IR 05000275/2013004
| ML13305B078 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 11/01/2013 |
| From: | O'Keefe N NRC/RGN-IV/DRP/RPB-B |
| To: | Halpin E Pacific Gas & Electric Co |
| References | |
| EA-12 238 IR-13-004 | |
| Download: ML13305B078 (55) | |
Text
U NIT E D S TATE S NUC LEAR RE GULATOR Y C OM MI S SI ON ber 1, 2013
SUBJECT:
DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000275/2013004 and 05000323/2013004
Dear Mr. Halpin:
On September 20, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Diablo Canyon Power Plant Units 1 and 2. On October 10, 2013, the NRC inspectors discussed the results of this inspection with you and members of your staff.
Inspectors documented the results of this inspection in the enclosed inspection report.
The NRC inspectors documented two findings of very low safety significance (Green) in this report. These findings involved violations of the NRC requirements.
If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Diablo Canyon Power Plant.
If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the Diablo Canyon Power Plant.
In accordance with Title 10 of the Code of Federal Regulations (10CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Neil F. OKeefe, Branch Chief Project Branch B Division of Reactor Projects Docket Nos.: 05000275, 05000323 License Nos: DPR-80, DPR-82 Enclosure: Inspection Report 05000275/2013004 and 05000323/2013004 w/Attachments: Supplemental Information Electronic Distribution for Diablo Canyon
SUMMARY OF FINDINGS
IR 05000275/2013004, 05000323/2013004; 07/01/2013 - 09/20/2013; Diablo Canyon Power
Plant, Integrated Resident and Regional Report; Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion.
The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Two Green non-cited violations of significance were identified. The significance of most findings is indicated by their color (Green, White,
Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.
The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross-Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after the NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
NRC-Identified Findings and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green.
The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, after the licensee performed corrective maintenance on a diesel fuel oil system leak without appropriate documentation or procedures. This resulted in the fuel oil header not being properly primed or vented, which rendered an emergency diesel generator inoperable. The licensee entered the condition into the corrective action program as Notification 50561918.
The failure to use procedures to perform corrective maintenance on an emergency diesel generator was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating Systems Screening Questions, this finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, was not a loss of the system or function, and did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time. The finding had a cross-cutting aspect in the area of human performance, associated with the work practices component, because licensee staff did not communicate human error prevention techniques, such as proper documentation of activities, and did not use this technique commensurate with the risk of the assigned task, such that work activities are performed safely. Specifically, the system engineer recognized the possibility of introducing air into the system, but assumed that operators would have filled and vented the system using the appropriate procedure, while operators did not use a procedure to tighten the leaking fitting and refill the priming tank H.4(a). (Section 4OA2.3)
- Green.
The inspectors reviewed a self-revealing non-cited violation 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with troubleshooting of the Unit 2, 4kV bus G that resulted in an unplanned de-energization.
This caused an unplanned entry into a 72-hour shutdown technical specification action statement due to diesel fuel oil transfer pump 0-2 becoming unavailable. The licensee entered the condition into the corrective action program as Notification 50544198.
The failure to plan and coordinate emergent maintenance such that it would not impact other mitigating systems was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and is therefore a finding. This finding was evaluated for each unit separately. For Unit 1, which was at power, using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating Systems Screening Questions, this finding was determined to be of very low safety significance (Green) because, it was not a design or qualification deficiency, was not a loss of the system or function, and did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time. For Unit 2 this finding did not require evaluation using Inspection Manual Chapter 0609, and Appendix G because the unit was defueled. The finding had a cross-cutting aspect in the area of human performance, work practices component, because workers failed to use multiple human error prevention techniques H.4(a).
(Section 4OA3.2)
Licensee-Identified Violations
None.
PLANT STATUS
At the beginning of the inspection period, Unit 1 was shutdown to repair a cracked weld in the residual heat removal (RHR) system. Unit 2 was operating at full power.
On July 2, 2013, repairs to the Unit 1 residual heat removal system were completed and plant operators performed a reactor startup. Unit 1 returned the unit to full power on July 3, 2013.
On July 10, 2013, Unit 2 experienced a reactor trip due to an electrical fault in the main transformer bank. On July 13, equipment repairs were completed, and plant operators performed a reactor startup. Unit 2 returned to full power operation on July 16, 2013.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity, and Emergency Preparedness
1R01 Adverse Weather Protection
.1 Summer Readiness for Offsite and Alternate AC Power Systems
a. Inspection Scope
The inspectors reviewed the licensees preparations for seasonal high grid loading. The inspectors reviewed the licensees procedures and communications protocols to ensure that they included measures to monitor and maintain availability and reliability of both the offsite and alternate-ac power systems.
