IR 05000302/2011002
| ML111170469 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 04/27/2011 |
| From: | Rich D NRC/RGN-II/DRP/RPB3 |
| To: | Franke J Progress Energy Florida |
| References | |
| IR-11-002 | |
| Download: ML111170469 (31) | |
Text
April 27, 2011
SUBJECT:
CRYSTAL RIVER UNIT 3 - NRC INTEGRATED INSPECTION REPORT 05000302/2011002
Dear Mr. Franke:
On March 31, 2011, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Crystal River Unit 3. The enclosed integrated inspection report documents the inspection findings which were discussed on April 11, 2011, with you and other members of your staff.
The inspection examined activities conducted under your license as they related to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, one self-revealing finding of very low safety significance (Green) was identified. The finding did not involve a violation of NRC requirements.
Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with the NRC Enforcement Policy. If you contest any NCV you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident Inspector at the Crystal River Unit 3 site.
In addition, if you disagree with the characterization of any finding 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, RII, and the NRC Senior Resident Inspector at Crystal River Unit 3.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document 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/
Daniel W. Rich, Chief Reactor Projects Branch 3 Division of Reactor Projects
Docket No. 50-302 License No. DPR-72
Enclosure:
Inspection Report 05000302/2011002 w/Attachment: Supplemental Information
_ML111170469________________
X SUNSI REVIEW COMPLETE OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS SIGNATURE SON SLM4 TXM1 by email RJR1 by email NRS2 by il LFL RPC1 by email NAME SNinh SMendez-Gonzalez TMorrissey RReyes NChilds LLake RCarrion DATE 04/22/2011 04/19/2011 04/20/2011 04/20/2011 04/20/2011 04/22/2011 04/20/2011 E-MAIL COPY?
YES NO YES NO YES NO YES NO YES N YES NO YES NO OFFICE RII:DRS RII:DRP RII:DRP RII:DRP
SIGNATURE MAB7
/RA/
WGR1 by email JRS6 by email
NAME MBates DRich WRogers JSowa
DATE 04/29/2011 04/27/2011 04/20/2011 04/20/2011 04/ /2011 04/ /2011 04/ /2011 E-MAIL COPY?
YES NO YES NO YES NO YES NO YES N YES NO YES NO
REGION II==
Docket No.:
50-302
License No.:
Report No.:
Licensee:
Progress Energy (Florida Power Corporation)
Facility:
Crystal River Unit 3
Location:
Crystal River, FL
Dates:
January 1, 2011 - March 31, 2011
Inspectors:
T. Morrissey, Senior Resident Inspector R. Reyes, Resident Inspector N. Childs, Resident Inspector J. Sowa, Resident Inspector L. Lake, Senior Reactor Inspector (Section 4OA5)
R. Carrion, Senior Reactor Inspector (Section 4OA5)
M. Bates, Senior Operations Engineer (Section R11)
Approved by:
D. Rich, Chief, Reactor Projects Branch 3 Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000302/2011002; 01/01/2011-03/31/2011; Crystal River Unit 3; Licensed Operator
Requalification Program; Follow-up of Events and Notices of Enforcement Discretion
The report covered a three month period of inspection by resident inspectors, two regional senior reactor inspectors and one regional senior operations engineer. One Green self-revealing finding was identified. The significance of most findings is identified by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP).
Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs 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
& Self-Revealing Findings
Cornerstone: Mitigating Systems
Green: A self-revealing Green finding, associated with operating crew performance on the simulator during facility-administered requalification examination was identified. Two of the eight crews evaluated failed to pass their simulator examinations. As immediate corrective action, the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully retested) prior to returning to shift. The licensee has entered this issue into the corrective action program as Nuclear Condition Report (NRC)450196.
The inspectors determined that the crew failures constituted a performance deficiency based on the fact that licensed operators are expected to operate the plant with acceptable standards of knowledge and abilities demonstrated through periodic testing as required by 10 CFR 55.59(a)(2). Two out of eight crews of licensed operators failed to demonstrate a satisfactory understanding of the required actions and mitigating strategies required to safely operate the facility under normal, abnormal, and emergency conditions. The finding is greater than minor because the performance deficiency potentially affects the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding reflected the crews potential inability to take timely actions in response to actual abnormal and emergency conditions. The cause of this finding was directly related to the cross-cutting aspect of personnel training and qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety. (H.2(b))
(Section 1R11)
Licensee Identified Violations
One violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. The violation and corrective action tracking number is listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status:
Crystal River Unit 3 began the inspection period in Mode 5 (< 200oF). Unit 3 remained in Mode 5 for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
==1R01 Adverse Weather Protection
==
.1 Adverse Weather Protection:
Tornado Watch / Warning
a. Inspection Scope
On January 25, 2011, and again on March 30-31 the inspectors evaluated the licensees preparations when the site was informed of being in a tornado watch then subsequently in a tornado warning. The licensee implemented emergency management procedure EM-220, Violent Weather, for the tornado watches and warnings. The inspectors walked down the outside protective area to ensure actions required by EM-220 were implemented. This constituted two samples representing observation of adverse weather protection activities.
