IR 05000335/2012002
| ML12117A005 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/26/2012 |
| From: | Rich D NRC/RGN-II/DRP/RPB3 |
| To: | Nazar M Florida Power & Light Co |
| References | |
| IR-12-002 | |
| Download: ML12117A005 (37) | |
Text
UNITED STATES ril 26, 2012
SUBJECT:
ST. LUCIE NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000335/2012002 AND 05000389/2012002
Dear Mr. Nazar:
On March 31, 2012, the US Nuclear Regulatory Commission (NRC) completed an inspection at your St. Lucie Nuclear Plant Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on April 5, 2012, with Mr. Anderson 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.
This report documents one self-revealing finding of very low safety significance (Green).
This finding was determined to involve a violation of NRC requirements and is being treated as a non-cited violation, consistent with the NRC Enforcement Policy. If you contest this non-cited violation, 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 20555-0001; 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 Inspector at the St. Lucie Nuclear Power Plant.
If you disagree with a cross-cutting aspect assignment 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 II; and the NRC Resident Inspector at the St. Lucie Nuclear Power Plant.
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
FPL 2 of NRCs document system (ADAMS). ADAMS is accessible from the NRC Website 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 Nos. 50-335, 50-389 License Nos. DPR-67, NPF-16
Enclosure:
Inspection Report 05000335/2012002, 05000389/2012002 w/Attachment: Supplemental Information
___ML12117A005_____________ X SUNSI REVIEW COMPLETE X FORM 665 ATTACHED OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS RII:DRS SIGNATURE MGD1 GJW TLH4 by email RJR1 by email DJones for REW1 by email GKO by email NAME MDonithan GWilson THoeg RReyes JHamman RWilliams GOttenberg DATE 04/16/2012 04/18/2012 04/19/2012 04/19/2012 04/16/2012 04/18/2012 04/17/2012 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE RII:DRS RII:DRS HQ:NSIR RII:DRP SIGNATURE AJB1 by email TXS2 by email JXL1 by email DWR1 NAME AButcavage TSu JLaughlin DRich DATE 04/18/2012 04/17/2012 04/16/2012 04/25/2012 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
FPL 3
REGION II==
Docket Nos: 50-335, 50-389 License Nos: DPR-67, NPF-16 Report No: 05000335/2012002, 05000389/2012002 Licensee: Florida Power & Light Company (FP&L)
Facility: St. Lucie Nuclear Plant, Units 1 & 2 Location: 6351 South Ocean Drive Jensen Beach, FL 34957 Dates: January 1 to March 31, 2012 Inspectors: T. Hoeg, Senior Resident Inspector R. Reyes, Resident Inspector D. Jones, Senior Reactor Inspector (1R17)
J. Hamman, Reactor Inspector (1R17)
R. Williams, Reactor Inspector (1R17)
G. Ottenberg, Resident Inspector (Oconee) (1R17)
A. Butcavage, Reactor Inspector (In-training) (1R17)
T. Su, Reactor Inspector (In-training) (1R17)
J. Laughlin, Emergency Preparedness Inspector (NSIR) (1EP4)
Approved by: D. Rich, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000335/2012-002, 05000389/2012-002; 01/01/2012 - 03/31/2012; St. Lucie Nuclear
Plant, Units 1 & 2; Identification and Resolution of Problems.
The report covered a three month period of inspection by resident inspectors and region based inspectors. The significance of most findings is identified by their color (Green, White,
Yellow, Red) using IMC 0609, Significance Determination Process (SDP); the cross-cutting aspect was determined using IMC 305, Operating Reactor Assessment Program; and 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.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
- Green.
A Green, self-revealing, non-cited violation (NCV) of Technical Specification (TS) 6.8.1 was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978, including safety related activities carried out during operation of the reactor plant. Licensee surveillance test procedure 2-OSP-63.01, Unit 2 RPS Logic Matrix Test, was not complied with as written when a Reactor Protection System (RPS) logic matrix switch was inadvertently placed out of position resulting in an unplanned reactor trip. The licensee entered this violation in their corrective action program as condition report 1657802.
The licensees failure to fully implement RPS testing procedure 2-OSP-63.01, Unit 2 RPS Logic Matrix Test, as written is a performance deficiency. The finding was determined to be of more than minor significance because it resulted in a reactor trip and is similar to NRC Manual Chapter 0612 Appendix E, example 4.b. The inspectors evaluated the risk of this finding using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. The inspectors determined that the finding was of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available.
The finding involved the cross-cutting area of human performance, in the component of work practices and the aspect of procedural compliance (H.4.b), in that the licensee failed to ensure that personnel followed procedure requirements to prevent unexpected results. (Section 4OA2.2)
Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
Unit 2 operated at full Rated Thermal Power (RTP) during this entire inspection period. At the start of the inspection period Unit 1 was shut down for a scheduled refueling outage. Unit 1 entered Mode 2 and was manually tripped on March 18 due to a rod control malfunction.
Unit 1 entered Mode 2 on March 28 and was manually tripped on March 28 during physics testing in accordance with procedural requirements. Unit 1 entered Mode 2 and Mode 1 on March 30 and was manually tripped on March 31 due to a steam bypass control system malfunction.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity (Reactor-R)
1R01 Adverse Weather Protection
.1 Seasonal Winter Weather Conditions
a. Inspection Scope
During the week of January 3, the inspectors reviewed the status of licensee actions in accordance with ADM-04.03, Cold Weather Preparations, for winter weather conditions. The inspectors verified conditions were met for entering the subject procedure and that equipment status was verified as directed by the procedure. The inspectors performed a walk down of the following safety-related equipment on both units that are exposed to outside weather conditions to identify any potential adverse conditions. Condition reports (CRs) were reviewed to assure that the licensee was identifying and resolving weather-related issues.
- Unit 1B emergency diesel generator (EDG) room
- Unit 1 refueling water tank (RWT) area
- Unit 2 RWT area
- Unit 2, 2A, 2B, and 2C auxiliary feed water pump areas
- Unit 1 spent fuel pool
b. Findings
No findings were identified.
.2 Impending Adverse Weather Conditions
a. Inspection Scope
On February 14 and 15, the inspectors reviewed the overall preparations of the licensee for an overnight weather forecast of freezing temperatures. The inspectors verified conditions were established for the onset of freezing temperatures, which included placement of temporary heaters around equipment affected by low temperatures. The inspectors reviewed compensatory measures put in place or expected to be put in place during the forecasted freezing temperatures while considering equipment controls, area accessibility, and system indications. The inspectors performed a walk down of the following areas:
- Unit 2, A and B main feed pump area
- Unit 2, A and B EDG engine rooms
- Unit 2, A, B, and C auxiliary feed water pump rooms
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial Equipment Walk downs
a. Inspection Scope
The inspectors conducted four partial alignment verifications of the safety-related systems listed below. These inspections included reviews using plant lineup procedures, operating procedures, and piping and instrumentation drawings, which were compared with observed equipment configurations to verify critical portions of the systems were correctly aligned to support operability. The inspectors also verified the licensee had identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers by entering them into the corrective action program (CAP).