The inspectors performed a walkdown of the switchyard with plant personnel to observe the material condition of offsite power sources. The inspectors reviewed the Final Safety Analysis Report Update and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by procedures. The inspectors reviews focused on the following systems:
- July 1-12, 2013, 12kV onsite, 230kV and 500kV offsite power systems The inspectors also reviewed corrective action program items to verify that the licensee was identifying summer readiness issues at an appropriate threshold and entering them into its corrective action program for resolution. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one sample to evaluate the readiness of offsite and alternate-ac power for summer weather, as defined in Inspection Procedure 71111.01-05.
b. Findings
No findings were identified.
.2 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors reviewed the licensees adverse weather procedures for seasonal marine conditions and evaluated the licensees implementation of these procedures. The inspectors verified that prior to the onset of marine environment impacts, the licensee corrected marine environment related equipment deficiencies identified during the previous occurrences.
The inspectors reviewed plant design features and the procedures used by plant personnel to mitigate or respond to adverse conditions. The inspectors verified that operator actions specified in these procedures maintained readiness of essential equipment and systems to preclude environment induced initiating events. The inspectors reviewed the Final Safety Analysis Report Update and the performance requirements for selected systems to ensure that selected system components would reasonably remain functional if challenged by an adverse environment. The inspectors reviews focused specifically on the following plant systems:
- The inspectors walked down, inspected, and reviewed preventive and corrective maintenance activities on the intake area, service water and circulating water systems to address salp, kelp and other marine conditions during the period August 5 through August 23, 2013 The inspectors also reviewed corrective action program items to verify that the licensee was identifying adverse environment issues at an appropriate threshold and entering them into its corrective action program for resolution. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one sample to evaluate the readiness for seasonal adverse weather, as defined in Inspection Procedure 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant systems:
- July 10, 2013, Unit 2, motor-driven auxiliary feedwater system
- July 10, 2013, Unit 2, 230kV and 4kV systems
- July 29, 2013, Unit 1, high pressure charging system
- August 1, 2013, Unit 2, component cooling water system The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected, while considering out of service time, inoperable or degraded conditions, recent system outages, and maintenance, modification, and testing. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Final Safety Analysis Report Update, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four partial system walkdown samples.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Quarterly Fire Inspection Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- July 10, 2013, Fire Area 3-T-2, Unit 2, motor-driven auxiliary feedwater pump room
- July 18, 2013, Fire Zone 3-Q-1, Unit 1, turbine-driven auxiliary feedwater pump room
- August 8, 2013, Fire Area 6-B-4, Unit 2, rod control room
- August 16, 2013, Fire Area TB-5 , Unit 1, 4.16-kV switchgear room, F bus The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition and verified that adequate compensatory measures were put in place by the licensee for out of service, degraded, or inoperable fire protection equipment systems or features. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four quarterly fire-protection inspection samples, as defined in Inspection Procedure 71111.05-05.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed licensee programs to verify heat exchanger performance and operability for the following heat exchangers:
- Residual Heat Removal Heat Exchangers (RHR HX 2-1, RHR HX 2-2)
- Safety Injection Pump Lube Oil and Seal Water Coolers (2-2, 2-2A/B, 2-1, 2-1A/B)
- Spent Fuel Pit Heat Exchanger (HX 2-1)
- Auxiliary Salt Water System as it relates to the other samples The inspectors verified whether testing, inspection, maintenance, and chemistry control programs are adequate to ensure proper heat transfer. The inspectors verified that the periodic testing and monitoring methods, as outlined in commitments to the NRC Generic Letter 89-13, utilized proper industry heat exchanger guidance. Additionally, the inspectors verified that the licensees chemistry program ensured that biological fouling was properly controlled between tests. The inspectors reviewed previous maintenance records of the heat exchangers to verify that the licensees heat exchanger inspections adequately addressed structural integrity and cleanliness of their tubes. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five triennial heat sink inspection samples as defined in Inspection Procedure 71111.07-05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
.1 Quarterly Review of Licensed Operator Requalification Program
a. Inspection Scope
On July 19, 2013, the inspectors observed a crew of licensed operators in the plants simulator during training. The inspectors assessed the following areas:
- Licensed operator performance
- The ability of the licensee to administer the evaluations and the quality of the training provided
- The quality of post-scenario critiques These activities constitute completion of one quarterly licensed operator requalification program sample(s), as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.2 Quarterly Observation of Licensed Operator Performance
a. Inspection Scope
The inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity. The inspectors observed the operators performance of the following activities:
- July 2, 2013, Unit 1, startup, including the pre-job brief
- July 10, 2013, Unit 2, reactor trip
- July 15-16, 2013, Unit 2, power ascension In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure and other operations department policies.
