4.0 Summary of Major Review Topics, DCISC 15th Annual Report - July 1, 2004 thru June 30, 2005

4.15 System and Equipment Performance/Problems

4.15.1 Overview and Previous Activities

During past periods, the DCISC had reviewed the performance and problems of DCPP equipment and systems as well as the actions taken by PG&E to resolve them.

During the previous period (July 1, 2004 @ndash; June 30, 2005), the DCISC reviewed the following items:

There were no system reviews with System Engineers performed during the previous reporting period.

In previous period the DCISC concluded that DCPP has satisfactorily identified and corrected many of its equipment problems where they were self-revealing or obvious; however, during the previous reporting period, there have been lapses in promptly identifying significant problems. Aggressive changes have been made, including augmenting the Corrective Action Program and developing a Trouble-shooting Program.

PG&E had performed inspections of its reactor vessel head and bottom penetrations as required by NRC and has found no signs of leakage problems.

4.15.2 Current Period Activities

The DCISC reviewed the following system and equipment areas during the current reporting period:

RCS Elbow Tap Flow Measurement Implementation and Results

In July 2004 the DCISC met with Bill Bojduj, Senior Reactor Engineer, Reactor Engineering Group to review the status of the RCS elbow tap flow measurement implementation (Volume II, Exhibit D.1, Section 3.10). This is an improved method for measuring flow of high pressure water in a secondary system pipe. DCISC had reviewed this issue at previous Fact-finding Meetings and the purpose of this discussion was to get an update on the effectiveness of the new measurement method.

The NRC approved DCPP@rsquo;s License Amendment in August 2003. DCPP revised the procedures so that they could use the elbow tap method instead of flow calorimetric method in June 2004 for Unit 1 after restart coming out of 1R12 refueling outage. The elbow tap method was implemented on Unit 2 during 2R12 in the fall of 2004. Comparing Precision Flow Calorimetric and Elbow Tap Method for cycles 1 to 13 for each unit shows that the calorimetric method is more conservative then the Elbow Tap Method.

Using the existing Calorimetric method, DCPP was running out of flow margin. They could only go to about 12 steam generator tube plugging. With the Elbow Tap Method they would be allowed to go to 18 tube plugging on Unit 1 and 17 tube plugging on Unit 2.

The current Tech Spec limit is 15 tube plugging on any single unit. Westinghouse is working on a License Amendment to go to 25 tube plugging in any one steam generator and an average of 15 tube plugging for all steam generators.

The Elbow Tap method has been very effective with its implementation. DCPP will now be able to go to the 15 average tube plugging limit if necessary.

Outage 1R12 and 2R12 Intake Structure Inspections

The DCISC Fact-finding Team met in July 2004 with a Civil Engineer in Technical-Ecology Services, to review the 1R12 intake structure inspection (Volume II, Exhibit D.1, Section 3.11) and again in January 2005 on Unit 2 (Volume II, Exhibit D.6, Section 3.9). The DCISC has reviewed the intake structure inspections for each unit after Refueling Outage inspections. DCPP has a program that identifies the scope and tracks the inspection and repairs of the intake and discharge structures.

Unit 1

1R12 was the eighth comprehensive documented inspection of the Unit 1 submerged concrete. The inspection included visual inspection of concrete, determination of reinforced steel attributes, sounding for concrete delaminations, concrete chloride content and determination of electrical characteristics of the conduits, intake structure and discharge structure.

They have reduced inspections in the last two outages because they have not seen much corrosion growth (about 1/2). They are still doing visual inspections, but not hammer soundings. The cathodic protections (CP) previously installed have been effective in reducing reinforcing steel corrosion.

The general condition of the concrete in the cooling water channels (CWC) 1-1 and 1-2 is structurally sound. There has been about 0.5 percent growth of delaminations in both CWC@rsquo;s since the previous inspection (1R11). During the 1R7 outage, a cathodic protection system was installed to protect the reinforcing steel within the CWC@rsquo;s. Tests were performed during 1R12 on this CP system to verify system operation. The CP system is functioning as designed.

There are several areas on the common wall in both CWC@rsquo;s that meet the requirements for concrete in need of repair. These areas have been previously evaluated by Engineering since 1R7, and have been deferred to a future outage. Delaminations in these areas have not significantly grown in size from the previous inspection.

