating Capacity Factor of 95.3% (Net Maximum Dependable Capacity, excluding refueling outages).
Unit 1 displayed good operating performance during this period, experiencing two planned non-refueling events for ocean cooling water tunnel cleaning and performance of a standard test procedure, and no unplanned events affecting power production. See table below.
Also occurring during this reporting period was Unit 1’s 1R14 refueling outage, starting on April 30, 2007, and completing in 29.8 days. When Unit 1 shut down for 1R14, this was the first time in Unit 1’s 21-year operating history that a fuel cycle (Cycle 14) completed without experiencing any forced outages (since the completion of the 1R13 refueling outage), remaining on-line during the entire fuel cycle’s power operation period. Following 1R14, the 3.8-day power ascension duration also set a new plant record for the shortest power ascension period in plant history.
Unit 1 Power Curtailments July 2006 – June 2007
| Start Date | Type | Duration | Curtailed Mwe | Event |
|---|---|---|---|---|
| 26 Nov 06 | Curtailed | 6.7 days | 550 | Planned reduction for cleaning marine biofouling from Circ Water Tunnels & Condenser Waterboxes |
| 05 Feb 07 | Curtailed | 1.5 days | 12 | Planned 12 Mw reduction for STP R07B End-of-Life Moderator Temp. Coeff. Determination |
| 29 Apr 07 | Curtailed | 29.8 | Refueling | Planned 1R14 Refueling Outage shutdown |
| 12 May 07 | Loss of 230kV | 4 hours | Refueling | Loss of 230 kV power to DCPP. No impact on generation. |
Unit 2 Operating Summary
During the 12-month period ending June 2007, Unit 2 experienced several unexpected events, but still maintained an average Operating Capacity Factor of 99.3% (Net Maximum Dependable Capacity, excluding refueling outages).
As reported in the table below, Unit 2 experienced two forced outages, including one automatic reactor trip, and three unplanned and two planned curtailments.
In December 2006, there were two forced outages. On December 10th, Unit 2 manually separated from the grid to repair failed stator temperature instrumentation on Reactor Coolant Pump 2-2, being off-line for 1.8 days. Upon completion of the outage, while Unit 2 was in the process of power ascension, Unit 2 experienced an automatic reactor trip when an electrical overcurrent occurred in Circulating Water Pump 2-1 during pump restart, causing a small localized fire that was quickly extinguished, resulting in a 1.9-day outage.
Two of the five curtailments had the most impact on power generation. On August 31, 2006, Unit 2 performed an unplanned reduction to 73% power for 0.6 days to address an RCS thimble tube leak beneath the reactor vessel. On April 2, 2007, Unit 2 performed a planned 4.6-day reduction to 57% power to clean the ocean cooling water tunnels of marine growth.
Unit 2 Power Curtailments July 2006 – June 2007
| Start Date | Type | Duration | Curtailed Mwe | Event |
|---|---|---|---|---|
| 12 Jul 06 | Curtailed | 25 days | 3 | Unplanned reduction to fix MSR 2-2A LCV-194 |
| 31 Aug 06 | Curtailed | 0.6 days | 330 | Unplanned reduction to 73% to investigate and resolve a RCS thimble tube leak beneath the Reactor. |
| 16 Sep 06 | Curtailed | 0.3 days | 162 | Planned reduction to 81% for STP M-21C, Main Turbine Control Valve Testing |
| 10 Dec 06 | Forced | 1.8 days | -- | Manual Reactor trip due to failure of RCP 2-2 stator temperature instrumentation |
| 12 Dec 06 | Forced | 1.9 days | -- | Auto Reactor trip due to electrical overcurrent while starting CWP 2-1 & small fire. |
| 5 Jan 07 | Curtailed | 3.9 days | 10 | Unplanned 10 Mw reduction to repair FDW Heater 2-1C steam leak. |
| 02 Apr 07 | Curtailed | 4.6 days | 537 | Planned reduction to 57% for Circulation Water Tunnel Cleaning. |
| 12 May 07 | Loss of 230kV | 4 hours | None | Loss of 230 kV power to DCPP. No impact on power generation. |
2.0.2 Refueling Outages
The Unit 1 fourteenth refueling outage (1R14) occurred between April 30 and May 29, 2007. PG&E continued to follow the same shutdown/RCS cleanup strategy as in the most recent outages, which continued to reduce radiation dose levels below previous U1 outages at many locations. The overall exposure for 1R14 was 103.2 person-Rem, exceeding the goal going into the outage of less than 84 person-Rem. Although there were a number of dose-significant projects that contributed to exceeding this goal, the amount by which the goal was exceeded was disappointing and has been entered into the corrective action program. Although there were no nuclear safety challenges, there was one disabling injury or there were six recordable injuries and one significant human performance events (site-level clock reset).