b. Findings
No findings were identified. The tornado watches and warnings expired with no violent weather or tornado formation near the site.
==1R04 Equipment Alignment
==
.1 Partial Equipment Walkdowns
a. Inspection Scope
The inspectors performed walkdowns of the critical portions of the selected trains to verify correct system alignment. The inspectors reviewed plant documents to determine the correct system and power alignments, and the required positions of select valves and breakers. The inspectors verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact mitigating system availability. The inspectors verified the following two partial system alignments in system walkdowns using the listed documents:
- A train nuclear service water (SW) and A train raw water (RW) systems, using operating procedure OP-408, Nuclear Services Cooling System, while B trains of SW and RW were out of service for scheduled maintenance
- Emergency diesel generator EGDG-1B using OP-707, Operation of the Emergency Diesel Generators, while the EGDG-1A was out of service for surveillance testing
b. Findings
No findings were identified.
==1R05 Fire Protection
==
.1 Fire Area Walkdowns
a. Inspection Scope
The inspectors walked down accessible portions of the plant to assess the licensees implementation of the fire protection program. The inspectors checked that the areas were free of transient combustible material and other ignition sources. Also, fire detection and suppression capabilities, fire barriers, and compensatory measures for fire protection problems were verified. The inspectors checked fire suppression and detection equipment to determine whether conditions or deficiencies existed which could impair the function of the equipment. The inspectors selected the areas based on a review of the licensees probabilistic risk assessment. The inspectors also reviewed the licensees fire protection program to verify the requirements of Final Safety Analysis Report (FSAR) Section 9.8, Plant Fire Protection Program, were met. Documents reviewed are listed in the attachment. The inspectors toured the following five areas important to safety:
- Remote shut down panel, and the A and B emergency service 4160-Volt switch gear rooms
- Sea water room 95 elevation auxiliary building
- Intermediate building 95 elevation emergency feed water pump EFP-1 and EFP-2 area
- Unit 3 main control room
- Control complex control rod relay cabinet room
b. Findings
No findings were identified.
.2 Annual Fire Drill
a. Inspection Scope
On January 18 and on January 23, the inspectors observed two separate licensee fire brigade responses to a simulated fire. Both drills involved a fire in the turbine building 480V unit switchgear room 95 elevation. The inspectors checked the brigades communications, ability to set up and execute fire operations, and their use of fire-fighting equipment. The inspectors verified compensatory actions were in place to ensure that additional alarms which may be received during the drill were addressed.
Additionally, the inspectors verified that the licensee considered the aspects as described below when the brigade conducted the firefighting activities and during the post drill critique. The inspectors attended the post-drill critiques to check that the licensees drill acceptance criteria were met and that any discrepancies were discussed and resolved. Administrative instruction AI-2205, Administration of CR-3 Fire Brigade, was reviewed to assure that acceptance criteria were evaluated and deficiencies were documented and corrected. In addition, the inspectors reviewed the storage, training, expectations for use and maintenance associated with the self-contained breathing apparatus (SCBA) program. This inspection completed one sample representing observation of selected fire drills. Documents reviewed are listed in the attachment.
The inspectors observed that:
- The brigade, including the fire team leader, had a minimum of five members.
- Members set out designated protective clothing and properly donned gear.
- SCBA were available and properly used.
- Control room personal verified fire location, dispatched fire brigade and sounded alarms. Emergency action levels were declared and notifications were completed.
- Fire brigade leader as well as the control room senior reactor operator had copies of the pre-fire plans.
- Brigade leader maintained control: Members were briefed, discussed plan of attack, received individual assignments, and completed communications checks. Plan of attack discussions were consistent with pre-fire plans.
- Fire brigade arrived at the fire scene in a timely manner, taking the appropriate access route specified in the strategies and procedures.
- Control and command was set up near the fire scene and communications were established with the control room and the fire brigade members.