The general condition of the concrete in CWP Forebays 1-1 and 1-2 is structurally sound. During 1R10 outage, a CP system was installed on the north, south, and west walls of TSFB 1-1 to protect the reinforcing steel within the forebay. The overall condition of the concrete in TSFB@rsquo;s 1-2 through 1-6 is fair to poor (from 1R9 results). These forebays were only visually inspected during this outage due to limited accessibility. Poor means that Civil-Structural Engineering needs to look at structure for evaluation and be sure the second bar in the structure is OK.

There were several areas that were not inspected during this outage due to limited accessibility. No concrete repairs were performed during the 1R12 outage.

Unit 2

This was the ninth comprehensive inspection of the Unit 2 submerged concrete. In general the concrete areas under water are in excellent condition. The problems have been observed above the water level in the splash areas.

The general condition of the concrete water channels (CWC) 2-1 and 2-2 is structurally sound. According to the PG&E inspection results, there has been a minimal growth of delaminations in the CWCs since the previous inspection (2R11). A total of 416 square feet of delaminations were located in CWC 2-1. Of the 22,100 square feet of concrete tested (33 of total CWC surface area), 0.6 percent of the concrete surface is delaminated. A total of 843 square feet of delaminated area were located in CWC 2-2. Of the 20,700 square feet of concrete surface area tested (33 of total CWC surface area), 1.3 percent of the concrete surface is delaminated. The cathodic protection (CP) system installed during 2R7 outage in the CWCs to protect the reinforcing steel is functioning as designed.

The general condition of the concrete in CWC Forebays 2-1 and 2-2 is good. The two small delaminations (1/2 square foot each) found during 2R7 in CWC 2-1 have not changed in size. No repairs were necessary in CWC Forebay 2-1 and 2-1 during the 2R12 outage.

The general condition of the concrete in the Traveling Screen Forebay (TSFB) 2-1 through 2-5 appears to be good. TSFBs 2-1 through 2-5 were visually inspected from elevation -31.5 feet and no signs of spalling or increased cracking were found. TSFBs 2-1 through 205 were not sounded for delaminations due to limited accessibility.

The general condition of the concrete in TSFB 2-6 is regarded as poor. TSFB 2-6 was sounded for delaminations from the intermediate floor (-2.1 ft.) to an elevation of 12 feet. The total area of delaminations in TSFB 2-6 has grown 22 since being inspected during 2R11. Since 2R7 the growth of delaminations in TSFB 2-6 has almost tripled (266 growth) from 48 square feet to 176 square feet. No repairs were performed in the TSFBs during 2R12 outage due to budget limitations.

Repairs for the TSFB are being proposed in the budget for 2R13). If the repairs are not made in 2R13, then they must be made in 2R14 or DCPP will not be able to determine the capability of the structure. They are also starting to have delaminations and corrosion of the top surface of the intake structure and will need to have cathodic protection installed. Preparations are under way to do this.

The DCPP inspection program for the intake structure seems to be effective in identifying any problems.

It appears that the Unit 1 Cathodic Protection (CP) system installed during previous outages has been effective in protection of the reinforcing steel. It appears that the combined growth of delaminations has been very small from that of early years.

It appears that PG&E is doing a good job of inspection the intake structure, but seem to be delaying repairs because of budget. DCPP should be sure that they have the Engineering group evaluate the problems that they find and do not repair during the outage.

Review NCR 0002186 Pipe Break

In August 2004 the DCISC reviewed the pipe break on the CCW (Component Cooling Water) supply line to the upper bearing lube oil cooler on Reactor Coolant Pump 1-3 (Volume II, Exhibit D.2, Section 3.3). The leak was found by Operations when unidentified leakage was detected in the containment.

An AR was written identifying a leak in containment. A containment entry was made on that day which identified that a CCW water leak was occurring on the Reactor Cooling Pump (RCP) 1-3 upper bearing lube oil cooler (UBLOC) CCW piping. A second containment entry on that day by ISI identified that the leak was due to a crack on the CCW inlet piping nozzle on that UBLOC, and determined that it was a significant leak.

Design Engineering discussed this situation with OPS, including the Shift Manager in the discussion. A similar problem in 1998 was recalled, and the indications appeared similar. Engineering could not make an operability determination within the one hour Technical Specification limit, so the Shift Manager chose to enter T/S 3.0.3 and start a shutdown to Mode 3 at 1900 on 7-21-04. DCPP resumed full power on 7-24-04.