- 1A intake cooling water (ICW) pump and header train while the 1B ICW train was out of service
- 2A ICW pump and header while 2B high pressure safety injection (HPSI) pump, 2B containment spray (CS) pump, 2B component cooling water (CCW) heat exchanger and 2B ICW header were OOS
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Fire Area Walk downs
a. Inspection Scope
The inspectors toured the following four plant areas during this inspection period to evaluate conditions related to control of transient combustibles and ignition sources, and the material condition and operational status of fire protection systems including fire barriers used to prevent fire damage or fire propagation. The inspectors reviewed these activities against provisions in the licensees procedure AP-1800022, Fire Protection Plan, and 10CFR50, Appendix R. The licensees fire impairment lists, updated on an as-needed basis, were routinely reviewed. In addition, the inspectors reviewed the CAP database to verify that fire protection problems were being identified and appropriately resolved. The following areas were inspected:
- Unit 2 charging pump rooms in the reactor auxiliary building (-0.5 foot elevation)
- Unit 1 spent fuel pool heat exchanger room (19.5 foot elevation)
- Unit 2A and 2B high head, low head and containment spray pump areas
- Unit 1 main steam code safety valve enclosure area
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
On March 29 the inspectors observed an announced fire drill that took place in the main work area of the carpenter shop. The drill was observed to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the de-brief, and took appropriate corrective actions as required. Specific attributes evaluated were:
- (1) proper wearing of turnout gear and self-contained breathing apparatus;
- (2) proper use and layout of fire hoses;
- (3) employment of appropriate fire fighting techniques;
- (4) sufficient fire-fighting equipment brought to the scene; (5)effectiveness of command and control;
- (6) search for victims and propagation of the fire into other plant areas;
- (7) smoke removal operations;
- (8) utilization of pre-planned strategies;
- (9) adherence to the pre-planned drill scenario; and
- (10) drill objectives.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors interviewed engineering personnel responsible for the end of cycle evaluation and monitoring of the 1B CCW heat exchanger activities, and for the mid-cycle evaluation and monitoring of the 2A and 2B CCW heat exchangers. The inspectors reviewed the as-found heat exchanger conditions on both the inlet and outlet side of the heat exchanger that used sea water. The inspectors verified the licensee adequately completed re-tubing of the 1B heat exchanger as a result of the eddy current tests and as required by the licensees heat exchanger re-tubing procedures. The inspectors verified that periodic maintenance activities were conducted in accordance with licensee procedure 0-PMM-14.01, CCW Heat Exchanger Clean and Repair. The inspectors reviewed the monitoring and trending of heat exchanger performance data and verified the operational readiness of the system should it be needed for accident mitigation. The inspectors walked down portions of the system for signs of degradation and to assess overall material condition, as well as to monitor system parameters for proper operation. The inspectors completed an as-left inspection of the 1B and 2A heat exchangers and verified new anodes had been installed as required by the licensees maintenance program. The inspectors verified that significant heat sink issues were being identified and entered into the CAP.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
Resident Inspector Quarterly Review
a. Inspection Scope
On March 29 the inspectors observed and assessed licensed operator actions during a simulated feedwater control malfunction and subsequent reactor trip training exercise. The operator training was conducted in accordance with St. Lucie training document PSL OPS 0914037, Feedwater Control Malfunctions with Loss of Feed, Revision 15. The inspectors also reviewed simulator physical fidelity and specifically evaluated the following attributes related to the operating crews 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 off-normal 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
- Effectiveness of the post-evaluation critique
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed system performance data and associated condition reports for the two systems listed below to verify the licensees maintenance efforts met the requirements of 10CFR50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, and licensee procedure ADM-17.08, Implementation of 10CFR50.65, Maintenance Rule. The inspectors efforts focused on maintenance rule scoping, characterization of maintenance problems and failed components, risk significance, determination of a(1) and a(2) classification, corrective actions, and the appropriateness of established performance goals and monitoring criteria. The inspectors also interviewed responsible engineers and observed some of the corrective maintenance activities. The inspectors also attended applicable expert panel meetings and reviewed associated system health reports. The inspectors verified that equipment problems were being identified and entered into the licensees CAP.
- Unit 1 Component Cooling Water System
- Unit 2 Control Room Heating and Ventilation System
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors completed in-office reviews, plant walk downs, and control room inspections of the licensees risk assessment of six emergent or planned maintenance activities. The inspectors verified the licensees risk assessment and risk management activities using the requirements of 10CFR50.65(a)(4); the recommendations of Nuclear Management and Resource Council 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 3; and licensee procedure ADM-17.16, Implementation of the Configuration Risk Management Program. The inspectors also reviewed the effectiveness of the licensees contingency actions to mitigate increased risk resulting from degraded equipment. The inspectors interviewed responsible Senior Reactor Operators on-shift, verified actual system configurations, and specifically evaluated results from the online risk monitor (OLRM) for the combinations of OOS risk significant systems, structures, and components (SSCs) listed below:
- Unit 2, ultimate heat sink barrier valves SB31-1 and SB31-2, 2B startup transformer, and 1B EDG OOS
- Unit 2, 2A HPSI pump, 2A CS pump, 2A CCW pump and heat exchanger, 2A ICW header, and A-train containment fan coolers OOS
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed the following seven action request (AR) interim dispositions and operability determinations to ensure that operability was properly supported and the affected SSCs remained available to perform their safety function with no increase in risk. The inspectors reviewed the applicable Updated Final Safety Analysis Report (UFSAR), and associated supporting documents and procedures, and interviewed plant personnel to assess the adequacy of the interim disposition.
- AR 1712847, 2B1 Emergency Diesel Generator Immersion Heater Failure
- AR 1718476, 1A Intake Cooling Water Discharge Header Degradation
- AR 1728975, 1B LPSI Pump Inboard Seal Overheated During Code Run
- AR 1729572, Unit 2 Feed Water Regulating Valve Position Indicator
- AR 1731750, Chemistry Samples Missed on Emergency Diesel Fuel Oil Tanker
- AR 1735681, 1B Emergency Diesel Generator Fan Belt Debris
- AR 1739338, 1B LPSI Pump Leakage After Replacement of Mechanical Seal
b. Findings
No findings were identified
1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed selected samples of evaluations to confirm the licensee had appropriately considered the conditions under which changes to the facility, UFSAR, or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for six changes and additional information, such as drawings, calculations, supporting analyses, the UFSAR, and TS to confirm the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed in the List of Documents Reviewed.
The inspectors reviewed samples of changes for which the licensee had determined that evaluations were not required to confirm that the licensees conclusions to screen out these changes were correct and consistent with 10CFR50.59. The sixteen screened out changes reviewed are listed in the List of Documents Reviewed.
The inspectors evaluated engineering design change packages for five material, component, and design based modifications to evaluate the modifications for adverse effects on system availability, reliability, and functional capability. The five modifications are as follows:
- EC 249195, HVS-4B Breaker Setting Change
- EC 236026, PC/M 09072, Replacement of Containment Spray Header Isolation Valves MV-07-3 & MV-07-4
- EC 271161, Replace V3113 With Suitable Equivalent
- EC 272094, Unit 2 HCV-14-11A1/A2/B1/B2 Excessive Closing Force
- EC 235858, PCM-08019 PSL-1 Inconel A600 PWSCC Mitigation in RCS Hot Leg Connected Piping Welds Documents reviewed included procedures, engineering calculations, modification design and implementation packages, work orders, site drawings, corrective action documents, applicable sections of the UFSAR, supporting analyses, TS, and design basis information. The inspectors additionally reviewed test documentation to ensure adequacy in scope and conclusion. The inspectors review was also intended to verify all appropriate details were incorporated in licensing and design basis documents and associated plant procedures.