- Effectiveness of radio communication between the command post, control room, plant operators and fire brigade members.
- Fire hose lines reached all necessary fire hazard locations, were laid out without flow constrictions, and were simulated as being charged with water.
- The fire area was entered in a controlled manner following the two person rule.
- The fire brigade brought sufficient fire-fighting equipment to the scene to properly perform its fire-fighting duties.
- The fire brigade checked for fire victims and fire propagation into other areas.
- Effective smoke removal operations were simulated in accordance with the pre-fire plan.
- The fire-fighting plan strategies were utilized.
- The drill scenario was followed, and the drill acceptance criteria were met.
- All firefighting equipment was returned to a condition of readiness.
b. Findings
No findings were identified.
==1R06 Flood Protection Measures
Internal Flood Protection
a. Inspection Scope
==
The Inspectors reviewed the Crystal River Unit 3, FSAR, Chapter 2.4.2.4, Facilities Required for Flood Protection, and the Crystal River Unit 3 design basis documents that depicted protection for areas containing safety-related equipment to identify areas that may be affected by internal flooding. A walkdown of the emergency feed pump EFP-1 and EFP-2 area was conducted to ensure that flood protection measures were in accordance with design specifications. Specific plant attributes that were checked included structural integrity, sealing of penetrations, and operability of sump systems.
b. Findings
No findings were identified
==1R07 Heat Sink Performance
Annual Review
a. Inspection Scope
==
The inspectors observed maintenance personnel perform heat exchanger inspections and cleaning for the service water heat exchanger SWHE-1B. The inspector reviewed the as-found conditions when the heat exchanger was opened for inspection and tube cleaning to verify the heat exchanger was in an acceptable condition to perform its design function. In addition, the inspectors observed heat exchanger maintenance that included tube replacement and recoating of the end bell and channel head. The documents reviewed are listed in the attachment.
b. Findings
No findings were identified.
==1R11 Licensed Operator Requalification Program
==
.1 Resident Inspector Quarterly Review
a. Inspection Scope
On February 1, the inspectors observed and assessed licensed operator crew response and actions for the Crystal River Unit 3 licensed operator simulator evaluated session SES-161. Session SES-161 involved two major transients: B train steam generator tube leak; and a spurious reactor trip. The plant conditions degraded to a point where the licensee entered an Alert emergency classification. The inspectors observed the operators use of abnormal procedures AP-545, Plant Runback; and AP-510 Rapid Power Reduction. Additionally, emergency operating procedures used during the scenario included EOP-02, Vital System Status Verification and EOP-06, Steam Generator Tube Rupture. The operators actions were verified to be in accordance with the above procedures. Event classification and notifications were verified to be in accordance with emergency management procedure EM-202, Duties of the Emergency Coordinator. The simulator instrumentation and controls were verified to closely parallel those in the actual control room. The inspectors attended the management crew critique and evaluation to verify the licensee had entered any adverse conditions into the corrective action program. The inspectors evaluated the following attributes related to crew performance:
- Clarity and formality of communication
- Ability to take timely action to safely control the unit
- Prioritization, interpretation, and verification of alarms
- Correct use and implementation of abnormal and emergency operation procedures and emergency plan implementing procedures
- Control board operation and manipulation, including high-risk operator actions
- Oversight and direction provided by supervision, including ability to identify and implement appropriate technical specification actions, regulatory reporting requirements, and emergency plan classification and notification
- Crew overall performance and interactions
b. Findings
No findings were identified.
.2 Biennial Review by Regional Inspector
a. Inspection Scope
The inspector reviewed the facility operating history and associated documents in preparation for this inspection. During the week of February 21, 2011, the inspector reviewed documentation, interviewed licensee personnel, and observed the administration of operating tests associated with the licensees operator requalification program. Each of the activities performed by the inspector was done to assess the effectiveness of the facility licensee in implementing requalification requirements identified in 10 CFR Part 55, Operators Licenses. Evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification Program. The inspector also evaluated the licensees simulation facility for adequacy for use in operator licensing examinations using ANSI/ANS-3.5-1998, American National Standard for Nuclear Power Plant Simulators for Use in Operator Training and Examination. The inspector observed a crew during the performance of the operating tests. Documentation reviewed included written examinations, Job Performance Measures (JPMs), simulator scenarios, licensee procedures, on-shift records, simulator modification request records, simulator performance test records, operator feedback records, licensed operator qualification records, remediation plans, and medical records.