DCPP performed a complete metallurgical evaluation on the failed part. In addition to the macroscopic examination of the fractured channel, ultra-sonic testing and visual weld inspection of the weld and crack area were performed. These tests revealed that the visible evidence of crack arrest indicated that a number of events of higher-magnitude stress occurred early in the crack life.

Back in 1998 they had replaced the channel heads on four RCP@rsquo;s (including 1-3) with a new design. This time the crack on RCP 1-3 was in a different place. The RCP 1-3 was found to have higher vibrations than the other three RCP@rsquo;s on Unit 1 and the four RCP@rsquo;s on Unit 2.

The decision was made to repair the channel head on RCP 1-3, and DCPP also increased weld size at both the inlet and outlet piping. This was based on a determination that the cause of the crack was high-cycle fatigue. However, they are performing a root-cause-analysis on this event and monitoring its performance. They checked vibration on this RCP in July 2004 and it was not too high or alarming. They checked the other three RCP for Unit 1 and found no vibration problems. They instrumented the pipe on RCP 1-3 to collect future information. Inspection Services inspected the Unit 2 RCP and found no leaks. They will replace all the channel heads on the coolers during the 10-year inspection of the motors.

Upon discovery of a leak in containment, DCPP performed the required operability determination in a short time and shut down the plant to Mode 3, as required by tech specs. They have also taken the appropriate corrective action by replacing the cracked channel head, performed tests to determine cause of crack, and are monitoring performance and doing a root@ndash;cause analysis to gain more information about the crack.

Review NCR N0002170 Diesel Generator (DG) Exhaust Supports

The DCISC met with the Lead System Engineer in August 2004 and heard a presentation at its February 16-17, 2005 Public Meeting to discuss NCR N0002170 on the Diesel Generator (DG) exhaust supports issue (Volume II, Exhibit D.2, Section 3.10 and Exhibit B.6).

On March 1, 2003, it was discovered that a DG exhaust stack slide bearing had fallen off the exhaust stack structure located in the ceiling of the Unit 1 side of the turbine building. The Design Engineering organization performed an analysis of this degraded condition and, based on the perceived margin loss of a single pipe support, reported to the Shift Manager that the DG exhaust stack would perform its intended design function. Both the initial degraded condition and the subsequent operability call were appropriately documented in an Action Request (AR).

Over the next seven months, information became available to the Design Engineering organization that clearly indicated that the DG exhaust stack slide bearings were not in accordance with plant design basis, specifically:

Design Engineering personnel failed to recognize the broader implications presented by this new and changing information, and therefore failed to document this information in the Corrective Action Program failed to inform Operations, and did not track this work to its completion.

DCPP performed a cause analysis to determine the causes and recommend corrective actions to prevent recurrence of the issues uncovered by this event.

The causes of this event were:

  1. Failure of the DG exhaust stack support bearing was caused by:
  1. The failures of the Design Engineering organization to document new information concerning the DG exhaust stack slide bearings in the Corrective Action Program as required by OM7.ID1, can be attributed to an apparent mismatch between procedural requirements and the Design Engineering department management/cultural expectations concerning the reporting of problems into the Corrective Action Program.
  2. The failures of the Design Engineering organization to communicate new information concerning the DG exhaust stack slide bearings to Operations as required by OM7.ID 12 can, in part, be attributed to an apparent knowledge deficiency regarding operability requirements and their bases. The evidence is not conclusive, but it is possible that this knowledge deficiency could be found in other functions of the Engineering organization.

The following corrective actions are being taken to prevent recurrence of issues like this:

  1. Increased management attention and expectation-setting is being implemented with the Design Engineering group regarding their use of the Corrective Action Program. The DCPP Human Performance group will work with station Leadership to address any cultural or organization issues in the Design Engineering group.
  2. Provide training on the requirements of, and bases for OM7.ID12. This training should include NRC GL 91-18 rev. 1 “Operability Requirements@rdquo;, and lessons learned from this NCR. This training should be provided (as a minimum) to all Professional Engineers, Design Engineers, and active SRO@rsquo;s.
  3. No additional corrective action is necessary to prevent recurrence for the failed slide bearings. These bearings were replaced with solid metal slide bearings that will not be subject to the failure exhibited by the Fluorogold slide bearings. Although there are other slide bearings of this design in the plant, none of them are installed in a configuration similar to those in the DG exhaust stack supports.