The inspectors also reviewed selected condition reports and the licensees recent self-assessment associated with modifications and screening/evaluation issues to confirm that problems were identified at an appropriate threshold, and were entered into the corrective action process, and appropriate corrective actions had been initiated and tracked to completion.
b. Findings
No findings were identified.
1R18 Plant Modifications
Baseline Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed the following two permanent plant modifications. Each modification was performed in accordance with licensee procedures EN-AA-205-1100, Design Change Packages and QI-3-PSL-1, Design Control.
The inspectors reviewed the 10CFR50.59 screening and evaluations, fire protection reviews, environmental reviews, and license renewal reviews as applicable, to verify the modification had not affected system operability and availability. The inspectors reviewed associated plant drawings and UFSAR sections impacted by the modification and discussed the changes with licensee personnel to verify that installation was consistent with the modification documents. The inspectors walked down accessible portions of the modifications to determine if they were installed in the field as described in the Engineering Change (EC) documents. Additionally, the inspectors verified that problems associated with modifications were being identified and entered into the CAP.
- EC 275040, Unit 1 Intake Cooling Water Buried Discharge Piping Replacement
b. Findings
No findings were identified.
1R19 Post Maintenance Testing
.1 Baseline Testing
a. Inspection Scope
For the six Post Maintenance Tests (PMTs) associated with the maintenance listed below, the inspectors reviewed the test procedures and either observed the testing or reviewed test records to determine whether the scope of testing adequately verified that the work performed was correctly completed and demonstrated that the affected equipment was functional and operable. The inspectors verified that the requirements of licensee procedure ADM-78.01, Post Maintenance Testing, were incorporated into test requirements. The inspectors reviewed the following work orders (WOs):
- WO 38021231, 1B EDG K54 relay replacement
- WO 40006385, 1A EDG engine overhaul
- WO 40009967, Unit 1 HPSI Pump maintenance
- WO 40120579, 1A ICW pump maintenance
- WO 40134013, Unit 1B ICW discharge header permanent modification
- WO 40139405, Unit 2 Feed Water Regulating Valve 9021B maintenance
b. Findings
No findings were identified.
.2 Extended Power Uprate Modifications Inspection Procedure (IP) 71004
a. Inspection Scope
For the two PMTs associated with the maintenance listed below, the inspectors reviewed the test procedures and either witnessed the testing and or reviewed test records to determine whether the scope of testing adequately verified that the work performed was correctly completed and demonstrated that the affected equipment was functional and operable. The inspectors verified that the requirements of licensee procedure ADM-78.01, Post Maintenance Testing, were incorporated into test requirements. The inspectors reviewed the following WOs:
- WO 40049782 Task 2, 1A Containment Spray Pump Min-flow Piping Modification EC 250013-M-220
- WO 40065765 Task 2, 1B Containment Spray Pump Min-flow Piping Modification EC 250013-M-219
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
Unit 1 Refueling Outage SL1-24
a. Inspection Scope
Outage Planning, Control and Risk Assessment During daily outage planning activities by the licensee, the inspectors reviewed the risk reduction methodology employed by the licensee during various refueling outage (RFO) SL1-24 meetings including Outage Control Center (OCC) morning meetings, Operations Daily Team Meetings, and Schedule Performance Update Meetings. The inspectors examined the licensee implementation of shutdown safety assessments during SL1-24 in accordance with procedure 0-AP-010526, Outage Risk Assessment and Control, to verify whether a defense in depth concept was in place to ensure safe operations and avoid unnecessary risk. In addition, the inspectors regularly monitored outage planning and control activities in the OCC, and interviewed responsible OCC management during the outage to ensure system, structure, and component configurations and work scope were consistent with TS requirements, site procedures, and outage risk controls.
Monitoring of Shutdown Activities The inspectors performed walk downs of important systems and components used for decay heat removal from the spent fuel pool during the shutdown period including the intake cooling water system, component cooling water system, and spent fuel pool cooling system.
Outage Activities The inspectors examined outage activities to verify they were conducted in accordance with TS, licensee procedures, and the licensees outage risk control plan.
Some of the more significant inspection activities accomplished by the inspectors were as follows:
- Walked down selected safety-related equipment clearance orders
- Verified operability of RCS pressure, level, flow, and temperature instruments during various modes of operation
- Verified electrical systems availability and alignment
- Verified shutdown cooling system and spent fuel pool cooling system operation
- Evaluated implementation of reactivity controls
- Reviewed control of containment penetrations
- Examined foreign material exclusion (FME) controls put in place inside containment (e.g., around the refueling cavity, near sensitive equipment and RCS breaches) and around the spent fuel pool (SFP)
- Verified workers fatigue was properly managed.
Refueling Activities and Containment Closure The inspectors witnessed selected fuel handling operations being performed according to TS and applicable operating procedures from the main control room, refueling cavity inside containment, and the SFP. The inspectors also examined licensee activities to control and track the position of each fuel assembly. The inspectors evaluated the licensees ability to close the containment equipment, personnel, and emergency hatches in a timely manner per procedure 2-MMP-68.02, Containment Closure.
Heat-up, Mode Transition, and Reactor Startup Activities The inspectors examined selected TS, license conditions, license commitments and verified administrative prerequisites were being met prior to mode changes. The inspectors also reviewed measured RCS leakage rates, and verified containment integrity was properly established. The inspectors performed a containment sump closeout inspection prior to reactor plant start up and conducted a containment walk down while Unit 1 was at normal operating pressure and temperature. The inspectors discussed the results of low power physics testing with Reactor Engineering and Operations personnel to ensure core operating limit parameters were consistent with the design. The inspectors witnessed portions of the RCS heat up, reactor startup, and power ascension in accordance with the following plant procedures:
- PTP 1-3200088, Unit 1 Initial Criticality Following Refueling
- 1-GOP-302, Reactor Startup Mode 3 to Mode 2
- 1-GOP-201, Reactor Plant Startup Mode 2 to Mode 1 Corrective Action Program The inspectors reviewed CRs generated during SL1-24 to evaluate the licensees threshold for initiating CRs. The inspectors reviewed CRs to verify priorities, mode holds, and significance levels were assigned as required. Resolution and implementation of corrective actions of several CRs were also reviewed for completeness. The inspectors routinely reviewed the results of Quality Assurance (QA) daily surveillances of outage activities.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed test results or observed performance of the following eight surveillance tests to verify the tests met the TS, the UFSAR, the licensees procedural requirements, and demonstrated the systems were capable of performing their intended safety functions and their operational readiness. In addition, the inspectors evaluated the effect of the testing activities on the plant to ensure that conditions were adequately addressed by the licensee staff and that after completion of the testing activities, equipment was returned to the positions/status required for the system to perform its safety function. The tests reviewed included one in-service test (IST) and one containment isolation valve local leak rate surveillance. The inspectors verified that surveillance issues were documented in the CAP.