These activities constitute completion of three quarterly licensed-operator performance samples, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk significant systems:
- June 27, 2013, Unit 1, containment particulate radiation monitor failure.
Notification 50570880
- July 15, 2013, Unit 2, 230kV system maintenance resulting in flashover.
Notification 50573100
- August 8, 2013, Unit 2, rod control urgent failure during surveillance testing.
Notification 50577272
- August 28, 2013, Unit 2, safety injection exceeded unavailability performance criteria. Notification 50569582 The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
- Implementing appropriate work practices
- Identifying and addressing common cause failures
- Scoping of systems in accordance with 10 CFR 50.65(b)
- Characterizing system reliability issues for performance monitoring
- Charging unavailability for performance monitoring
- Trending key parameters for condition monitoring
- Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)
- Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were appropriately handled by a screening and identification process and that issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four maintenance effectiveness samples, as defined in Inspection Procedure 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:
- July 8, 2013, Units 1 and 2, risk assessment of Morro Bay 230kV configuration
- August 5, 2013, Units 1 and 2, risk assessment of intake bubble curtain deployment
- August 8, 2013, Unit 2, risk assessment of rod control urgent failure alarm
- August 18, 2013, Unit 1, risk assessment for failure of startup transformer 1-1 The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed the following assessments:
- July 1, 2013, Unit 1, Notification 50571052, crack on sockolet weld on RHR-1-RV-8708
- July 3, 2013, Unit 2, Notification 50571934, auxiliary saltwater pump 2-1 dark oil sample
- July 8, 2013, Unit 1, Notification 50571886, reactor coolant pump 1-2 vibration alarms
- August 8, 2013, Unit 2, Notification 50577272, rod control urgent failure alarm
- August 14, 2013, Unit 1, Order 60060222, removal of loop 3 Th input to the reactor vessel level indicating system
- August 23, 2013, Unit 1, Notification 50561918, slow start of emergency diesel generator 1-1 following fuel oil leak
- September 3, 2013, Unit 1, Notification 50570582, operators placed all three diesels in manual simultaneously causing unplanned entry into technical specification shutdown actions The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems along with other factors, such as engineering analysis and judgment, operating experience, and performance history. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Final Safety Analysis Report Update to the licensees evaluations to determine whether the components or systems were operable.
Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of seven operability evaluation inspection samples, as defined in Inspection Procedure 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications:
- Installation of alternate circuit wiring in plant operating vent panel
- Removal of loop 3 Th input to the reactor vessel level indicating system The inspectors reviewed the temporary modification and the associated safety-evaluation screening against the system design bases documentation, including the Final Safety Analysis Report Update and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.
These activities constitute completion of two samples for temporary plant modifications, as defined in Inspection Procedure 71111.18-05.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
- July 1, 2013, Unit 1, post-maintenance testing of RHR-1-RV-8708 sockolet weld repair, Work Order
- July, 30, 2013, Unit 2, post-maintenance testing of centrifugal charging pump 2-1
- July 31, 2013, Unit 1, post-maintenance testing of component cooling water pump 1-1
- August 29, 2013, Unit 1, post-maintenance testing of component cooling water heat exchanger 1-1 The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):
- The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed
- Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the Final Safety Analysis Report Update, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19-05.
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
During the Unit 1 unplanned outage conducted from June 26, 2013 to July 2, 2013; and the Unit 2 unplanned outage from July 10, 2013 to July 16, 2013, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.
- Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.
- Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.
- Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.
- Monitoring of decay heat removal processes, systems, and components.
- Controls over activities that could affect reactivity.
- Startup and ascension to full power operation.
- Management of fatigue
- Licensee identification and resolution of problems related to forced outage activities.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two other outage inspection samples, as defined in Inspection Procedure 71111.20-05.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors selected risk-significant surveillance activities based on risk information and reviewed the Final Safety Analysis Report Update, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:
- Preconditioning
- Evaluation of testing impact on the plant
- Acceptance criteria
- Test equipment
- Procedures
- Jumper/lifted lead controls
- Test data
- Testing frequency and method demonstrated technical specification operability
- Test equipment removal
- Restoration of plant systems
- Fulfillment of American Society of Mechanical Engineers Code requirements
- Updating of performance indicator data
- Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct
- Reference setting data
- Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.