The records were inspected using the criteria listed in Inspection Procedure 71111.11.
Documents reviewed during the inspection are listed in the Attachment.
On February 25, 2011, the licensee completed the comprehensive biennial requalification written examinations and annual requalification operating tests required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The inspector performed an in-office review of the overall pass/fail results of the written examinations, individual operating tests and the crew simulator operating tests. These results were compared to the thresholds established in Manual Chapter 0609 Appendix I, Operator Requalification Human Performance Significance Determination Process.
b. Findings
Introduction:
A self-revealing Green finding, associated with operating crew performance on the simulator during facility-administered requalification examination was identified when two of eight crews failed the simulator portion of the facility-administered annual operating test. Based on the licensees successful remediation and subsequent re-testing of individuals who failed the simulator portion of the annual operating test, no violation of regulatory requirements occurred.
Description:
During the facility-administered annual operating test of licensed operators, covering the period from January 19, to February 24, 2011, the licensees training staff evaluated crew performance during dynamic scenarios. The evaluations were performed using TRN-NGGC-0420, Conduct of Simulator Training and Evaluation, Rev. 0. Facility results of crew performance indicated that two of eight crews (25 percent) did not pass their simulator exam. The licensees training staff determined that two crews failed to meet the criteria for satisfactory performance of critical tasks. The crew failures of simulator operational evaluations on the 2011 annual operating test have been addressed in the licensees corrective action program with nuclear condition report (NCR) 450196.
Analysis:
The inspector determined that the crew failures constituted a performance deficiency based on the fact that licensed operators are expected to operate the plant with acceptable standards of knowledge and abilities demonstrated through periodic testing as required by 10 CFR 55.59(a)(2). Two out of eight crews of licensed operators failed to demonstrate a satisfactory understanding of the required actions and mitigating strategies required to safely operate the facility under normal, abnormal and emergency conditions. The finding was greater than minor because the performance deficiency was associated with the Human Performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding reflected the crews potential inability to take timely actions in response to actual abnormal and emergency conditions.
The perceived risk associated with the number of crews failing the annual operating test was provided in the Simulator Operational Evaluation matrix of NRC Manual Chapter 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP). The matrix was entered based on the number of crews that took the simulator test (eight) and the number of crews with unsatisfactory performance (two).
Based on a crew failure rate of 25 percent on the simulator portion of the annual operating test, the fact that the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully re-tested) prior to returning to shift, and because there was no similar finding the previous year, this finding was characterized by the SDP as having a very low safety significance, or Green. The cause of this finding was directly related to the cross-cutting aspect of personnel training and qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety. (H.2(b))
Enforcement:
This finding does not involve enforcement action because no regulatory requirement violation was identified. Because this finding does not involve a violation and has a very low safety significance, it is identified as FIN 5000261/2011002-01, Two of Eight Operating Crew Failures on the Simulator Operational Evaluation Portion of the 2011 Annual Requalification Operating Test.
==1R12 Maintenance Effectiveness
a. Inspection Scope
==
The inspectors reviewed the licensees effectiveness in performing routine maintenance activities. The review included the identification, scope, and handling of degraded equipment conditions, as well as common cause failure evaluations, and the resolution, of historical equipment problems. For those systems, structures, and components within the scope of the Maintenance Rule (MR) per 10 CFR 50.65 (a)(1) and (a)(2),classifications were justified in light of the reviewed degraded equipment condition. The documents reviewed are listed in the attachment. The inspectors conducted this inspection for the following four items:
- System Engineering (SE) report SE11-0006, Remove Spent Fuel Pump Motor Cooling system (AH-XG) from the Scope of the Maintenance Rule
- NCR 434362, Raw water pump RWP-2B reduced seal flush flow
- SE11-0014, Nuclear Instrumentation Source Range to Return to (a)(2)
- Inspector review of licensees preventative maintenance program associated with components that have a recommended vendor service life. This completes the NRC review utilizing Operating Experience Smart Sample (OpESS) FY 2010-01 Recent Inspection Experience for Components Installed Beyond Vendor Recommended Service Life.
b. Findings
No findings were identified.