- 0-OSP-37.01, Emergency Cooling Water Canal Periodic IST
- 2-OSP-59.01B, 2B Emergency Diesel Generator Fast Start
- 2-OSP-07.04A, 2A Containment Spray Pump and 2A Hydrazine Pump Code Run
- 1-OSP-68.02, Local Leak Rate Test, Penetration 31, Containment Isolation Valves V6554 and V6555
- 1-OSP-03.16B, 1B Low Pressure Safety Injection Pump Comprehensive Flow Test
- 1-OSP-69.13B, Engineered Safety Features 18 Month Surveillance Test
- 2-OSP-07.04B, 2B Containment Spray Pump Code Run
- 2-OSP-01.03, Reactor Coolant System Inventory Balance
b. Findings
No findings were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) located under ADAMS accession number ML12009A021 as listed in the Attachment.
The licensee transmitted these procedure revisions to the NRC pursuant to the requirements of 10 CFR 50, Appendix E, Section V, Implementing Procedures. 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
.
b. Findings
No findings were identified.
OTHER ACTIVITIES (OA)
4OA1 Performance Indicator (PI) Verification
.1 Initiating Events and Mitigating Systems Cornerstones
a. Inspection Scope
The inspectors reviewed licensee submittals for the performance indicators (PIs)listed below for the period January 1, 2011, thru December 31, 2011, to verify the accuracy of the PI data reported during that period. Performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures ADM-25.02, NRC Performance Indicators, and NAP-206, NRC Performance Indicators, were used to check the reporting for each data element. The inspectors checked operator logs, plant status reports, condition reports, system health reports, and PI data sheets to verify the licensee had identified the required data, as applicable. The inspectors interviewed licensee personnel associated with performance indicator data collection, evaluation, and distribution.
- Unit 1 Unplanned Scrams per 7000 Critical Hours
- Unit 2 Unplanned Scrams per 7000 Critical Hours
- Unit 1 Unplanned Scrams With Complications
- Unit 2 Unplanned Scrams With Complications
- Unit 1 Unplanned Power Changes per 7000 Critical Hours
- Unit 2 Unplanned Power Changes per 7000 Critical Hours
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Daily Review
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems, and to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a screening of items entered daily into the licensees corrective action program. This review was accomplished by reviewing daily printed summaries of CRs and by reviewing the licensees electronic CR database. Additionally, reactor coolant system unidentified leakage was checked on a daily basis to verify no substantive or unexplained changes. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
.2 Annual Sample: Root Cause Evaluation Associated With the Unit 2 Unplanned
Automatic Reactor Trip During Reactor Protection System Testing
a. Inspection Scope
The inspectors selected AR 1657802, Unit 2 Unplanned Automatic Reactor Trip Event While Performing Reactor Protection System Testing, for a more in-depth review of the circumstances and the corrective actions that followed. On June 6, 2011, Unit 2 was operating at full power when a licensed reactor operator was performing monthly reactor protection system logic matrix testing in the control room when he accidentally tripped the reactor when taking a matrix relay trip select switch to the wrong position. This particular trip event and associated Licensee Event Report is discussed in further detail in section 4OA3 of this inspection report.
The inspectors reviewed the licensees evaluation of the event and the associated corrective actions taken or planned. The inspectors reviewed licensee performance attributes associated with complete and accurate information of the problem, 10 CFR 50.72 reporting requirements, identification of the root and contributing causes, and planning or completion of assigned corrective actions. The inspectors interviewed plant personnel and evaluated the licensees administration of this selected condition report in accordance with their corrective action program as specified in licensee procedures PI-SL-204, Condition Identification and Screening Process, and PI-SL-205, Condition Evaluation and Corrective Action.
b. Findings and Observations
Introduction:
A Green, self-revealing, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978, including safety related activities carried out during operation of the reactor plant. Licensee surveillance test procedure 2-OSP-63.01, Unit 2 RPS Logic Matrix Test, was not complied with as written when an RPS logic matrix switch was inadvertently placed out of position resulting in an unplanned reactor trip.
Description:
On June 6, 2011, Unit 2 was operating at full power while a licensed reactor operator was performing monthly reactor protection system logic matrix testing in the control room when he accidentally tripped the reactor when taking a matrix relay trip select switch to the wrong position. The licensee determined the cause of the event was due to the creation of a human error single point vulnerability in the test methodology resulting from a 1998 procedure revision that required depressing the matrix relay hold spring loaded push button during the entire test which resulted in a circuit trip signal being locked in while rotating the matrix relay trip select switch. As a result, if the switch is rotated past its intended position prior to resetting trip breakers then a trip will occur. The inspectors noted that the licensee identified contributing causes to be human error in part of the operator taking the switch to the wrong position and inadequate problem resolution following similar RPS testing incidents in 1979, 1980, 1984, and 1985. The inspector determined that the human error by the reactor operator when taking the matrix relay trip select switch to the wrong position caused the reactor trip and was not in accordance with RPS testing procedure 2-OSP-63.01, Unit 2 RPS Logic Matrix Test.
Immediate corrective actions for this event included an operations department human performance stand down reinforcing use of human error prevention techniques, reviewed the RPS surveillance procedure to remove the requirement to hold the matrix relay push button during the entire test to eliminate the single error vulnerability, and an extent of condition review. The planned corrective actions are to replace the pushbuttons with a rotary switch design to eliminate the inadvertent trip signal from being locked in when rotating the matrix relay trip select switch. The design change is planned during the next refueling outages scheduled for Unit 1 in 2013 (SL1-25) and Unit 2 in 2012 (SL2-20). The licensee entered this issue into their corrective action program as CR 1657802.
Analysis:
The licensees failure to comply with RPS testing procedure 2-OSP-63.01, Unit 2 RPS Logic Matrix Test was a performance deficiency. The finding was determined to be of more than minor significance because it resulted in a reactor trip and is similar to Manual Chapter 0612 Appendix E, example 4.b. The inspectors evaluated the risk of this finding using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. The inspectors determined that the finding was of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding involved the cross-cutting area of human performance, in the component of work practices and the aspect of procedural compliance (H.4.b), in that, the licensee failed to ensure that personnel followed procedure requirements to prevent unexpected results.
Enforcement:
Unit 2 Technical Specification 6.8.1, Procedures and Programs, requires, in part, that written procedures be implemented covering activities referenced in Regulatory Guide 1.33, Revision 2, dated February 1978, including safety related activities carried out during operation of the reactor plant. Operations Surveillance Procedure 2-OSP-63.01, RPS Logic Matrix Test, step 4.10.3.k, directed that the matrix relay trip select switch be placed in the mid-position between position 2 and 3 in order to reset reactor trip circuit breakers. Contrary to this, the operator moved the switch past the mid-position to position 3 causing a reactor trip. Because the licensee entered the issue into their corrective action program as condition report 1657802 and the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000389/2012002-01, Failure to Follow Reactor Protection System Surveillance Procedure Resulting in Reactor Plant Trip.
.3 Annual Sample: Root Cause Evaluation Associated With the Unit 1 Manual Reactor
Trip Due to a Severe Influx of Jelly Fish into the Intake Structure
a. Inspection Scope
The inspectors selected action request 1679935 for a more in depth review of the circumstances and the corrective actions that followed. On August 22, 2011, an unusually large influx of jellyfish into the combined unit intake structure caused an increase differential pressure across the intake traveling screens on both units. Both units entered their respective circulating water system abnormal operating procedures. Unit 1 initiated a rapid down power as condenser vacuum was decreasing and initiated a manual reactor trip from approximately 90% power. Unit 2 control room operators also started a rapid down power and the units condenser vacuum improved when power was lowered to 70% reactor power where it was maintained.