- July 3, 2013, Unit 2, reactor coolant system leakage trending
- August 8, 2013, Unit 2, rod control operability
- August 16, 2013, Unit 2, reactor trip breaker response time test
- August 26, 2013, Unit 1, Emergency diesel generator 1-3 engine analysis and visual inspections Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four surveillance testing inspection samples, as defined in Inspection Procedure 71111.22-05.
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)
a. Inspection Scope
The Nuclear Security and Incident Response (NSIR) headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML13247A168 as listed in the Attachment.
The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.
These activities constitute completion of two samples as defined in Inspection Procedure 71114.04-05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on August 14, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.
These activities constitute completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06-05.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety.
2RS2 Occupational ALARA Planning and Controls
a. Inspection Scope
This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel and reviewed the following items:
- Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements
- ALARA work activity evaluations/post-job reviews, exposure estimates, and exposure mitigation requirements
- The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies
- Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry
- Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas
- Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.
b. Findings
No findings were identified.
2RS4 Occupational Dose Assessment
a. Inspection Scope
This area was inspected to:
- (1) determine the accuracy and operability of personal monitoring equipment;
- (2) determine the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent; and
- (3) ensure occupational dose is appropriately monitored. The inspector used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspector interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:
- External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters
- The technical competency and adequacy of the licensees internal dosimetry program
- Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment
- Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Mitigating Systems Performance Index - Heat Removal System (MS08)
a. Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for Diablo Canyon Units 1 and 2 for the period from the second quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of two mitigating systems performance index heat removal system samples as defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
.2 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)
a. Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for Diablo Canyon Units 1 and 2 for the period from the second quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of two mitigating systems performance index residual heat removal system samples as defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
.3 Mitigating Systems Performance Index - Cooling Water Systems (MS10)
a. Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for Diablo Canyon Units 1 and 2 for the period from the second quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.
The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of two mitigating systems performance index -
cooling water system samples, as defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.
These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.
The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings were identified.
.3 Selected Issue Follow-up Inspection
a. Inspection Scope
During a review of items entered in the licensees corrective action program, the inspectors reviewed a corrective action item documenting a slow start of emergency diesel generator 1-1 following inadequate recovery from a fuel oil leak. The inspectors reviewed the licensees apparent cause analysis, applicable station procedures, and also interviewed key personnel involved.
These activities constitute completion of one in-depth problem identification and resolution sample, as defined in Inspection Procedure 71152-05.
b. Findings
Introduction.
The inspectors reviewed a Green self-revealing non-cited violation (NCV)of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, after the licensee performed corrective maintenance on a diesel fuel oil system leak without appropriate documentation or procedures. This resulted in the fuel oil header not being properly primed or vented, which rendered an emergency diesel generator inoperable.
Description.
On April 24, 2013, at 9:50 a.m., an operator discovered a fuel oil leak on emergency diesel generator (EDG) 1-1 at the fitting for the primary filter selector valve.
The fitting had been disconnected in accordance with an approved work procedure two days previously during a scheduled maintenance outage. At the conclusion of maintenance, the fitting had been tightened in accordance with the work procedure, and EDG 1-1 was started and ran satisfactorily with no fuel oil leaks observed. The diesel was declared operable at 6:58 p.m. on April 23, 2013, following this test run.
Engineering personnel subsequently concluded that the fitting most likely became loose due to vibrations during the test run, but did not begin to leak fuel oil until several hours later as the internal metal components cooled to ambient temperature.
Upon discovery of the leak, operations staff immediately tightened the fitting, which stopped the leak. The operators noted that the diesel fuel oil priming tank level was low and refilled the tank. The operations shift manager completed an operability determination and concluded that the diesel was operable because no degraded or non-conforming condition existed after tightening the fitting to stop the leak.
Operations contacted engineering and maintenance personnel to inform them of the leak. The operations shift manager, the EDG system engineer, and a maintenance foreman met in the diesel room while operations personnel were cleaning up the fuel oil leak area. At the time of this meeting, the leaky fitting had already been tightened and the priming tank refilled. Neither the maintenance foreman nor the system engineer advocated for developing a work package to address the situation.