The Cause Analysis NCR N0002170 “untimely identification of extent of degraded condition of Unit 1 Diesel Generator (DG) exhaust supports, which was contrary to 10CFR50 Appendix B, Criterion XVI@rdquo; was a very thorough analysis and detailed all of the problems and corrective actions. Mr. Shoulders stated that if DCPP had written a PAO in March, 2004, they would have recognized the issues and been timelier in their response.

DCPP Design Engineering did not handle the Diesel Generator (DG) 1-2 degraded exhaust supports problem or final operability determination in a timely manner. The root cause analysis was a very through one and determined the causes and identified the corrective action necessary.

Outage 2R12 Reactor Head and Bottom Inspections

In January 2005 the DCISC met with the In-Service Inspection (ISI) Supervisor to review the results of the 2R12 reactor head and vessel bottom inspections (Volume II, Exhibit D.6, Section 3.2). This item has been reviewed at past Fact-finding and Public Meetings, most recently at the DCISC February 16-17, 2005 Public Meeting (Volume II, Exhibit B.6). The purpose of this meeting was to receive an update on these inspections.

NRC order EA-03-009 (revised February 2004) listed specified inspection requirements for reactor heads at PWR@rsquo;s. The susceptibility categories are determined by a formula that considers reactor vessel head temperature at 100 power and the number of operating years. This formula yields Effective Degradation Years (EDY). DCPP Unit 2 reaches 12 EDY, which is in the “High Sensitivity@rdquo; category, and therefore requires volumetric inspection in 1R12.

The volumetric Exam Results were:

PG&E will have to perform volumetric inspection on both units at all future refueling outages. Some US plants are replacing their reactor heads rather than inspecting during all refueling outages. An ASME code case is being prepared, which if accepted, would no longer require volumetric inspection at each outage if it can be determined that the head condition is safe enough to permit operation until the next outage before inspection.

The reactor vessel top head bare metal visual inspection was conducted with the robotic crawler. This allows a 360-degree examination around all tubes and complete base metal inspection. No indications of pressure boundary leakage were found. Slight staining from old boric acid or water spills was visible on some tubes and was determined to be inactive.

DCPP also conducted, for the first time for Unit 2, a robotic exam of bottom-mounted instrumentation penetration areas of 58 1-1/2 inch diameter tubes. They used modified robotic crawler with a pan, tilt and zoom camera. They examined all tubes and did not find any indication of pressure boundary leakage. Some slight boric acid trails from previous cavity seal leakage were found. No other plants, except South Texas, have found any problems on the bottom head.

PG&E is taking appropriate action to perform the required inspections of reactor top heads and bottom heads to meet NRC requirements. Outage 2R12 inspections revealed no problems.

ECCS Voids Status

An update on Emergency Core Cooling System (ECCS) voids was reviewed at the April 6-7, 2005 Fact-finding meeting (Volume II, Exhibit D.8, Section 3.8) and at the June 1-2, 2005 Public Meeting (Volume II, Exhibit B.9) The DCISC met with Anderson Lin, Principal Engineer in the System Transient Analysis Group. The DCISC last reviewed this subject in the late 1990s.

Gas accumulation or voiding in high-points of ECCS piping is a concern due to the potential to render ECCS pumps inoperable during certain design basis accidents. Gases accumulate when introduced during maintenance, and by coming out of solution in a system. In 1997 NRC issued an information notice (and multiple supplements) regarding voids, and INPO issued Significant Operating Experience Report (SOER) 97-1 “Potential Loss of High Pressure Injection and Charging Capability from Gas Intrusion@rdquo; on ECCS voiding; and a new SOER is expected.

When the DCISC reviewed DCPP voiding in the late 1990s, it believed PG&E had taken appropriate action to solve the problem caused by degassing occurring in the chemical and volume control system letdown orifice. Actions consisted primarily of careful filling and venting during restart from outages and the addition of specific high-point vents to eliminate accumulated voids. Periodically, systematic ultrasonic testing (UT) was used to detect and monitor high-point voids, and finally, continuous void monitoring was employed.

In 2004 Palo Verde experienced a large bubble in the Residual Heat Removal (RHR) System which was initially determined to render the system inoperable (but it was later determined through testing to have been operable). DCPP has performed scale-model testing and plans to run an actual charging pump test to determine the effects of voiding.