The inspectors reviewed the licensees evaluation of the event and the associated corrective actions taken or planned. The inspectors reviewed licensee performance attributes associated with complete and accurate information of the problem, 10 CFR 50.72 reporting requirements, identification of the root and contributing causes, and planning or completion of assigned corrective actions. The inspectors interviewed plant personnel and evaluated the licensees administration of this selected condition report in accordance with their corrective action program as specified in licensee procedures PI-SL-204, Condition Identification and Screening Process, and PI-SL-205, Condition Evaluation and Corrective Action.
b. Findings and Observations
No findings were identified. The licensee identified two root causes of this event.
The first root cause described that the intrusion rate of the jellyfish at the intake structure exceeded the design capacity of the intake traveling screens and trash pits.
The second root cause was that the operators response to the initiating events and precursors were not timely and there was a lack of understanding by the station operators regarding the potential for a rapidly escalating jellyfish intrusion rate. The evaluation described that the amount of jellyfish traveling in the intake was not a common event at the St. Lucie site and the equipment and procedures used to control such biological intrusion was not adequate to control the debris from entering the circulating water system. Due to the different location of the intake structures for each unit, Unit 1 was more affected by the jellyfish intrusion. Additionally, as a result of the Unit 1 manual reactor trip, the Unit 2 operators entered the rapid down power procedure sooner and condenser vacuum reactor trip limits were not reached.
The licensees immediate corrective actions included installing a second 5-inch turtle net and additional canal cleaning equipment to better respond to a high rate of jellyfish intrusion, and provide written guidance to address a more rapid plant response to jellyfish intrusion into the intake canal. Long term corrective actions to prevent recurrence included revising the circulating water off normal procedures to require a pre-emptive rapid down power of the affected unit, and implement a design change to both units to upgrade the traveling screens to increase the load carrying capacity and speed of the screens to be able to continue operation during this type of event.
.4 Unit 1 Extended Power Uprate (EPU) Identification and Resolution of Problems (IP
71004)
a. Inspection Scope
The inspectors reviewed selected CAP ARs and CRs generated by the licensee during an extended power uprate project being performed on Unit 1 during a scheduled refueling outage. The inspectors verified that problems were being properly identified, appropriately characterized, and entered into the CAP. The inspectors reviewed corrective action program documents that were issued during the first quarter of 2012, including the following risk significant systems: ICW, CCW, HPSI, CS, and Emergency Core Cooling System (ECCS) Safety Injection Tanks.
Where possible, the inspectors reviewed selected CRs, verified corrective actions were implemented, and attended meetings where CRs were screened for significance to determine whether the licensee was identifying, accurately characterizing, and entering problems into the CAP at an appropriate threshold.
The inspectors conducted plant walk downs of equipment associated with the aforementioned systems and other plant areas to assess the material condition and to look for any deficiencies that had not been previously entered into the CAP.
Control room walk downs were performed to assess new EPU control equipment and instruments were functioning properly and deficiencies were documented in the control room deficiency logs.
The inspectors reviewed site trend reports to determine if the licensee effectively trended identified issues and initiated appropriate corrective actions when adverse trends were identified associated with EPU projects. The inspectors attended various plant meetings to observe management oversight functions of the corrective action process. These included CR screening meetings and Management Review Committee (MRC) meetings.
b. Findings and Observations
No findings were identified. The inspectors determined that the licensee was effective in identifying problems and entering them into the CAP and there was a low threshold for entering issues into the CAP associated with the EPU project. This conclusion was based on a review of the requirements for initiating CRs as described in licensee procedures PI-SL-204, Condition Identification and Screening Process, and PI-AA-205, Condition Evaluation and Corrective Action and the few number of deficiencies identified by inspectors during plant walk downs not already entered into the CAP. Trending was generally effective in monitoring equipment performance.
Site management was actively involved in the CAP and focused appropriate attention on significant plant issues associated with the EPU project.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1 Licensee Event Report Reviews
(Closed) LER 05000389/2011-002-00 and LER 05000389/2011-002-01 (Supplement), Unplanned Automatic Reactor Trip During Reactor Protection System Testing On June 6, 2011, while Unit 2 was operating at full power, a licensed reactor operator was performing monthly reactor protection system logic matrix testing in the control room and accidentally tripped the reactor when inadvertently taking a matrix relay trip select switch to the wrong position. The trip resulted when the operator rotated the reactor protection system matrix relay trip select switch too far past its mid-position which resulted in energizing the associated relay and opening reactor trip circuit breakers. The control element assemblies fully inserted into the core and all safety systems functioned as designed. The licensee determined the root cause of the event was due to creation of a single point human error vulnerability in the test methodology resulting from a 1998 procedure revision that required depressing the matrix relay hold spring-loaded push button with a mechanical device during the entire test which resulted in a circuit trip signal being locked in while rotating the matrix relay trip select switch. As a result, if the selector switch is rotated past its intended position prior to resetting trip breakers then a trip will occur. Corrective actions included immediately performing an operations department human performance stand down to reinforce use of human error reduction tools and revising the associated test procedures to prevent opposing reactor trip breakers from opening if the matrix relay trip select switch is placed in the mid-position in error. The inspectors reviewed the LER and condition report 1657802 that documented the event. A Green finding was documented in Section 4OA2.2 of this report. This LER is closed.
(Closed) LER 05000335/2011-001, Unit 1 Manual Reactor Trip Due to High Condenser Backpressure Caused by Severe Influx of Jellyfish into the Intake Structure This LER documents a manual reactor trip that resulted from a loss of condenser vacuum. A significant influx of jellyfish into the intake structure caused a high traveling screen differential pressure on the 1A2 traveling screen. Subsequently, the traveling screen tripped off and required the 1A2 circulating water pump to be stopped. Condenser vacuum decreased requiring a manual reactor trip. The licensees root cause identified that the jellyfish intrusion rate exceeded the design capacity of the intake structure traveling screen system and associated trash weir pits. Corrective actions included revising the circulating water off normal procedures to start a rapid down power when a jellyfish, sea grass, or intake intrusion event occurs and meets specific criteria relating to traveling screen differential pressure and other intake structure parameters. Additional corrective actions include implementing a design change upgrade to increase the traveling screen capacity to function during large jellyfish and sea grass intrusion events. The inspectors reviewed the LER and condition report 1679935 that documented the event. No findings or violations of NRC requirements were identified. This LER is closed.
.2 Personnel Performance During Unplanned Plant Operations
a. Inspection Scope
The inspectors reviewed personnel performance during and after manual reactor trips on Unit 1 that occurred on March 18 and March 31. The inspectors reviewed plant status, equipment and personnel performance associated with initiation of a manual reactor trip and post trip actions to place the reactor plant in a safe condition. The inspectors reviewed plant strip chart recorders, operator logs, interviewed operators, attended post trip review meetings, and verified emergency operating procedure compliance. The March 18 manual reactor trip was initiated from less than 1 percent reactor power as a result of a rod control malfunction that occurred during reactor core physics testing in Mode 2. The March 31 manual trip was initiated from 10 percent reactor power as a result of a malfunction with the steam bypass control system.
b. Findings
No findings were identified.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period the inspectors conducted observations of security force personnel activities to ensure they were consistent with the licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both 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. Findings
No findings were identified.