The system engineer knew there was a possibility that the fuel oil leak could have drained fuel not only from the priming tank, which was clearly visible, but also from the fuel injection header, which could leave voids in the header that are not apparent by a visual external inspection. However, the system engineer did not verbalize this concern because she assumed that operators would have used station procedure STP M-21-RTS.1, Return Diesel Engine to Service Following Outage Maintenance, Revision 12, when refilling the priming tank. This procedure gives detailed instructions for ensuring the priming tank is full and then ensuring the entire fuel oil system is filled and vented. This procedure accomplishes this by specifying use of a manual hand pump as well as venting the system at an installed hose fitting. This procedure, or portions of it, would have been appropriate when returning the fuel oil system to service and ensuring the diesel generator was in a standby condition. Meanwhile, the operations shift manager did not recognize that the fuel oil system is vulnerable to void formation after a leak, so he believed the situation was adequately addressed by stopping the leak and refilling the priming tank.
Station procedure MA1.DC54, Conduct of Maintenance, Revision 2, stated that all work on plant systems, structures, or components (SSCs) should be performed using appropriate documentation such as work orders, notifications, procedures, or design drawings. Contrary to this, the operators tightened the fitting and refilled the fuel oil priming tank without any documentation. Station Procedure MA1.DC54 further stated that maintenance personnel shall thoroughly test equipment to ensure component and system operability prior to returning a component to service. Contrary to this, no test was performed on the diesel engine to ensure operability. In addition, station procedure MA1.DC54 explicitly defined toolpouch work, which would not require a procedure, as work on non-plant equipment as well as work specified on a pre-determined toolpouch list. An emergency diesel generator is not non-plant equipment, nor is it listed on the MA1.DC54 toolpouch list.
Station procedure OP1.DC10, Conduct of Operations, Revision 37, stated that operating plant components shall be per written guidance which maintains plant status control. This procedure also provided guidance for situations when procedure use is not required, stating: Each operator shall act per their judgment whenever time critical action is necessary to: prevent injury to personnel, mitigate a plant transient, prevent damage to property, or maintain service of critical equipment. Licensee leadership staff determined, upon review of the event, that since the leak was characterized as 40-50 drops per minute, it was not an immediate hazard; therefore, taking immediate action to tighten the fitting without a procedure was not appropriate.
On April 26, 2013, EDG 1-1 was started for a scheduled biannual test run. The starting times were observed to be in excess of the technical specification surveillance requirements for an emergency diesel generator to start and reach normal speed to be ready to assume required loading. The EDG system engineer noted that the initial start conditions resembled those when air is trapped in the fuel oil header, and she recommended performing an additional start to verify the header was fully primed.
Operations performed a successful hot restart of EDG 1-1, including meeting all the timing requirements of technical specification surveillance requirements, as part of the biannual test run on April 27, 2013. The licensee subsequently concluded that EDG 1-1 had been inoperable for approximately 74 hours8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br /> during the period from April 24, 2013, when the fuel oil leak was discovered, until successful performance of the hot restart on April 27, 2013.
The inspectors noted that EDG 1-1 could have been inoperable for as many as 15 additional hours, depending on when the fitting had cooled down sufficiently to begin leaking following the test run on the evening of April 23, 2013. Accounting for this possibility, the total time EDG 1-1 was inoperable could have been as long as 89 hours0.00103 days <br />0.0247 hours <br />1.471561e-4 weeks <br />3.38645e-5 months <br />.
However, this still would have been within the technical specification allowed outage time of 14 days.
Analysis.
The failure to use procedures to perform corrective maintenance on an emergency diesel generator was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating Systems Screening Questions, this finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, was not a loss of the system or function, and did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time. The finding had a cross-cutting aspect in the area of human performance work practices component because licensee staff did not communicate human error prevention techniques, such as proper documentation of activities, and did not use this technique commensurate with the risk of the assigned task such that work activities are performed safely. Specifically, the system engineer recognized the possibility of introducing air into the system, but assumed that operators would have filled and vented the system using the appropriate procedure, while operators did not use a procedure to tighten the leaking fitting and refill the priming tank H.4(a).
Enforcement.
Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be performed in accordance with procedures. Procedure MA1.DC54, Conduct of Maintenance, Revision 2, requires all work on plant systems, structures, or components to be performed using appropriate documentation such as work orders, notifications, procedures, or design drawing. Contrary to the above, on April 24, 2013, the licensee performed activities affecting quality that were not performed in accordance with procedures. Specifically, operators tightened a loose fitting on an emergency diesel generator fuel oil line and refilled the priming tank without using a procedure. This resulted in EDG 1-1 being inoperable because the fuel line was not properly refilled.
This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the licensees corrective action program as Notification 50561918 (NCV 05000275/2013004-01, Failure to Use a Procedure to Restore from Diesel Fuel Oil Leak).