Scope highlights include replacement of the containment recirculation sump screens, Reactor Head volumetric inspection, 4kV vital Bus F load cables and cubicle wiring replacement, Reactor Coolant Pump 1-1 and 1-3 seal replacements, RCS makeup system replacement, Charging pump 1-3 replacement, and preparation activities for the Steam Generator replacement in 1R15.
The pre-outage planning phase was marked by six red milestones - four related to planning and preparation challenges. The most significant managed exception was the containment recirculation sump project. While well-managed, preparations associated with this project were completed after closure of nearly all pre-outage milestones.
Financial goals for 1R14 included a duration of 25 days or less at a cost of $40.1 million or less. The outage duration and cost actuals were approximately 29 days and $41.3M. The significant contributors to the schedule delays were associated with vital bus F work activities, as well as main bank transformer bushing, charging pump, sump, and makeup system replacements.
Over 800 lessons learned were collected during 1R14. During the post-outage management critique, each department identified their key lessons learned and the actions for addressing them. In addition, an initiative was undertaken to improve the implementation of the 10/30 minute rule, consistent with high performing plants. Actions were put in place to improve the site’s schedule performance, particularly modeled around 2006 benchmarking of industry-leading outage schedule implementation methods. The physical layout and staffing of the Outage Coordination Center remained largely the same as the previous outage, in order to reap the same benefits realized in 2R13.
The key issues related to DCPP not meeting its goals for 1R14 were inadequate site preparations, inferior project execution, and inadequate safety focus. As a result, a Non-Conformance Report (NCR) was opened to address the safety issues related to the outage (N0002217), and an Apparent Cause Evaluation (ACE) is being written to understand the key causes and contributors to the organizational “miss” on outage goals (A0701529).
2.0.3 Collective Radiation Dose Equivalent Exposures
The bulk of personnel radiation exposure occurs during refueling outages. For this reason, the total annual exposure is largely dependent upon the outage planning effectiveness, radiation levels, outage duration, number of outages conducted in the year and emergent maintenance activities.
The collective radiation exposure for 2006 was 82.2 person-Rem total for both units. Included in that total was the Unit 2 13th refueling outage exposure. The actual exposure for 2R13 was 74.3 person-Rem, and the actual exposure for on-line work totaled 7.9 person-Rem.
The collective radiation exposure goal for 2007 is 92 person-Rem for both units. This value includes goals for 1R14 exposure of 84 person-Rem and on-line exposure of 8 person-Rem.
The total 2007 exposure through June 30, 2007 was 109 person-Rem. The actual exposure for 1R14 was 103.3 person-Rem, and the actual exposure for on-line work through June 30, 2007 is 5.7 person-Rem. 1R14 dose performance of 103.3 person-Rem was best ever performance for Unit 1. The inability to meet the challenging 1R14 dose goal was due primarily to increased scope and emergent issues. On-line exposure continues to track at low levels and is first quartile performance compared to the rest of the PWR industry.
2.0.4 Industrial Safety Lost-Time Accident Rate
The 2007 PG&E industrial safety goal is zero lost-time injuries. This is unchanged from the 2006 goal. There was 1 lost-time injury recorded in 2006. There have been 3 lost-time injuries year-to-date in 2007.
2.0.5 Unplanned Reactor Trips
PG&E’s goal is to have no unplanned automatic reactor trips per unit per year while critical. Unnecessary reactor trips not only reduce plant capacity factor, they also represent unnecessary challenges to safety systems and may indicate substandard operating or maintenance practices. Manual trips are not counted because PG&E believes this might inhibit operator-initiated trips and actions to protect equipment.
On December 12, 2006, while returning to service following a short unplanned outage to repair failed Reactor Coolant Pump 2-2 stator temperature instrumentation, Unit 2 experienced an automatic reactor trip when an electrical overcurrent occurred in Circulating Water Pump 2-1 during pump restart, causing a small localized fire that was quickly extinguished, resulting in a 1.9-day outage.