.2 Independent Spent Fuel Storage Facility (ISFSI) Walk Down (IP 60855.1)
a. Inspection Scope
On March 26, the inspectors conducted a walk down of the ISFSI controlled access fenced-in cask area per inspection procedure 60855.1, Operation of an ISFSI at Operating Plants. The inspectors observed each cask building temperature indicator and passive ventilation system to be free of any obstruction allowing natural draft convection decay heat removal through the air inlet and air outlet openings. The inspectors observed associated cask building structures to be structurally intact and radiation protection access controls to the ISFSI area to be functional.
b. Findings
No findings were identified.
4OA6 Meetings
Exit Meeting Summary
Resident Inspection The resident inspectors presented the inspection results to Mr. Anderson and other members of licensee management on April 5, 2012. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary information. The licensee did not identify any proprietary information.
ATTACHMENT: SUPPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee personnel:
R. Anderson, Site Vice President N. Bach, Chemistry Manager M. Baughman, Training Manager (Acting)
D. Calabrese, Emergency Preparedness Manager D. Cecchett, Licensing Engineer D. DeBoer, Operations Manger K. Frehafer, Licensing Engineer R. Filipek, Design Engineering Manager J. Hamm, Site Engineering Director M. Haskin, Maintenance Manager J. Heinold, Chemistry Technical Supervisor M. Hicks, Director of Plant Improvement T. Horton, Assistant Ops Manager D. Howard, Design Engineering Supervisor D. Huey, Work Control Manager B. Hughes, Plant General Manager E. Katzman, Licensing Manager J. Kramer, Site Safety Manager R. McDaniel, Fire Protection Supervisor C. Martin, Radiation Protection Manager J. Owens, Performance Improvement Department Manager K. Rydman, Licensing M. Snyder, Site Quality Assurance Manager P. Sullivan, Maintenance Programs Supervisor G. Swider, Systems and Component Engineering Manager T. Young, Security Manager NRC personnel:
D. Rich, Chief, Branch 3, Division of Reactor Projects G. Wilson, Senior Project Engineer, Division of Reactor Projects J. Hanna, Senior Risk Analyst, Division of Reactor Safety LIST OF ITEMS OPENED, CLOSED AND DISCUSSED Opened and Closed 05000389/2012002-01 NCV Failure to Follow Reactor Protection System Surveillance Procedure Resulting in Reactor Plant Trip (Section 4OA2.2)
Closed 05000389/2011-002-00,01 LER Unplanned Automatic Reactor Trip During Reactor Protection System Testing (Section 4OA3.1)05000335/2011-001-00 LER Unit 1 Manual Reactor Trip Due to High Condenser Backpressure Caused by Severe Influx of Jellyfish into the Intake Structure (Section 4OA3.1)
Discussed NONE LIST OF
DOCUMENTS REVIEWED
Condition Reports
469258 1606990 1680371 1727484 1731746
474614 1611010 1715509 1729594 1732020
476765 1619757 1716171 1729825 1733785
2586 1621646 1722246 1729355 1735286
2888 1629366 1723587 1729492 1736593
567686 1632052 1724521 1729594 1739269
593208 1656030 1725304 1730150 1740112
1603677 1656769 1727467 1730604
1606952 1668387 1727474 1731347
1R01 Adverse Weather Protection
OP-AA-102-1002, Seasonal Readiness
1R04 Equipment Alignment
2998-G-078, Unit 2 Safety Injection System Flow Diagram
2998-G-082, 2A Intake Cooling Water Flow Diagram
8770-G-082, 1A Intake Cooling Water Flow Diagram
8770-G-096, 1A Emergency Diesel Generator System
1R05 Fire Protection
ADM-0005728, Fire Protection Training, Qualification and Requalification
ADM-1800022, Fire Protection Plan
AP-2-1800023, Unit 2 Fire Fighting Strategies
1R12 Maintenance Effectiveness
ADM-17.08, Implementation of 10 CFR 50.65, Maintenance Rule
NAP-415, Maintenance Rule Program Administration
SCEG-004, Guideline for Maintenance Rule Scoping, Risk Significant Determination, and
Expert Panel Activities
Unit 1 System Health Report for the Component Cooling Water System
Unit 2 System Health Report for Risk Significant Heating, Ventilation and Air Conditioning
1R13 Maintenance Risk Assessments and Emergent Work Control
OP-AA-104-1007, Online Aggregate Risk
WCG-016, Online Work Management
1R15 Operability Evaluations
EN-AA-203-1001, Operability Determinations and Assessments
1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications
Full Evaluations
EC 236024 (PCM 09070) Emergency Response Data Acquisition and Display System
Replacement (ERDADS)
EC 235824 (PCM 07147) Analog Display System (ADS) Replacement
EC 249654, St. Lucie Unit 2 Cycle 19 Reload
EC 235845, PCM-08004 Qualified Safety Parameter Display System (QSPDS) Replacement
EC 250134, 1-NOP-25.02, Control Containment Pressure Using the Hydrogen Purge System
EC 235858, PCM-08019 PSL-1 Inconel A600 PWSCC Mitigation in RCS Hot Leg Connected
Welds
Screened Out Items
EC 235555 PC/M 06008M, 120VAC Instrument Inverter and Isolimiter Replacement (PSL-1,
Train A)
EC 236133 MSP 10088, Rewiring of Loops P-1100X and P-1100Y
ENG-10088-001, Pressurizer Pressure Ch. P-1100X, Rev 2
ENG-10088-002, Pressurizer Pressure Ch. P-1100X, Rev 2
EC 220690, Replace Unit 2 Valve V3891 with a Flowserve Valve Converted to MSP Ref.
