IR 05000250/2010006
| ML101830300 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 07/02/2010 |
| From: | Hopper G NRC/RGN-III/DRP/RPB7 |
| To: | Nazar M Florida Power & Light Co |
| References | |
| IR-10-006 | |
| Download: ML101830300 (19) | |
Text
July 2, 2010
SUBJECT:
TURKEY POINT NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000250/2010006 AND 05000251/2010006
Dear Mr. Nazar:
On May 21, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Turkey Point Nuclear Plant Units 3 and 4. The enclosed report documents the inspection results which were discussed on May 21, 2010, and again on June 29, 2010, with Mr. P. Rubin and other members of your staff.
The inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of plant equipment and activities, and interviews with personnel.
On the basis of the sample selected for review, the team concluded that in general, problems were properly identified, evaluated, and resolved within your corrective action program. There was one green finding identified during this inspection associated with the inadequate implementation of a procedure during a visual inspection of a safety-related snubber. The failure to identify missing, detached, loosened support items, or full thread engagement of all mechanical connections led to a snubber failure. This finding was determined to involve a violation of NRC requirements. Additionally, one licensee-identified violation of very low safety significance (Green) is listed in this report. However, because of the very low safety significance of these findings and because they have been entered into your corrective action program, the NRC is treating them as a non-cited violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you contest any NCV in this report, 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 Resident Inspectors at Turkey Point.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response, if any, 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/
George T. Hopper, Chief
Reactor Projects Branch 7
Division of Reactor Projects
Docket Nos.: 50-250 and 50-251 License Nos.: DPR-31 and DPR-41
Enclosure:
Inspection Report 05000250/2010006 and 05000251/2010006
w/Attachment: Supplemental Information
REGION II==
Docket Nos.:
50-250, 50-251
License Nos.:
Report No:
05000250/2010006, 05000251/2010006
Licensee:
Florida Power & Light Company (FP&L)
Facility:
Turkey Point Nuclear Plant, Units 3 & 4
Location:
9760 S. W. 344th Street
Florida City, FL 33035
Dates:
May 3 to 21, 2010
Inspectors:
R. Taylor, Senior Project Inspector, Team Leader
M. Barillas, Resident Inspector, Turkey Point
T. Lighty, Project Engineer
S. Sanchez, Resident Inspector, St. Lucie
Approved by:
George T. Hopper, Chief Reactor Projects Branch 7 Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000250/2010006, 05000251/2010006; 05/03/2010 - 05/21/2010; Turkey Point Nuclear
Plant, Units 3 and 4; biennial inspection of the identification and resolution of problems.
The inspection was conducted by one senior project inspector, two resident inspectors, and one project engineer. One green finding of very low safety significance was identified. The significance of most findings is indicated by its color (Green, White, Yellow, Red) using the Significance Determination Process in Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspect was determined using IMC 0305,
Operating Reactor Assessment Program. Findings for which the Significance Determination Process 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.
Identification and Resolution of Problems
The team concluded that, in general, problems were properly identified, evaluated, prioritized, and corrected. The threshold for initiating condition reports (CRs) was appropriately low, as evidenced by the types of problems identified and the number of CRs entered annually into the Corrective Action Program (CAP). Employees were encouraged by management to initiate CRs. However, the team identified deficiencys associated with preventative maintenance (PM)scheduling in that a number of PMs were inadvertently scheduled past their due dates when the licensee began using the PM scheduling tool LCP.net. In addition, the team identified several examples of minor equipment issues that had not been identified by the licensee and entered into the CAP. When identified, the licensee entered these issues into the CAP. Generally, prioritization and evaluation of issues were adequate, formal root cause evaluations for significant problems were adequate, and corrective actions specified for problems were acceptable. Overall, corrective actions developed and implemented for issues were generally effective and implemented in a timely manner.
The team determined that, overall, audits and self-assessments were adequate in identifying deficiencies and areas for improvement in the CAP, and in most cases, appropriate corrective actions were developed to address the issues identified. Operating experience usage was found to be generally acceptable and integrated into the licensees processes for performing and managing work and plant operations.
Based on discussions and interviews conducted with plant employees from various departments, the inspectors determined that personnel felt free to raise safety concerns to management and use the CAP to resolve those concerns.
Cornerstone: Mitigating Systems
- Green.