2.0.6 Unplanned Safety System Actuations
This indicator is the sum of the number of unplanned emergency core cooling system (ECCS) actuations (whether the ECCS actuation set point has been reached or from a spurious or inadvertent ECCS signal) and the number of unplanned emergency AC power system actuations that result from the loss of power to a safeguards bus. For Diablo Canyon, ECCS actuations include actuations of the high-pressure injection system, the low-pressure injection system, or the accumulators. Such actuations should be avoided because the plant should be maintained in a safe configuration to preclude actuations, and unnecessary challenges to plant safety systems should be minimized.
PG&E’s goal for this indicator continues to be no unplanned safety system actuations at DCPP. During this reporting period, Diablo Canyon experienced two actuations.
On December 12, 2006, at 1:22 pm, while conducting power ascension with Unit 2 at approximately 25% power, an electrical failure occurred in the Unit 2 Circulating Water Pump 2-1 motor enclosure, initiating an automatic reactor trip. The explosive failure of a surge capacitor caused a small, short-duration fire that was quickly extinguished.
On May 12, 2007, at 10:25 am, due to the failure of the Morro Bay – Diablo Canyon transmission line, Unit 1 off-site startup power was lost to both units, resulting in an 8-hour non-emergency event notification in accordance with 10 CFR 50.72(b)(3)(iv)(A) for a valid actuation of five emergency diesel generators (EDGs) due to the loss of startup power. At the time, Unit 1 was in “No Mode” during its 1R14 refueling outage, with all fuel offloaded to the spent fuel pool (SFP). Auxiliary power was cleared for maintenance and offsite power was being provided by startup power. EDG 1-3 was also cleared for maintenance. On the loss of startup power, EDGs 1-1 and 1-2 auto-started and powered their loads. Since SFP cooling is not automatically loaded on the EDGs, Operators re-started a SFP Cooling pump. This re-established decay heat removal via component cooling water (CCW) (two of three pumps remained operable) and auxiliary saltwater pump 1-2. SFP temperature remained at approximately 105 degrees F.
Unit 2 remained in Mode 1 at 100 percent power with auxiliary power supplying Unit 2 equipment. The loss of startup power caused all three EDGs to auto-start but did not load.
At approximately 11:30 am, startup power was restored to the site via the Mesa substation. Operators completed restoration of startup power to plant equipment by approximately 2:30 pm.
2.0.7 Secondary Chemistry Index (SCI)
The purpose of the secondary chemistry index is to evaluate and trend chemistry control in the feedwater and steam generators. Experience has shown that operation with impurity concentrations above the target values used in this indicator will likely cause increased corrosion damage. Therefore, PG&E believes plants with MA 600 steam generator tubing should be operated with the lowest practicable impurity levels.
The index goal for 2007 is 1.00. This index is based on a normalized ratio of the steam generator and feedwater parameters divided by their limiting factors per INPO specifications where 1.00 is the lowest and most desirable score.
The 18-month rolling average through the end of June 2007 is 1.01 for Unit 1 compared to 1.00 in 2006. The increase from 1.00 to 1.01 is due to sulfate increases associated with implementation of new condensate polisher resin during August 2006. The Unit 1 index is projected to remain at 1.01 during 2007 due to this reason.
The 18-month rolling average through the end of June 2007 is 1.00 for Unit 2 compared to 1.01 in 2006. The decrease from 1.01 to 1.00 is due to 2R12 startup transients now being greater than 18 months ago. Startup control strategies aimed at reducing transients to the secondary system that cause impacts to these critical parameters have been successfully implemented. The unit 2 index is projected to remain at 1.00 for 2007.
2.0.8 Fuel Reliability
The purpose of the fuel reliability indicator is to monitor progress in achieving and maintaining high fuel integrity. Failed fuel represents a breach in the initial barrier for preventing offsite release of fission products. Such failure also has a detrimental effect on operations and increases the radiological hazards to plant workers.
The PG&E goal for 2006 was to ensure that the “corrected” coolant radioactivity due to potential fuel failures did not exceed 5xl0-4 microcuries per gram (mCi/g) of Iodine-131 in each unit. The goal for 2007 remains at 5xl0-4 mCi/g. For Unit 1, the measured performance indicator was 1x10-6 mCi/g for every month between July 1, 2006 and June 30, 2007. Thus, Unit 1 met the goal for all months of this reporting period.