CRN 07127-19262, Rev. 0
EC 235114, PC/M 03129, ICW Drain Valve Addition, Rev. 0
EC 235892, PC/M 08059, 1C AFW Pump Overspeed Trip Circuit Modification, Rev. 0
EC 235842, PC/M 08001, AFW Turbine Mechanical Overspeed Replacement, Rev. 0
EC-DCP 249654,10 CFR 50.59 Applicability Determination/Screening
EC-235114, PCM-03129 ICW Drain Valve Addition
EC 249862, Instrument Bus 2MB Undervoltage Relay Settings
EC 249865, Instrument Bus 2MD Undervoltage Relay Settings
EC 270466, 480V MCC 2B6 Breaker Changes
1-AOP-21.03A, 1A Intake Cooling Water System Header
1-AOP-050.07A, Loss of Degraded Safety Related DC Bus 1A
PCM10017, Containment 1A - CCW System Isolation
Modifications
EC 249195, HVS-4B Breaker Setting Change, Rev 0
PSL-2FSE-08-001, Unit 2 Electrical Coordination Study, Rev 0
EC 236026, PC/M 09072, Replacement of Containment Spray Header Isolation Valves MV-
07-3 & MV-07-4, Rev. 5
EC 271161, Replace V3113 with Suitable Equivalent, Rev. 0
EC 272094, Unit 2 HCV-14-11A1/A2/B1/B2 Excessive Closing Force, Rev. 1, dated 04/28/11
EC 235845, PCM-08004 Qualified Safety Parameter Display System (QSPDS) Replacement
CRN-04201-15899, Change Request Notice for Showing Disabled 94 RP Relay
Calculation NAI-1101-033, LOCA Radiological Analysis with Alternate Source Term, Rev. 3
EC 246557, PCM 10045 - Power Uprate - Hydrogen Purge Containment Pressure Control
System
EC-DCR 249715, Engineering to Revise Drawing 8770-G-083 to Include Locked Closed
Designation
Corrective Action Documents
2008-31947, Air Introduction into CCW System
2009-13750, Track Action Items for PC/M 08004, QSPDS Replacement
2010-4668, St. Lucie Engineering Self-Assessment, Evaluations of Changes, Tests, or
Experiments, and Permanent Plant Modifications
2010-5379, Unexpected Condensation in ERDADS Cabinets
458601, Air Introduction into CCW System
479560, 2006-25490-MV-08-3 Did Not Trip from Local Trip Lever after 2C AFW Run
485624, Received High CCW Surge Tank Alarm
567655, Set Point Requirements for GE NGV Relays In U2 System 49
1643083, Unit 2 HCV-14-11A1/A2/B1/B2 Excessive Closing Force
1654735, Moisture Inspection of ERDADS Cabinets in PSL2 ERDADS Room
1663056, Conduit Seal Degraded 21754F-NB @ ERDADS CAB 1SA-R PSL2
1665440, Damaged Sealant at Conduit 21750H-NB PSL2 ERDADS AB5SB FR
Procedures
1-ARP-01-C22, St. Lucie unit 1, Annunciator Response Procedure, Panel C, Window 22,
Generator Negative Sequence, Rev. 3
1-EOP-99, Appendices / Figures / Tables / Data Sheets, Rev. 46
1-NOP-21.12, Intake Cooling Water System Initial Alignment, Rev. 9
1-AOP-04.01, Fuel Pool Cooling System, Rev. 7
1-OSP-66.03, CEA Drop Time and Position Indication Functional Tests, Rev. 1
104423-TR-005, WSI Work Traveler Nozzle Weld Overlay (WOL) Repair, Rev. 1
2-NOP-03.05, Shutdown Cooling, Rev. 49
2-OSP-07.02A, 2A Containment Spray Pump Safeguards Full Flow Test, Rev. 10
2-OSP-07.02A, 2B Containment Spray Pump Safeguards Full Flow Test, Rev. 10, completed
03/12/11
2-OSP-07.02A, 2A Containment Spray Pump Safeguards Full Flow Test, Rev. 9, completed
09/05/11
2-OSP-03.04B, HPSI Loop 2B Flow Balance Test, Rev. 1, completed 3/5/2011
2-OSP-03.04A, HPSI Loop 2A Flow Balance Test, Rev. 1, completed 3/31/2011
2-OSP-66.03, CEA Drop Time and Position Indication Functional Tests, Rev. 10
ADM-17.11, 10CFR50.59 Screening, Rev. 9
EN-AA-203-1102, Safety Classification, Rev. 1
ENG-QI 2.1, 10CFR50.59 Applicability/Screening/Evaluation, Rev. 12
OP-1-0010125A, Surveillance Data Sheets, Rev. 137
QI-12-PR/PSL-7, Calibration of Installed Plant Instrumentation and Control Equipment,
Rev. 8C
QI-3-PSL-1, Design Control, Rev. 29
Completed Work Orders
38001561-01, Perform Surge Nozzle Weld Overlay, dated 11/15/08
39003363, Perform PMT per PC/M 07147 and CRN 07147-17962, dated 4/30/2011
39005189, Qualified Safety Display System (QSPDS) Replacement
39017165, HCV-1411A1 Calibrate AOV Actuator, dated 1/26/2011
40072760, U2 MV-07-3: Operate and Lubricate (6MOS)
40072762, U2 MV-07-4: Operate and Lubricate (18MOS)
40076235, HCV-14-11A1; Water leak at packing- Flow Scan, dated 5/2/2011
40083143, HCV-14-11A2; Supply Regulator Adjustment (EC 272094), dated 5/2/2011
40083145, HCV-14-11B1; Adjust the Air Supply Regulator (EC 272094), dated 5/2/2011
40083146, HCV-14-11B2; Adjust the Air Supply Regulator (272094), dated 5/2/2011
Calculations
0800024.301, Material Properties for Weld Overlay Repairs, Rev. 2
0800024.302, Weld Overlay Design Weight Calculation, Rev. 0
24-7.6001, Containment Spray System Flow and Pressure Drop, Rev. 0
EC-249862, Mathcad Calculations for Ground Detection Relays for Instrument Bus 2MB
Undervoltage Relay Setting Rev. 0
NSSS-006, Containment Spray System, Rev. 6
PSL-2EJM-73-026, Containment Spray Piping- Discharge Side, Rev. 0
PSL2 FE DSS 2010 0101, Reverse Power Relay Calculation, Rev. 0
PSL-2-F-J-E-90-010, Emergency Diesel Generator 2A & 2B 120/208 VAC Power Panel &
480 Volt Power Panel Load Study, Rev. 5, 11/28/2007
PSL-2FSE-03-010, Unit 2 Electrical System Computer Model (ETAP) Documentation, Rev. 2
9/11/2008
PSL-2FSE-03-011, St. Lucie Unit 2 Short Circuit, Voltage Drop and PSB-1 Analysis, Rev. 1,
2/11/2008
PSL-2FSE-08-001, CCN-5, Unit 2 Electrical Coordination Study, Rev. 0
PSL-BFSM-06-019, Required Thrust for Category 2 AOVs, Rev. 5
PSL-BFSM-06-022, Margin Verification for AOVs, Rev. 6
PSL-ENG-SEIJ-05-009, QSPDS Failure Modes and Effects Analysis, Rev. 0.