==1R15 Operability Evaluations
a. Inspection Scope
==
The inspectors reviewed the following two NCRs to verify operability of systems important to safety was properly established, that the affected components or systems remained capable of performing their intended safety function, and that no unrecognized increase in plant or public risk occurred. The inspectors determined if operability of systems or components important to safety was consistent with Improved Technical Specifications (ITS), the FSAR, 10 CFR Part 50 requirements, and when applicable, NRC Inspection Manual, part 9900, Technical Guidance, Operability Determinations &
Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety. The inspectors reviewed licensee NCRs, work schedules, and engineering documents to check if operability issues were being identified at an appropriate threshold and documented in the corrective action program, consistent with 10 CFR 50, Appendix B requirements and licensee procedure CAP-NGGC-200, Condition Identification And Screening Process. The documents reviewed are listed in the attachment.
- NCR 447026, SWHE-1B front and back channel heads corroded with several areas below the vendor recommended limit
- NCR 436065, Evaluate makeup system valve MUV-163 for possible degradation
b. Findings
No findings were identified.
==1R18 Plant Modifications
Permanent Plant Modifications
a. Inspection Scope
==
The inspectors reviewed the engineering change (EC) 76007, Emergency Feedwater Initiation and Control Flow Circuit, to verify it met the requirements of engineering procedures EGR-NGGC-0003, Design Review Requirements, and EGR-NGGC-0005, Engineering Change. The inspectors observed the as-built configuration of the modification and observed installation, and observed testing activities associated with the modification. Documents reviewed included surveillance procedures, design and implementation packages, work orders (WOs), system drawings, corrective action documents, applicable sections of the FSAR, ITS, and design basis information. Post maintenance testing data and acceptance criteria were reviewed. The inspectors verified that issues found during the course of the installation and testing associated with the modification were entered and properly dispositioned in the licensees corrective action program.
b. Findings
No findings were identified.
==1R19 Post Maintenance Testing
a. Inspection Scope
==
The inspectors either observed or reviewed post-maintenance test results as appropriate, for selected risk significant systems to verify whether:
- (1) testing was adequate for the maintenance performed;
- (2) acceptance criteria were clear, and adequately demonstrated operational readiness consistent with design and licensing basis documents;
- (3) test instrumentation had current calibrations, range, and accuracy consistent with the application;
- (4) tests were performed as written with applicable prerequisites satisfied, and
- (5) equipment was returned to the status required to perform its safety function. The five post-maintenance tests reviewed are listed below:
- Surveillance procedure SP-354B, Monthly Functional Test of the Emergency Diesel Generator EGDG-1B, after performing maintenance per work orders (WOs)01706861 and 01435520
- SP-344B, RWP-2B, SWP-1B and Valve Surveillance, after performing maintenance on RWP-2B and SWP-1B per WOs 1852978, 1332475, 1332477, 1848527 and 1852978
- Performance Test PT-445, Control Rod Programming Verification, after performing maintenance per WO 1893481
- SP-354C, Functional Test of the Alternate AC Diesel Generator EGDG-1C, after performing maintenance per WO 1691112
- SP-344A, RWP-2A, SWP-1A and Valve Surveillance, after performing maintenance per WO 1063292
b. Findings
No findings were identified.
==1R20 Refueling and Outage Activities
Steam Generator Replacement Refueling Outage (RFO16)
a.
==
Inspection Scope
On September 26, 2009, the unit was shutdown for a planned steam generator replacement refueling outage. The previous quarters NRC inspection activities in this area were documented in NRC integrated inspection report 05000302/2010005. During this quarter, the inspectors observed and monitored licensee controls over the refueling outage activities listed below. Documents reviewed are listed in the Attachment.
- Outage related risk assessment monitoring
- Controls associated with shutdown cooling, reactivity management, electrical power alignments, containment closure, and spent fuel pool cooling
- Implementation of equipment clearance activities
b. Findings
No findings were identified
==1R22 Surveillance Testing
a. Inspection Scope
==
The inspectors observed surveillance tests or reviewed the test results for the six surveillance tests listed below to verify that ITS surveillance requirements were followed and that test acceptance criteria were properly specified. The inspectors verified that proper test conditions were established as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria had been met. Additionally, the inspectors verified that equipment was properly returned to service and that proper testing was specified and conducted to ensure that the equipment could perform its intended safety function.
In-Service Test:
- SP-340A, RWP-3A, DCP-1A and Valve Surveillance
Surveillance Test:
- PT-315, Remote Shutdown Relay Operability
- SP-524, Battery Modified Performance Discharge Test (A train only)
- SP-108, Reactor Trip Module And Control Rod Drive Trip Functional Test
- SP-902 4160V ES Bus A Undervoltage Trip Test and Auxiliary Relay Calibration (sections 4.3 and 4.4 only)
b. Findings
No findings were identified.