Gas voids in the suction piping of the ECCS have been a recurrent and elusive problem at DCPP and other nuclear plants. In the most recent events, during the second half of 2004, Units 1 and 2 experienced five unexpected voids at the crosstie between the Centrifugal Charging Pump (CCP) and the Safety Injection Pump (SIP) suction lines.

Investigation by a Root Cause Analysis (RCA) Team identified the phenomena that created the gas source, where during normal system operation, gases come out of solution in the RCP seals due to the large acceleration, pressure drop, and pressure recovery that occur in the RCP seal labyrinth and result in localized pressures below the gas saturation pressure. Additionally, H2 dissolved in the Volume Control Tank (VCT) may degas at process pressures lower or temperatures higher than that of the VCT, contributing to void formation. The Team investigated many potential mechanisms for the unexpected voids formation. They utilized both Fault Tree Analysis and Event and Causal Factors approaches to narrow down the causes. The DCISC considers their analysis to be noteworthy in identifying the root causes of the problem, and in particular in identifying the RCP seals as a source of gas. They also determined that the reason no sizeable voids formed from 1999 through mid-2004 was because of the way the PDPs and CCPs were operated for normal charging and swapping.

The DCPP Team determined that there were several earlier missed opportunities to identify the actual root causes of the void problems. Basically, two previous efforts identified some, but not all gas sources. They therefore stopped short of the actual root cause or didn@rsquo;t go far enough in corrective actions, including failure to recognize and take advantage of an applicable industry event at Catawba Nuclear Station.

The root causes were determined to be inadequate piping configurations, due to design flaws, which caused the void accumulations. Specifically, the design flaws were as follows:

The root cause analysis was thorough and comprehensive. Two corrective actions recommended to prevent recurrence and address the root cause were:

  1. Revision of the Design Change Procedure to require the proper evaluation and correction of any void issue during the design change process
  2. Implementation of a piping design modification that would prevent accumulation of voids at the connection to the CCPs suction header.

It was also recommended that the PDP be replaced with a different type of pump with a continuous recirculation flow to minimize void collection. It was recognized that recirculation line check valves normally exhibit back leakage and that pump swaps are an operational/testing necessity, and no changes were recommended. Interim temporary modifications and operational procedure changes were put in place until the permanent corrective actions are complete.

DCPP developed an Effectiveness Evaluation Plan to test the effectiveness of the corrective actions. The Plan consists of performing Surveillance Procedure STM M-89 “ECCS System Venting@rdquo; each month (and at prescribes modes of operation) for one year to verify whether the Units 1 and 2 ECCS are full of water.

Following a thorough, comprehensive root cause analysis and implementation of resulting corrective actions, DCPP appears to have solved ECCS piping void problems which have plagued it since 1997. This involved noteworthy detective work to identify the root-cause source of degassing in the RCP seals. Its one-year evaluation and monitoring plan will determine the effectiveness of the solutions. The DCISC will closely follow this issue.

Review of 230 and 500 kV Systems with System Engineer

The DCISC met in the May 3-4, 2005 Fact-finding meeting with Engineer for the 230 and 500 kV Systems, to review the system design, operation and health and to tour on-site portions of the systems (Volume II, Exhibit D.10, Section 3.2). The 230 kV line provides emergency off-site electrical power to DCPP from three sources. The 500 kV lines are the pathway for power out of the plant as well as back-up emergency power.

The Fact-finding Team took a driving tour with the System Engineer of the on-site portions of the two systems. This included the lines coming in from off-site, 230 and 500 kV switchyards, and points of entry of the lines into the plant. The Team toured the 500 kV Control Room which is separate from the main plant. Transmission System Department Operators and Maintenance Technicians here work in coordination with DCPP Plant Operators on operations, maintenance and outages.

Although operated by the Transmission Department, operation of these systems is governed by a DCPP procedure which controls and specifies DCPP operability conditions and configurations for both the 230 and 500 kV systems. Additionally, the procedure contains:

DCPP controls breakers and other components which are important to the nuclear plant according to the NRC Maintenance Rule. Responsibilities for various components and portions of these systems are contained in a procedure specifying boundaries of jurisdiction for Transmission and Distribution facilities. The System Engineer believed coordination between DCPP Operations and the Switchyard Operators was good. Transmission Department Switchyard Technicians must be qualified to DCPP requirements and work under a DCPP project manager or supervisor in accordance with DCPP@rsquo;s Contractor Oversight Procedure.