The NRC identified a non-cited violation of 10 CFR 50, Appendix B, Criterion V, for the licensees failure to implement procedures during a visual inspection of safety related seismically qualified snubber SN-4-1039. Specifically, the licensee failed to identify missing, detached, loosened support items, or full thread engagement of all mechanical connections that led to a snubber failure as prescribed in procedure 0-OSP-105.1, Visual Inspection, Removal and Reinstallation of Mechanical Shock Arrestors, section 7.2.1.3.d. The snubber would not have been able to perform its design function to arrest shocks of the main steam piping to the C Steam Generator during seismic events or transients, such as sudden isolation of the main steam isolation valve. The licensee implemented immediate corrective actions which included replacing the snubber in containment, adding specific instructions in procedure 0-OSP-105.1 to specifically inspect the locking ring and correct installation, and to include emphasis on FPL expectations from vendor provided snubber inspection services. The licensee documented this in condition report CR 2008-31372.
The performance deficiency was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone in that the licensee did not ensure reliability of the snubber to respond to initiating events to prevent undesirable consequences in that the snubber would not have been able to perform its design function to arrest shocks of the main steam piping to the C Steam Generator during seismic events or transients. The finding was screened using Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," and was determined to have a very low safety significance (Green)because the system remained operable and capable of meeting its design function with no loss of safety function of the C main steam system. This finding was reviewed for cross-cutting aspects and none were identified. (4OA2).
One violation of very low safety significance (Green), 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. This violation and associated corrective actions are listed in Section 4OA7 of this report.
REPORT DETAILS
OTHER ACTIVITIES
4OA2 Problem Identification and Resolution
a.
Assessment of the Corrective Action Program (CAP)
- (1) Inspection Scope
The inspectors reviewed the licensees CAP procedures which described the administrative process for initiating and resolving problems using condition reports (CRs). To verify that problems were being properly identified, the inspectors toured plant areas, including the main control rooms and accompanied operations personnel on routine daily rounds to verify that issues were identified and documented in the CAP.
Daily plant status reports were reviewed and plant issues were checked for appropriate documentation in the CAP. A sampling of work orders and surveillance tests since 2008 was checked to assure that identified problems were documented and resolved in the CAP. Further, the inspectors verified that issues were appropriately characterized, and screened in accordance with the significance of the issue. The inspectors included a detailed review of selected CRs associated with four risk-significant systems: Auxiliary Feedwater (AFW), Component Cooling Water (CCW), Intake Cooling Water (ICW), and Station Batteries. In these systems and in other selected cases, a review of issues as far back as 5 years or more was done. The inspectors conducted plant walkdowns of equipment associated with selected systems to look for any deficiencies that had not been previously entered into the CAP. System health reports, condition reports, engineering walkdown reports and interviews with personnel were done to assess effectiveness of problem resolution. Also, work order and corrective action backlogs were checked to assess if risk-significant issues were being promptly addressed. Where possible, the inspectors independently verified that the corrective actions were implemented as intended. The inspectors also reviewed selected common causes and generic concerns associated with root cause evaluations to determine if they had been appropriately addressed. To help ensure that samples were reviewed across all cornerstones of safety, the team selected a representative number of CRs that were identified and assigned to the major plant departments, including operations, maintenance, engineering, emergency preparedness, health physics, and security.
These CRs were reviewed to assess each departments threshold for identifying and documenting plant problems, thoroughness of evaluations, and adequacy of corrective actions.
The inspection included a detailed review and evaluation of CRs associated with significant conditions adverse to quality (screened as significance level 1 by the licensee and requiring root cause evaluation). The inspectors assessed if the licensee had adequately determined the cause(s) of identified problems and had adequately addressed operability, reportability, common cause, generic concerns, extent-of-condition, and extent-of-cause. The use of operating experience (OE) in assessing significant conditions was evaluated. The review also assessed if the licensee had appropriately identified and prioritized corrective actions to prevent recurrence.
Control room walkdowns were also performed to assess the main control room (MCR)deficiency list and to ascertain if deficiencies were being tracked to resolution. A sample of operator workarounds and operator burden screenings were reviewed and the inspectors verified compensatory measures for deficient equipment were being implemented in the field.
The team reviewed selected industry operating experience items, including NRC generic communications and Part 21 reports, to verify that they had been appropriately evaluated for applicability or used in licensee activities and that issues identified through these reviews had been entered into the CAP.