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed two emergency response activities to verify the licensee was properly classifying emergency events, making the required notifications, and appropriate protective action recommendations. The inspectors assessed the licensees ability to classify emergent situations and make timely notification to State and Federal officials in accordance with 10 CFR Part 50.72. Emergency activities were verified to be in accordance with the Crystal River Radiological Emergency Response Plan, Section 8.0, Emergency Classification System, and 10 CFR Part 50, Appendix E. Additionally, the inspectors verified that adequate licensee critiques were conducted in order to identify performance weaknesses and necessary improvements.
- February 1, license operator simulator evaluated session, SES-161, involving a steam generator tube rupture and a spurious reactor trip
- March 1, Crystal River Unit 3 2011 radiological emergency response training drill.
The drill scenario included equipment failures on the operating reactor that caused the licensee to make emergency classifications and notifications and activate the technical support center (TSC) and the emergency operating facility (EOF). The inspectors observed the drill activities at the Unit 3 simulator, TSC, and the EOF.
The inspectors attended the drill critiques at the TSC and EOF to verify the licensee had adequately identified any performance weaknesses and necessary improvements.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA2 Problem Identification and Resolution
.1 Daily Review
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program (CAP). This review was accomplished by attending daily plant status meetings, interviewing plant operators and applicable system engineers, and accessing the licensees computerized database.
b. Findings
No findings were identified.
.2 Annual Sample Review
a. Inspection Scope
The inspectors selected several NCRs documenting NRC identified deficiencies associated with spent fuel pool foreign material exclusion area (FMEA) controls for a detailed review and discussion with the licensee. These deficiencies were identified by the inspectors over the last several months. The NCRs reviewed are listed in the attachment. The NCRs were written to address improper FMEA log entries, material in the area not properly logged, and expansion of the FMEA without verifying proper cleanliness of the expanded area. The inspectors verified that the issues were completely and accurately identified in the licensees corrective action program, safety concerns were properly classified and prioritized for resolution, the cause determination was sufficiently thorough, and appropriate corrective actions were initiated. The inspectors also evaluated the NCRs using the requirements of the licensees CAP as delineated in corrective action procedure CAP-NGGC-200, Condition Identification and Screening Process.
b. Findings and Observations
No findings were identified. The inspectors noted that the licensee took immediate and appropriate actions to address each of the identified deficiencies. The licensees corrective action to require an FME monitor for all entries into the spent fuel pool FMEA should prevent recurrence of similar issues. The inspectors determined that there were no identified consequences associated with the FMEA issues identified.
.3 Semi-Annual Trend Review
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1 above, plant status reviews, plant tours, and licensee trending efforts. The inspectors review nominally considered the six month period of October 2010 through March 2011. The review also included issues documented in the licensees Plant Health Committee Site Focus List - March 2011, various departmental CAP Rollup & Trend Analysis reports for the 4th quarter 2010, various nuclear assessment section reports and maintenance rule (MR) reports. Corrective actions associated with a sample of the issues identified in the licensees corrective action program were reviewed for adequacy.
b.
Assessment and Observations
No findings were identified. The inspectors evaluated the licensees trend methodology and observed that the licensee had performed a detailed review. The inspectors review of licensee performance over the last six months noted one negative trend associated with spent fuel pool FMEA controls. The licensee is aware of the negative trend and has implemented appropriate corrective actions. Additional detail can be found in section 4OA2.2.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
(Closed) LER 05000302/2010-001-00, -01, -02 As-Found Cycle 16 Pressurizer Code Safety Valve Setpoints Outside Improved Technical Specification Limit
With Crystal River Unit 3 in No Mode (core off loaded), the licensee determined that the as-found lift setpoints of the two pressurizer code safety valves (PCSV) removed after the September 2009 unit shut down were outside Improved Technical Specification (ITS)limits. ITS 3.4.9 requires that two PCSVs shall be operable in Modes 1, 2, and 3. To be operable, the lift setpoints must be within +/- 2 percent of 2500 psig. The lift setpoints for the PCSVs were found to be 5.32 percent and 2.08 percent above the ITS setpoint respectively. The licensee concluded that both PCSVs were inoperable for a period longer than allowed by plant ITS. A root cause could not be determined.
The licensee identified a selected cause associated with the licensees failure to manage vendor quality. The licensee failed to provide proper relief valve specifications to the vendor including a detailed testing procedure, repair plan and acceptance criteria.