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000275; 05000323/1-2011-008-00: Control
Room Ventilation System Design Vulnerability In November 2011, operators determined the control room ventilation system had a design vulnerability in which a portion of system airflow could bypass the installed filter in the event no control room ventilation system booster fan was operating. Without a booster fan operating, a portion of system airflow could go backwards through an equalizing line, which bypassed the filter, and was therefore unfiltered in-leakage.
Each train of control room ventilation has two booster fans, and the redundant fan could be started in the event that one booster fan fails. While operators would take actions per their emergency operating procedures to rectify the condition, it is estimated that it could take as long as 30 minutes to identify the problem and reestablish booster fan flow to ensure all system air was flowing in the correct direction through the filter. The 30 minutes of unfiltered air supply was not previously included in the calculated dose analysis of record. The licensee implemented compensatory measures to maintain operator dose less than the regulatory limit in the event of an accident and subsequently modified the ventilation system to include dampers that prevent the airflow from bypassing the filters in the event that no booster fan is operating.
The inspectors previously dispositioned the nonconforming in-leakage as a Green non-cited violation in Section 1R15.1 of NRC Integrated Inspection Report 05000275; 05000323/2011005.
No additional deficiencies were identified during the review of this Licensee Event Reports. This Licensee Event Report is closed.
.2 (Closed) LER 05000275; 05000323/2011-008-01: Control Room Ventilation System
Design Vulnerability On November 2011, operators determined the control room ventilation system had a design vulnerability in which a portion of system airflow could bypass the installed filter in the event no control room ventilation system booster fan was operating. Without a booster fan operating, a portion of system airflow could flow backwards through an equalizing line, which bypassed the filter, and was therefore unfiltered in-leakage.
This Licensee Event Report supplement identifies this concern as a condition prohibited by technical specifications, and provides updated information on the licensees corrective actions. The licensee has installed modifications in the control room ventilation system in November 2012, to add backdraft dampers that shut to prevent reverse-flow from bypassing the filter. The licensee then successfully completed control room envelope testing using a single train.
This Licensee Event Report supplement also discusses the licensees actions following the NRCs Task Interface Agreement 2012-08, Final Response to Task Interface Agreement 2012-08, Diablo Canyon Power Plant, Unit 1 and 2 - Request Office of Nuclear Reactor Regulations Review of Operability Issues Associated with Technical Specification 3.7.10, Control Room Ventilation System, dated November 20, 2012. In this letter, the NRC clarified that operability could not be restored without a change in the licensing basis design, basis analysis, or a repair to the control room envelope boundary, or both. The backdraft dampers installed by the licensee accomplished the repair of the control room envelope boundary. In addition, the licensee revised their technical specification bases, to bring them in line with this decision.
The inspectors previously dispositioned the nonconforming in-leakage as a Green non-cited violation in Section 1R15.1 of NRC Integrated Inspection Report 05000275; 05000323/2012005.
No additional deficiencies were identified during the review of this Licensee Event Reports supplement. This Licensee Event Report is closed.
.3 (Closed) LER 0500323/2013-001-00: Valid EDG 2-1 Start Signal Caused by a Loss of
4 kV Class 1E Bus G
Introduction.
The inspectors reviewed a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving troubleshooting on the Unit 2, 4kV Bus G that resulted in an unplanned de-energization. This caused a loss of a mitigating system and an unplanned entry into a 72-hour shutdown technical specification action statementdue to diesel fuel oil transfer pump 0-2 becoming unavailable.
Description.
On February 26, 2013, with Unit 2 in cold shutdown during a refueling outage, and with Unit 1 at 100 percent power, plant operators discovered that the white potential light that indicated that voltage was available for Unit 2, 4kV Bus G phases B-C was out. Operators discovered that Bus G undervoltage relay 7HGB1 had tripped.
Maintenance technicians performed troubleshooting on February 27 and identified that Bus G potential fuse UA-2 had failed. The Outage Control Center assembled a team to develop an action plan focused on fuse replacement and additional troubleshooting to determine the cause of the fuse failure.
The initial action plan developed on the night of February 27 recommended placing the diesel generator feeding Bus G in manual, cutting out the Bus G auto-transfer to startup Feature Cut Out (FCO), and stripping all loads from Bus G. An FCO switch prevents a relay from performing an unplanned actuation. Subsequent discussions on dayshift revealed that it would not be possible to strip all loads off Bus G as it fed component cooling water pump 2-2, one of the required outage safety plan components (component cooling water pump 2-1 was out of service for maintenance). This condition, along with a concern of losing Bus G due to another fuse failure, prompted a change in plans to work on an energized bus that supplied protected equipment. Existing procedures did not require a formal assessment of risk, nor was one performed; instead, the shift manager would address any potential impacts to protected equipment. While there was a requirement to address outage unit impacts to the operating unit, the plant staff did not recognize the potential impact to Unit 1 Technical Specification required diesel fuel oil transfer pump 0-2 being fed from Unit 2 Bus G.