The team reviewed site trend reports, to determine if the licensee effectively trended identified issues and initiated appropriate corrective actions when adverse trends were identified.
Documents critically reviewed are listed in the Attachment.
- (2) Assessment
Identification of Issues
The team determined that the licensee was effective in identifying problems and that plant staff had a low threshold for entering issues into the CAP. This conclusion was based on observation of daily summaries of issues documented in the CAP during the inspection and in discussion with management on the expectation that employees initiate CRs for any reason. Site management was actively involved in the CAP and focused appropriate attention on significant plant issues. The inspectors observed that trending was generally effective in monitoring equipment performance.
During plant walkdowns the NRC inspectors identified several minor issues that were not previously identified by operators or system engineers during routine rounds and system walkdowns. Examples included general corrosion of AFW pipes, insulation damage, incidental acid deposits on two 4B battery cells, and several minor housekeeping issues.
The issues were subsequently evaluated by the licensee and determined not to have a current adverse impact on reliability of equipment.
NRC inspectors identified several discrepancies associated with PMs scheduled past their due date. These discrepancies were due to the licensees use of PM scheduling tool LCP.net. Approximately 3300 PMs were aligned via LCP.net, including some 1500 PMs without a current next required due date (first performance). Many current existing PMs were affected. Although the intent of assigining new due/late dates by LCP.net was to schedule and perform the rescheduled PMs prior to their original date, there was no physical barrier in place to prevent performance of any of the effected PMs past their original late date. The significance is that there is potential for equipment failures/deficiencies due to those delayed PMs. However, the team did not identify any failures or deficiencies associated with PMs scheduled past their due date. As part of the immediate corrective actions the licensee performed a review and evaluated the rescheduled dates to determine if the rescheduled due dates were appropriate. Dates that were determined to be inappropriate were returned to their original due date based on the engineering review.
Prioritization and Evaluation of Issues
The inspectors concluded that problems were prioritized and evaluated in accordance with the licensees CAP procedures. Each CR was assigned a priority level using station procedures.
The team determined that station personnel had conducted root cause and apparent cause analyses in compliance with the licensees CAP procedures and assigned cause determinations were appropriate, considering the significance of the issues being evaluated. A variety of formal causal-analysis techniques were used depending on the type and complexity of the issue consistent with 0-ADM-059, Root Cause Evaluation.
The team determined that, generally, the licensee had performed evaluations that were technically accurate and of sufficient depth. The team further determined that operability, reportability, and degraded or non-conforming condition determinations had been completed consistent with the guidance contained in Procedures are PI-AA-01, Corrective Action Program and Condition Reporting, PI-AA-204, Condition Identification and Screening Process, and PI-AA-205, Condition Evaluation and Corrective Actions.
The use of operating experience was appropriate and obvious in cause evaluations.
Effectiveness of Corrective Actions
Based on a review of corrective action documents, interviews with licensee staff, and verification of completed corrective actions, the team determined that overall, corrective actions were timely, commensurate with the safety significance of the issues, and effective, in that conditions adverse to quality were corrected and non-recurring. For significant conditions adverse to quality, the corrective actions directly addressed the cause and effectively prevented recurrence in that a review of performance indicators, CRs, and effectiveness reviews demonstrated that the significant conditions adverse to quality had not recurred. Effectiveness reviews for corrective actions to prevent recurrence (CAPRs) were sufficient to ensure corrective actions were properly implemented and were effective.
- (3) Findings
i.
Inadequate Procedure Implementation Resulted in Snubber Failure
Introduction:
A green NRC identified Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for failing to implement procedures during a visual inspection of safety-related seismically-qualified snubber SN-4-1039. The licensee failed to identify missing, detached, loosened support items or full thread engagement of all mechanical connections as prescribed in procedure 0-OSP-105.1, Visual Inspection, Removal and Reinstallation of Mechanical Shock Arrestors that led to a snubber failure.