Corrective actions planned or completed include: changing the as-left setpoint to +0/-1 percent of the nominal setpoint; installing PCSVs with +0/-1 percent of nominal setpoint prior to unit startup; creation of a test procedure for steam testing the PCSV to meet the licensees standards; and revision of specifications associated with PCSV repairs.
The finding was evaluated under the Significance Determination Process (SDP) using Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and was determined to degrade the RCS barrier under the Barriers Cornerstone. Utilizing Table 4a, Attachment 0609.04, the issue was screened as needing an SDP Phase III evaluation. When notified that an SDP Phase III evaluation was required, the licensee contracted with Areva NP Inc. to analyze the impact of high as-found PCSV setpoints on peak reactor coolant system (RCS) pressure for the most limiting accident transients.
Areva Technical Data Record 12-9154488-000, CR-3 Pressurizer Code Safety Valve Analysis for Licensee Event Report, concluded that for the most limiting transients (startup accident, loss of feed water and feed water line break), the peak RCS pressure remained below the acceptance criteria for each transient and would not impact RCS integrity. Revision 02 of the LER documents this Areva NP Inc. analysis. With this additional information, the inspectors in conjunction with the Regional NRC Senior Reactor Analyst (SRA) concluded that the PCSVs, with their as-found setpoints outside of ITS limits, would have performed their safety function and a formal SDP Phase III evaluation would not be required. Therefore, the finding was determined to be of very low safety significance (Green). The inspectors determined that this violation of ITS 3.4.9, Pressurizer Safety Valves, met the criteria for a licensee-identified violation. The enforcement aspects of the violation are discussed in Section 4OA7. This LER is closed.
b.
Finding
No findings were identified.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel Activities
a. Inspection Scope
During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during normal and off-normal plant working hours.
These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors normal plant status reviews and inspection activities.
b.
Finding
No findings were identified.
.2 Steam Generator Replacement Project and Containment Wall Repair (IP 50001)
a. Inspection Scope
Steam Generator Replacement Project Activities
The inspectors reviewed the following issues:
Bulges of Liner Plate The licensee developed an engineering calculation to evaluate bulges in the CR3 liner plate. It was directed at determining an apparent cause for the bulges and establishing an analytically-based acceptance criterion for the bulges within the CR3 design basis. The analyses included finite element modeling of the liner and the associated anchorage to the concrete containment structure. The apparent cause for the bulges was determined to be a combination of elements, including geometrical imperfections in the original liner plate during construction. The calculations considered worst case configurations and a threshold for bulge size was established considering the effects that occur due to normal operation and accident conditions. The primary variables in the bulge evaluation were determined to be bulge size and thermal loading.
The calculation found that the bulges have an insignificant effect on the response of the structure due to various load combinations. The current bulges are bounded by the acceptance criteria in the analysis. To ensure that conditions are acceptable in the future, the licensee planned to include bulge surveillance in the international welding engineer (IWE) program. The licensee also planned to validate the effects of retensioning on bulge size by measurement and evaluation of a representative sample before initiating Structural Integrity Test (SIT) pressurization as well as performing a complete baseline scan after completion of the SIT.
50.59 Evaluation The inspectors reviewed the licensees evaluation of the containment building modification resulting from the introduction of the construction opening and its subsequent restoration with respect to requirements of 10 CFR, § 50.59, Changes, Tests and Experiments, to determine whether the design bases, licensing bases, and performance capability of the containment had been degraded through the modification and to determine whether the design and license basis documentation used to support changes reflected the design and license basis of the facility after the change had been made. This evaluation remained ongoing pending completion of containment repairs, completion of tendon retensioning, completion of post modification testing, and subsequent validation of design parameters.
Vertical Cracks of Containment Building The licensee determined that the vertical cracks discovered on the exterior wall of the Containment Building would close as the buildings tendons were retensioned. The inspectors walked down selected vertical cracks being monitored by the licensee to evaluate their condition. The licensee had measured the cracks periodically and determined that they were closing as the tendon retensioning process continued. The inspectors also visited the tendon control center where the retensioning process was controlled and which housed the acoustic monitoring and strain gage instrumentation and interviewed personnel in the center to better understand the operation of the systems being used and how the information obtained was interpreted. Inspection in this area remained ongoing pending completion of tendon retensioning and subsequent validation of design parameters.
Tendon Retensioning Activities The inspectors reviewed the licensees retensioning plans, procedures, and drawings. Retensioning activities began on January 4, 2011.