STARS plans to perform a self-assessment of the switchyard and its interfaces with the plant in July 2005, and INPO plans to evaluate switchyard/plant interfaces during its next evaluation. The DCISC plans to review both of these evaluations with DCPP.

The DCISC Fact-finding Team understood that the quality oversight for Transmission Department work in the DCPP switchyard is that performed periodically by the System Engineer (SE). The DCISC also understands that changes in the SE Program will make the SE less responsible for day-to-day oversight of modifications and maintenance of his/her systems. The DCISC believes that this may lead to a lapse in quality oversight and recommends this situation be reviewed in the STARS self-assessment.

The DCISC Fact-finding Team received and reviewed the system health cards for each system. Both systems@rsquo; health was Green. See Volume II, Exhibit D.10, Section 3.2 for a detailed description of the contents of the health cards.

The 230 and 500 kV systems appear to be in good health, and the System Engineer appears to be knowledgeable of the systems and on top of trends and issues. It appears that quality oversight of switchyard work is performed only periodically by the System Engineer. This is a concern to the DCISC.

Recommendation:
DCPP@rsquo;s July 2005 STARS self-assessment should include a review of the quality oversight of switchyard work by DCPP and non-DCPP (e.g., PG&E Transmission Department) personnel.
Basis for Recommendation:
The DCISC understands that currently the only quality oversight applied to DCPP switchyard work is that performed periodically by the System Engineer. That, in itself, appears marginal. Also, in general, System Engineers@rsquo; responsibilities are changing to focus more on engineering and less on oversight of maintenance and modification work, thus possibly reducing the current “periodic@rdquo; quality oversight of switchyard work.

4.15.3 Conclusions and Recommendations

Conclusion:
In the past DCPP has satisfactorily identified and corrected many of its system and equipment problems; however, during the reporting period, there have been lapses in promptly identifying significant problems. Aggressive changes have been made, including augmenting the Corrective Action Program and developing a Trouble-shooting Program. In one example of an industry-wide issue, PG&E has performed inspections of its reactor vessel head and bottom penetrations as required by NRC and had found no signs of leakage problems. The DCISC will continue to follow these initiatives.PG&E has performed inspections of its reactor vessel head and bottom penetrations as required by NRC and has found no signs of leakage problems.

PG&E Response to Recommendations

R05-4
DCPP@rsquo;s July 2005 STARS self-assessment should include a review of the quality oversight of switchyard work by DCPP and non-DCPP (e.g., PG&E Transmission Department) personnel. (Note: this recommendation was provided to PG&E during the DCISC June 1-2, 2005 Public Meeting).

DCPP, in conjunction with its Strategic Teaming and Resource Sharing (STARS) partners, performed a self-assessment covering large power transformers and switchyards. The self-assessment was performed during the week of August 29, 2005, and included participation from the industry to aid in the self-assessment. The assessment was patterned after an industry document, “Guidance for Performing Reviews on Large Power Transformers and Switchyards (Revision 0, 2005),@rdquo; and covered all the topics in the guidance document. The STARS, DCPP, and other industry participants interviewed PG&E@rsquo;s Transmission Operations, Transmission Maintenance organizations, and DCPP staff. The assessment team also reviewed DCPP procedures that address the maintenance activities associated with the switchyard.

The assessment team made 13 recommendations in total. Of the 13, two recommendations related to enhancing the quality of switchyard maintenance and quality of DCPP oversight of switchyard maintenance. DCPP is overseeing the resolution of both issues, along with the other recommendations.

DCPP controls the maintenance activities in both the 500kV and 230kV switchyards through the use of procedure AD7.ID6, “Nuclear Generation/ Supplemental Personnel Interface.@rdquo; This applies to the Transmission Line Department, Substation Construction, and Substation Maintenance organizations of PG&E. DCPP maintenance conducts an onsite briefing before work starts, and discusses key objectives and concerns/risks with individuals prior to them performing any work at Diablo Canyon. Switchyard maintenance activities are tracked using DCPP@rsquo;s scheduling tools, and associated risk activities are factored into the overall plant scheduling review. During Unit 1 Refueling Outage 13, a DCPP maintenance assistant team leader was located at the switchyard on a daily basis during maintenance activities to ensure that DCPP expectations were met.

In summary, the assessment team concluded that there are appropriate controls built into the switchyard maintenance activities for Diablo Canyon and provided recommendations to enhance the quality oversight of switchyard work

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