Description:
On October 11, 2008, during a Unit 4 Containment Leak Inspection walkdown as part of a plant shutdown, snubber SN-4-1039 was found to be detached from its transition piece on the 4C steam generator main steam line. The licensee entered Technical Specification 3.7.6 action statement for an inoperable snubber and replaced the inoperable snubber within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. On April 22, 2008, the snubber had been inspected during a visual ASME code VT-3 inspection using procedure 0-OSP-105.1. Section 7.2.1.3.d of 0-OSP-105.1, stated visually inspect snubber for missing, detached, loosened support items, verify full thread engagement of all mechanical connections and weld integrity. During inspection the examiner failed to identify any missing, detached or loosened support items, or disengagement of any mechanical connections. As a result, the snubber had an improperly fastened connection that eventually allowed the snubber cylinder to become detached from its transition piece.
The NRC determined that the instruction in 0-OSP-105.1 was sufficient for a VT-3 qualified inspector to verify proper engagement of all mechanical connections. The licensee implemented immediate corrective actions which included adding specific instructions in procedure 0-OSP-105.1; to specifically inspect the locking ring and correct installation; and to include emphasis on FPL expectations from vendor provided snubber inspection services. The licensee documented this in condition reports CR 2008-31372 and CR 2010-13596.
Analysis:
The failure to identify missing, detached, loosened support items or full thread engagement of all mechanical connections as prescribed in procedure 0-OSP-105.1, that led to a snubber failure was a performance deficiency. The performance deficiency was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone in that the licensee did not ensure reliability of the snubber to respond to initiating events to prevent undesirable consequences in that the snubber would not have been able to perform its design function to arrest shocks of the main steam piping to the C Steam Generator during seismic events or transients. The inspectors evaluated the finding using NRC Inspection Manual 0609, Attachment 0609.04, SDP Phase 1 Screening and Characterization of Findings. The finding was determined to be of very low safety significance because the loss of the snubber during the seismic or transient event it was intended to mitigate would not have caused a plant trip and would not have degraded one or more trains that support a safety system or function. This finding was reviewed for cross-cutting aspects and none were identified.
Enforcement:
10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
The licensee meets this requirement by implementing procedure 0-OSP-105.1, Visual Inspection, Removal and Reinstallation of Mechanical Shock Arrestors. Contrary to the above, on April 22, 2008, the licensee failed to accomplish an activity affecting quality in accordance with applicable procedures, specifically, operating procedure 0-OSP-105.1 was not adequately implemented during a visual inspection of safety related seismically qualified snubber SN-4-1039. The licensee failed to identify missing, detached, loosened support items, or full thread engagement of all mechanical connections as prescribed in procedure 0-OSP-105.1, that resulted in snubber failure. Because the failure to comply with 10 CFR 50, Appendix B, criterion V, is of very low safety significance and has been entered into the licensees corrective action program as CR 2008-31372 and CR 2010-13596, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000250/2010-006-01, Inadequate Procedure Implementation Resulted in Snubber Failure.
b.
Assessment of the Use of Operating Experience (OE)
- (1) Inspection Scope
The team examined the licensees use of industry operating experience to assess the effectiveness of how external and internal operating experience data was used to prevent similar or recurring problems at the plant. In addition, the team selected operating experience documents (e.g., NRC generic communications, 10 CFR Part 21 reports, licensee event reports, and plant internal operating experience items), which had been issued since 2008 to verify whether the licensee had appropriately evaluated each notification for applicability to the Turkey Point plant, and whether issues identified through these reviews were entered into the CAP. The inspectors checked if operating experience was appropriately incorporated into cause evaluations and integrated into plant operations through pre-job briefs and other activities. Documents reviewed are listed in the Attachment.
- (2) Assessment
Based on observations of activities and interviews with station personnel and a review of documentation related to operating experience issues, the team determined that the licensee was effective in screening operating experience for applicability to the plant.
OE issues requiring action (e.g., Part 21 reports) were entered into the CAP for evaluation, tracking, and closure. In addition, operating experience was included in apparent cause and root cause evaluations in accordance with licensee procedures. OE was evident in plant operations activities, such as pre-job briefings and turnover meetings.
- (3) Findings
No findings of significance were identified.
c.
Assessment of Self-Assessments and Audits
- (1) Inspection Scope
The team reviewed the licensees audit and self-assessment reports, including those which focused on problem identification and resolution, to assess if the licensee was identifying problems at an appropriately low threshold and to verify that problems identified through those activities were entered into the CAP and prioritized for resolution in accordance with licensee procedures. The team verified that recommendations from self-assessments reviewed had been entered into the CAP, evaluated, and verified that actions had been completed consistent with those evaluations.