On February 28, 2013 dayshift electrical maintenance personnel developed a troubleshooting work package that included a work order that directed placing diesel generator 2-1 in manual and opening all Bus G undervoltage FCO switches. Since it was assumed that the trip cut out was already completed, an action to ensure personnel had cut out the FCO was included in the work order prerequisites.
During dayshift, an operations and electrical maintenance staff meeting resulted in the decision to move various running equipment to an alternate bus. The decision left the backup spent fuel pool pump and diesel generator fuel oil transfer pump 0-2 powered by Bus G (note that these loads could have been moved to their alternate power sources),along with the previously mentioned component cooling water pump 2-2.
At 4:30 p.m. the dayshift emerging issue manager emailed the organization an updated emerging issue action plan. The updated plan stated that a partial markup of surveillance test procedure, STP M-75G, 4kV Vital Bus G Undervoltage Relay Calibration, would include the action to open the FCO switch; however, this was not consistent with the actual troubleshooting plan.
After a brief face-to-face turnover between the troubleshooting plan preparer and the oncoming nightshift electrical maintenance supervisor, the nightshift electrical maintenance crew performed a pre-job brief focused on the actual troubleshooting plan rather than the entire work package and its prerequisites. Additionally, personnel did not perform the required task preview in advance of the pre-job brief, nor did personnel determine nor mark specific critical steps as required by procedures. Finally, the shift foreman did not perform a task preview of the work package prior to the pre-job briefing.
After a joint walkdown of Bus G by operations and electrical maintenance personnel, work package implementation commenced with step 1 of the work instructions, bypassing the work order prerequisites, precautions, and limitations, including the work order action to ensure the FCO switch was opened by operations personnel.
Maintenance personnel failed to implement procedure place-keeping, which could have identified the missing prerequisite condition. When workers pulled the fuse block per the troubleshooting plan, Bus G de-energized as a result of the failure to open the FCO switch, and the following occurred:
- An unplanned start of diesel generator 2-1. This was reported to the NRC per 10 CFR 50.72(b)(3)(iv)(A).
- The loss of power to diesel generator fuel oil transfer pump 0-2, which caused an unplanned entry into a 72-hour technical specification action for Unit 1.
- The loss of power to component cooling water pump 2-2 and spent fuel pool pump 2-1. As the other train was operating, there was no loss of decay heat removal.
Analysis.
The failure to plan and coordinate emergent maintenance such that it would not impact other mitigating systems was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was evaluated for each unit separately. For Unit 1, which was at power, this finding was evaluated using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating Systems Screening Questions, this finding was determined to be of very low safety significance (Green) because, it was not a design or qualification deficiency, was not a loss of the system or function, and did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time. For Unit 2 this finding did not require evaluation using Inspection Manual Chapter 0609, and Appendix G because the unit was defueled. The finding had a cross-cutting aspect in the area of human performance, work practices component, because workers failed to use multiple human error prevention techniques H.4(a).
Enforcement.
Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be performed in accordance with procedures. Procedure MA1.DC54, Conduct of Maintenance, Revision 2, requires all work on plant systems, structures or components to be performed using appropriate documentation such as work orders, notifications, procedures, or design drawing. Contrary to the above, on February 28, 2013, the licensee performed activities affecting quality that were not performed in accordance with procedures. Specifically, operations and maintenance personnel failed to ensure the FCO switch was opened as required by procedure prerequisites. This resulted in diesel generator fuel oil transfer pump 0-2 becoming inoperable.
This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the licensees corrective action program as Notification 50544198 (NCV 05000275/2013004-02, Failure to Properly Follow Procedures Resulting in the Loss of a Vital Bus).
4OA5 Other Activities
.1 (Closed) Temporary Instruction 2515/182, Review of the Industry Initiative to Control
Degradation of Underground Piping and Tanks
a. Inspection scope
Leakage from buried and underground pipes has resulted in groundwater contamination incidents at some NRC-regulated sites with associated heightened NRC and public interest. The industry issued a guidance document, NEI 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS accession number ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS accession number ML110700122) with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.
b. Observations The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the Temporary Instruction and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase 1 inspection was conducted, have been completed.
Additionally, the licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the Temporary instruction and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff. Based upon the scope of the review described above, TI-2515/182 was completed and will be closed.
c. Findings
No findings were identified.