The inspectors observed some of the retensioning work on selected hoop tendons as it was being performed to verify that the work was being conducted per approved procedures.
Structural Integrity Test (SIT) / Integrated Leak Rate Test (ILRT) Preparations The inspectors interviewed licensee personnel responsible for the planned SIT/ILRT to determine the status of the test preparations, walked down the containment building to verify the locations of the extensometers to be used to measure the containment movements during the SIT/ILRT, and discussed the licensees procedures to assure that they conformed to industry standards and ASME Code requirements.
Events of March 14, 2011 On the afternoon of March 14, 2011, the licensee had completed the first retensioning sequence (Sequence #100, Hoop Tendons 42H41, 62H41, and 64H41) of the final pass (Pass 11). Per procedure, the licensee was waiting for the containment building to stabilize before beginning the next sequence and was monitoring the structural behavior of the containment building via acoustical emissions monitors and strain gauges, specifically placed at various points of the structure to detect any abnormal/unexpected response to tendon retensioning. During this monitoring period, the strain gauges indicated an increase in strain and then failed high, and the acoustic monitors indicated a high level of acoustic activity in the bay bordered by Buttresses 5 and 6 (Bay 5-6). Sound coming from the bay was reported to sound like popcorn popping by workers in the area. The phenomenon reportedly lasted for approximately twenty minutes. The licensee utilized impulse response (IR) non-destructive examination (NDE) techniques to determine the condition of the wall in Bay 5-6. The IR scans of the bay determined that there were numerous indications consistent with a delamination. By the end of the inspection period, the licensee had determined that the delamination was extensive in Bay 5-6 and was continuing to evaluate the condition of the containment structure.
b. Findings
No findings were identified.
4OA6 Exit
Exit Meeting Summary
On April 11, 2011, the resident inspectors presented the inspection results to Mr. J.
Franke, Site Vice President and other members of licensee management. The inspectors confirmed that proprietary information was not provided or examined during the inspection.
4OA7 Licensee Identified Violations
The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.
Improved Technical Specification (ITS) 3.4.9 states that two pressurizer code safety valves (PCSVs) shall be operable in Modes 1, 2 and 3. To be operable, the lift setpoints must be within +/- 2 percent of 2500 psig. Contrary to the above, on September 1, 2010 and on October 5, 2010, Progress Energy was notified that the as-found lift setpoints of PCSVs RCV-9 and RCV-8 were outside ITS setpoint limits, respectively. The as-found lift setpoint of RCV-9 was 5.32 percent above the lift setpoint and RCV-8 was 2.08 percent above the lift setpoint. The licensee identified a selected cause associated with the licensees failure to manage vendor quality. The performance deficiency, failure to provide proper relief valve specifications to the vendor, was determined to be greater than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern regarding the integrity of the reactor coolant system (RCS) barrier during plant transients. Corrective actions planned or completed include: changing the as-left setpoint to +0/-1 percent of the nominal setpoint; installing PCSVs with +0/-1 percent of nominal setpoint prior to unit startup; creation of a test procedure for steam testing the PCSV to meet the licensees standards; and revision of specifications associated with PCSV repairs. As documented in Section 4OA3, the finding was determined to be of very low safety significance (Green) because there was no loss of safety function due to the lift setpoints being outside of the ITS limit.
This issue was documented in the licensees corrective action program as NCR 426852.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- J. Holt, Plant General Manager
- D. Douglas, Manager, Maintenance
- S. Cahill, Director, Engineering
- J. Huegel, Manager, Nuclear Oversight
- P. Dixon, Manager Training
- B. Wunderly, Manager, Operations
- D. Westcott, Supervisor, Licensing
- B. Akins, Superintendent, Radiation Protection
- C. Poliseno, Supervisor, Emergency Preparedness
R, Wiemann, Acting Director, Engineering
- I. Wilson, Manager Outage and Scheduling
- J. Franke, Vice President, Crystal River Nuclear Plant
- M. Van Sicklen, Superintendent Operations Training
- R. Llewellyn, Supervisor - Operations Continuing Training
NRC personnel
- D. Rich, Chief, Branch 3, Division of Reactor Projects
LIST OF ITEMS
OPENED, CLOSED
Opened and Closed
FIN Operating Crew Failures on the 2011 Annual
Requalification Operating Test (Section 1R11.2)
Closed
- 05000302/2010001-00, -01, -02 LER As-Found Cycle 16 Pressurizer Code Safety Valve Setpoints Outside Improved technical Specification Limit