- (2) Assessment
The team determined that the scopes of assessments and audits were technically sound and appropriate. Self-assessments were generally detailed and critical. Condition reports were created to document the results and associated recommendations from the final reports. The team also determined that the licensee had adequately prioritized self-assessment and audit issues entered into the CAP.
- (3) Findings
No findings of significance were identified.
d.
Assessment of Safety Conscious Work Environment
- (1) Inspection Scope
The inspectors assessed the stations safety conscious work environment (SCWE)through review of the stations Employee Concern Program (ECP), discussions with coordinators of the ECP, interviews with personnel from various station departments, and reviews of station performance indicators. The inspectors checked the status of FPLs evaluation and actions related to improving the corporate safety culture, including upgrades to the Employee Concerns Program.
- (2) Assessment
The inspectors found that individuals remained aware of the processes available to raise safety issues and that no reluctance to raise safety concerns was identified.
Improvements to the employee concerns program and initiatives to improve the FPL safety culture were proceeding.
The inspectors found, through interviews with site workers, that they were willing to raise nuclear safety concerns, had initiated CAP items, and had been involved in the safety culture surveys. Interviews also revealed that plant workers were knowledgeable of the various available methods for raising nuclear safety concerns. Furthermore, the workers communicated recent improvement in station supervisions support of the workers raising issues. None of the workers indicated that their co-workers or they had been retaliated against for raising safety concerns.
The inspectors met with the station ECP coordinator. The ECP coordinator indicated activities that would facilitate more awareness and understanding of the ECP including introducing the program with onsite staff and contractor groups at departmental meetings. Furthermore, the ECP office had been recently relocated within the plant protected area and procedures had been developed for uptake of concerns and management of concern resolution. The new process required closeout of the concern with the concerned individual, typically in a face-to-face meeting.
- (3) Findings
No findings of significance were identified.
4OA6 Meetings, Including Exit
On May 21, 2010, the inspectors provided the results of the inspection to Mr. P. Rubin and other members of the site staff. On June 28, 2010 a re-exit was completed per phone call to discuss the final resolution of the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.
4OA7 Licensee Identified Violations
The following violation of very low safety significance (Green) was identified by the licensee and constituted a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation.
- Technical Specification 6.8.1 requires that procedures required by the Florida Power and Light Quality Assurance Topical Report (QATR) be implemented. The QATR includes procedures listed in Appendix A of NRC Regulatory Guide 1.33 Revision 2.
Contrary to the above, on November 26, 2009, during PMT of the New Analog Rod Position Indication System (NARPI), the control room received indication that the H6 and H10 control rods dropped from the fully withdrawn position and did not enter the required off-normal procedure ONOP-28.3, Dropped RCC, when the two control rods (H6 and H10) were confirmed to be dropped during the Unit 4 Outage. The licensee eventually entered the procedure when directed by management and tripped the reactor as required by the procedure. The non-compliance was identified by the licensee following issuance of LER 2010-001-0 on January 25, 2010, and entered into the corrective action process. During the post modification test Unit 4 was in Mode 3 (Hot Standby) and was borated such that all control rods could be withdrawn and the reactor would not go critical, eliminating any safety concern with two dropped control rods. The issue was screened to be of very low safety significance (Green). The issue was documented in condition report 2010-3782 and additional corrective actions were identified. Because the licensee identified the issue and documented it in their corrective action program and because the finding is of very low safety significance, this violation is being treated as a licensee-identified NCV consistent with Section VI.A of the NRC Enforcement Policy.
ATTACHMENT: SUPPPLEMENTAL INFORMATION
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- L. Bandel, Performance Improvement
- R. Coffey, Maintenance Manager
- M. Crosby, Quality Assurance
- R. Everett, Licensing
- E. Fisher, Work Control
- J. Garcia, Engineering
M. Guth Engineering
- J. Herrera, Performance Improvement
- K. Mohindroo, Engineering
- P. Rubin, Plant Manager
- J. Shafer, Health Physics
- S. Shaffer, Assistant Operations Manager
B. Stamp Operations
- B. Tomonto, Licensing Manager
- M. Wayland, Work Control Manager
NRC
- S. Stewart, SRI Turkey Point
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000250&251/2010-006-01 NCV
Inadequate procedure implementation resulting in snubber failure.