.2 (Closed) Violation 05000275; 05000323/2012012-004-01: Inadequate Corrective Actions
to Update the Final Safety Analysis Report Update with Required Information (EA-12-238)
The inspectors reviewed information submitted by the licensee in response to Notice of Violation EA-12-238, Inadequate Corrective Actions to Update the Final Safety Analysis Report Update with Required Information, and completed a review of the circumstances, causes, and corrective actions related to the violation. The corrective actions included reinstating Appendix 3.1A AEC General Design Criteria - 1971, in the FSARU, and numerous procedure revisions.
The inspectors noted that the descriptions in NRC inspection reports 0500275; 0500323/
2009003 and 050275; 0500323/2010002 did not provide sufficient clarity when describing that the Diablo Canyon units are designed to comply with the General Design Criteria for Nuclear Power Plant Construction Permits, (GDC) published by the Atomic Energy Commission (AEC) in July, 1967. The degree to which the Diablo Canyon Power Plant design conforms to the intent of the General Design Criteria for Nuclear Power Plants published in February 1971, establishes additional Diablo Canyon Power Plant licensing bases, which must also be reviewed when evaluating facility changes. The inspectors determined that the licensees apparent cause analysis and corrective actions were adequate. This violation is closed.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On August 15, 2013, the inspector presented the results of the radiation safety inspections to Mr. B. Allen, Site Vice President and other members of the licensee staff. The licensee staff acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
On September 12, 2013, the inspectors presented the final heat sink inspection results to Mr. J. Welsch, Station Director, and other members of the licensee staff. The licensee acknowledged the issues presented. Proprietary information was provided to the inspectors and all proprietary information was returned to PG&E.
On October 10, 2013, the resident inspectors presented the final inspection results to Mr. B. Allen, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. Proprietary information was provided to the inspectors and all proprietary information was returned to PG&E.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- B. Allen, Site Vice President
- J. Arhar, Supervisor, Engineering
- S. Baker, Manager, Engineering
- T. Baldwin, Manager, Regulatory Services
- A. Bates, Director, Engineering Services
- K. Bych, Manager, Engineering
- S. Dunlap, Supervisor, Engineering
- J. Fledderman, Director, Strategic Projects
- P. Gerfen, Senior Manager
- M. Gibbons, Acting Director, Work Control
- E. Halpin, Chief Nuclear Officer
- D. Hardesty, Senior Engineer
- J. Hinds, Director, Quality Verification
- T. Irving, Manager, Radiation Protection
- J. Kang, Engineer, Mechanical Systems Engineering
- A. Lin, Engineering
- J. MacIntyre, Director, Maintenance Services
- M. McCoy, NRC Interface, Regulatory Services
- J. Nimick, Director, Operations Services
- G. Porter, Senior Engineer
- J. Salazar, System Engineer
- L. Sewell, Supervisor, Radiation Protection
- D. Shippey, ALARA Supervisor, Radiation Protection
- D. Stermer, Manager, Operation
- M. Stevens, Associate, Quality Verification
- S. Stoffel, Supervisor, Dosimetry
- J. Summy, Senior Engineering Director
- L. Walter, Station Support
- J. Welsch, Station Director
- E. Wessel, Chemical Engineer, Chemistry
- M. Wright, Manager, Mechanical Systems Engineering
Attachment 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
The failure to use procedures to perform corrective maintenance
- 05000275-004-01 NCV on an emergency diesel generator (Section 4OA2)
Valid EDG 2-1 start Signal Caused by a Loss of 4 kV Class 1E
- 05000323-004-02 NCV Bus G (Section 4OA3)
Closed
- 05000275; Control Room Ventilation System Design Vulnerability
- 05000323/1-2011- LER (Section 4OA3)
008-00, -01
- 05000275; Control Room Ventilation System Design Vulnerability
- 05000323/1-2011- LER (Section 4OA3)
008-01:
Valid EDG 2-1 start Signal Caused by a Loss of 4 kV Class 1E 0500323/2013-001-
LER Bus G (Section 4OA3)
Review of the Industry Initiative to Control Degradation of 2515/182 TI Underground Piping and Tanks (Section 4OA5)
- 05000275; Inadequate Corrective Actions to Update the Final Safety Analysis
Discussed
- 05000275; Failure to Update the Final Safety Analysis Report Update with
- 05000323/2009- NCV Current Plant Design Criteria (Section 4OA3)
003-03
- 05000275; Failure to Update the Final Safety Analysis Report Update with
- 05000323/2010- NCV Current Plant Design Criteria (Section 4OA3)
2-02