The Unit 2 performance indicator for the second half of 2006 averaged 4.72x10-6 mCi/g, with a high monthly value of 2.33x10-5 mCi/g in December. Thus, Unit 2 also met the goal for all months of the second half of 2006.
However, for the first half of 2007, the Unit 2 performance indicator had an average value of 2.61x10-4 mCi/g , with a high monthly value of 5.69 x10-4 mCi/g for the month of June. Thus Unit 2 did not meet the goal for the second half of 2007.
Based on measurement of both steady-state reactor coolant activity and transient iodine spiking, PG&E determined that Unit 1 operated without any failed rods during the period from July 1, 2006 to June 30, 2007. In fact, Unit 1 has operated without any failed rods since the beginning of Cycle 5.
Based on the Unit 2, Cycle 14 RCS radiochemistry data, PG&E believes that a single fuel rod failed on December 14, 2006. In-mast sipping and ultrasonic inspection will be implemented during 2R14 (first half of 2008) to locate the failed rod to ensure it is not reinserted into Cycle 15.
PG&E continues to follow its fuel reliability programs, including the aggressive preventive maintenance inspection of new and irradiated fuel, continued implementation of procedural guidelines to prevent fuel damage during both power and refueling operations, implementation of chemistry controls, fuel assembly reconstitution for identified rod failures, tracking and disposition of damaged fuel assemblies and strict controls to exclude foreign material from the reactor coolant system.
2.1 Employee Concerns Program Statistics
The Employee Concerns Program (ECP) is an alternate resource (to management) for reporting concerns having nuclear quality or nuclear safety significance. This includes issues of harassment, intimidation, retaliation and discrimination (HIRD). This resource is available to all PG&E employees, contractors, and supplemental personnel that support activities for Nuclear Power Generation (NPG). The process is designed to offer the concerned individual anonymity without fear of retaliation.
The ECP receives concerns primarily from direct contact with concerned individuals or in the form of allegations referred to the ECP from the NRC. Below are statistics comparing past indicators with current activities.
| Item | 2004 | 2005 | 2006 | 2007 (as of 8/26) |
|---|---|---|---|---|
| NRC allegations | 4 | 5 | 3 | 2 |
| Referred allegations that ECP investigated | 1 | 1 | 3 | 1 |
| PG&E ECP concerns | 3 | 1 | 0 | 0 |
| Anonymous concerns (% of total) | 0% | 50% | 0% | 0% |
| HIRD concerns (% of total) | 66% | 50% | 0 | 0% |
The ECP staff is also contacted by individuals with issues that do not meet the established ECP criteria for full investigations. These issues are generally resolved through mediation, intervention, referral, or another means acceptable to the employee. ECP documents these “Employee Contacts” along with their resolution. For the period July 1, 2006 - June 30, 2007 there have been 35 Employee Contacts, compared with 41 for 2006.
The ECP staffing remained consistent with the level of investigative activity and continues to be staffed effectively with one lead investigator and one senior engineer.
2.2 Fitness for Duty
- The PG&E Fitness for Duty (FFD) Program testing of personnel for alcohol and drugs is divided into three categories:
- Random testing – targeted to perform an annual number of tests equal to or greater than 50% of the number of personnel
- Follow-up testing – required for three years for those who have previously tested positive for alcohol or drugs or those who have a record of drug or alcohol abuse prior to coming to DCPP
- For-cause testing as referred by DCPP management
PG&E has found that positive results of random testing have remained about the same for utility and contract employees during the past year. There was one positive random test during the period July 1, 2006 through June 30, 2007. In the past, the random positive rate for utility and contract employees has varied from year to year with an overall downward trend.
For follow-up testing, approximately 1-2% of those tests yield a positive indication of alcohol or drugs, which PG&E considers a relatively low number, considering the population being tested.
For-cause testing is dependent upon those specifically requested by supervision for testing and has varied from six positive indications out of 11 tested during 1996 to two positive indications out of seventeen tested through mid-2006. PG&E believes that this indicates that DCPP managers only refer people for testing as required under the Fitness For Duty program standards.
DCPP’s FFD program continues to identify individuals who are not fit for duty and individuals who violate the company FFD policies.