PSL-ENG-SEIJ-08-033, Triconex Qualified Safety Parameter Display System (QSPDS)
EMI/RFI Evaluation, Rev. 0
SI Calculation Package-0800024.340, Weld Overlay Sizing for Hot Leg Surge Nozzle, Rev. 1
SI Calculation Package-0800024.340-Addendum 1, Rev. 1
Drawings
0800024.346, SI, Crack Growth Evaluation of Hot Leg Surge Nozzle, Rev. 0
0800024.540, SI Hot Leg Surge Nozzle Weld Overlay Design, Rev. 3
09-56553-02, Double Disc Gate Valve Stainless Steel, Weld Ends, for Limitorque SMB-0-25
Actuator Size: 12 Class: 300, Sheet 1, Rev. B
2998-A-452, Generator & Main Transformer Protection RTGB 201, Sheet 2, Rev. 0, 1, & 2
2998-A-452, St. Lucie Unit 2 Relay Settings, Sheet 3, Rev. 1
2998-B-327, Generator Current Relay, Sheet 880, Rev. 12
2998-B-327, Generator Current Relay, Sheet 881, Rev. 17
2998-B-327, Primary Generator Lockout Relay-1, Sheet 883 Rev. 27
2998-B-327, Generator Control Protection & Monitoring, Sheet 893, Rev. 11
2998-B-327, Instrument Buses & Inverter 2MB & 2MD, Sheet 1010, Rev. 14
2998-B-327, Generator Protection Relay Cabinet and Digital Fault Recorder Interface
Current, Sheet 1113, Rev. 3
2998-B-327 Digital Fault Recorder, Sheet 1114, Rev. 3
2998-B-327, SAS Cabinet 120 VAC Distribution & Grounding System, Sheet 1750, Rev. 1
2998-B-327, Analog Display System Power Distribution, Sheet 1944, Rev. 0
2998-B-335, Power Distr. B Motor Data, Sheet K, Rev. 1
2998-G-078, Safety Injection System, Sheet 130A, Rev. 22
2998-G-078, Safety Injection System, Sheet 130B, Rev. 30
2998-G-078, Safety Injection System, Sheet 131, Rev. 22
2998-G-088, Containment Spray and Refueling Water Systems, Sheet 1, Rev. 44
2998-G-088, Containment Spray and Refueling Water Systems, Sheet 2, Rev. 46
2998-G-332, 480V Miscellaneous, 125VDC and Vital AC One Line, Sheet 2, Rev. 6
405519, WSI, Construction Drawing, Hot Leg Surge, B Loop, St. Lucie U1, Sheet 1 of 2,
Rev. 3, Sheet 2 of 2, Rev. 4
800850, Diagram - Trip System, Rev. A
801043, Diagram - Trip System, Sheet 1, Rev. 0
81-465, 300 L
8770-14084, Edward Forged Steel Univalve Class 1848 Check Valve, Rev. 1
8770-7699R7, Containment Instrument Air Compressor Aftercooler and Air Receiver Outline,
dated 3/9/92
8770-A-452, Relay Setting, Generator & Main Transformers Protection, Sheet 2, Rev. 0
8770-A-452, Relay Setting, Generator Protection Aux. Cabinet, Sheet 3, Rev. 3 & 3A
8770-B-326, Aux FW Pump 1C Turbine and Steam Valve MV-08-3, Sheet 631, Rev. 12 & 13
8770-G-083, Flow Diagram Component Cooling System, Sheet 1B, Rev. 60
8770-G-085, Flow Diagram Instrument Air System, Sheet 2A, Rev. 39
8770-G-085, Flow Diagram Instrument Air System, Sheet 4B, Rev. 31
8770-G-085, Flow Diagram Instrument Air System, Sheet 48, Rev. 31
8770-G-799, Rector Building Pipe Restraints, Sheet 20, Rev. 1
8770-G-862, HVAC - Air Flow Diagram, Rev. 34
8770-G-878, HVAC - Control Diagrams, Sheet 1, Rev. 35
BCS-361-183.3001, Primary Gen. Lockout Relay Sheet 3
BCS-361-183.3016, Primary Gen. Lockout Relay Sheet 2
EC271161-M-001, Small Bore Piping Isometric Safety Injection System, Rev. 0
ENG-08059-001, Unit #1 Aux Feedwater Pump 1C- Turbine Gov. & Control Panel, Rev. 0
ENG-09072-002, Unit No. 2 Large Bore Piping Isometric- Containment Spray, Rev. 0
ENG-09072-003, Unit No. 2 Large Bore Piping Isometric- Containment Spray, Rev. 0
ENG-09072-004, St. Lucie Plant - Unit No. 2 Valve Operational Number Index, Rev. 0
ENG-09148-1072, St. Lucie Plant - Unit 2 Relay Setting, Rev. 1
ENG-09148-1073, St. Lucie Plant - Unit 2 Relay Setting, Rev. 1
SK-GE-53-80-26 sheet 1, Aux. Relay Cabinet Wiring Diagram, Rev. 1
Other Documents
2-PTP-44, ERDADS Digital Points Attachment P.2, Test Result Report
2998-15436, Auxiliary Feedwater Actuation System, Rev. 5
7186-545-1-A, Triconex Topical Report, Qualification Summary Report, dated 3/8/2002
CEOG, Report No. CE-NPSD-1211-P, Identification of Bi-Metallic Weld Locations in C-E
NSSS Primary Components, dated 3/1/2001
Crane Technical Paper No. 410, Flow of Fluids through Valves, Fittings, and Piping, 1988
CRN No 08019-17683, dated 10/30/08
CSR 508, Electromagnetic Site Survey in Support of the Triconex Tricon Installation at St.
Lucie Plant
Curve 632868, Capability Curve (Main Generator)
EC 246480, Engineering Evaluation Software Verification and Validation Report for ERDADS
and Analog Display System Replacement Rev. 0, 2/27/2011
EC 249654 Attachment 2, UFSAR Change Package Form, Rev. 0
FPL, L-2008-098, dated April 29, Fourth Ten Year Interval Unit-1, Relief Request 2, Item 1,
Relief Request for Structural Weld Overlay of Surge Line to Hot Leg B Pipe Nozzle,
FPL Letter L-2009-019, 60 Day Structural Weld Overlay Report dated 1/20/2009
FPL Memo, St. Lucie Reactive Power Limitations, dated 3/31/2011
FSAR Change Package, Amendment No. 24 (Chapter 15), dated 6/2010
GE NGV Relay Brochure
GEI-90806C, GE Instruction Manual for Undervoltage Relay NGV15A, NGV15B
I/M 8770-6702, Turbine Driver for Auxiliary Feedwater Pump, Rev. 23
IB 6.1.12.1-1E, ABB Low Voltage Air-Magnetic Power Circuit Breakers K-Line
25A through 2000A Installation/Maintenance Instructions,
JPN-SPSL-95-0033, St Lucie Plant Unit 2 Breaker & Overload Settings, dated Jan. 27, 1995
L-2010-281, Report of 10 CFR 50.59 Plant Changes, dated 12/8/2010
L-2011-479, Report of 10 CFR 50.59 Plant Changes, dated 11/2/2011
Limitorque Valve Actuator Qualification for Nuclear Power Station Service Report B0058,
dated 01/11/1980
OWA Report 2-007-2, MV-07-4 Leaks by Seat, dated 12/7/2007
PCM 09078M, Att.1, 10CFR50.59, Applicability Determination Rev 0, 12/17/09
PCR 1608100, 2-AOP-50.07A, Rev 0, Draft H, dated 8/6/11
PSL 4th Interval II Unit-1, Interval Schedule, Summary Number 1-12-RC-108, Weld IDs,
RC-6-509, RC-108-FW-3, RC-108-FW-2002, 12 inch Branch Connection to Safe End
PSL OPS 0711602, Containment and Shield Building Ventilation Systems, Rev. 18
PSL-11-003, St. Lucie Nuclear Oversight Report- Engineering Design, dated 5/2/2011
PSL-11-030, St. Lucie Nuclear Oversight Report- Engineering Programs, dated 9/29/2011
Report # 0900186.403, Design Report for Weld Overlay Repair of Hot Leg Locations
Containing Alloy 600 Materials St Lucie Unit 1, Rev 0, dated 6/2009
SI- Report Number 0800024.407, Summary Report of the Design Analysis and Non-
destructive Examination Results for St. Lucie Unit 1 Hot Leg Nozzle Weld Overlay
Repairs, Rev 0
SPEC-IC-025, Software Requirements Specification PSL ERDADS System Replacement,
Rev. 4
St. Lucie Unit 1 & 2 Conformance to Regulatory Guide 1.97, Docket Nos. 50-335 & 50-389
USNRC SER on St. Lucie Weld Overlays, dated 11/3/2008
WCAP 9272-P-A, Westinghouse Reload Safety Evaluation Methodology
Welding Services (WSI) Certificate of Conformance, Cert. No 104423-Hot Leg Surge, dated
1/22/09
1R18 Plant Modifications
8770-G-082, Intake Cooling Water System Flow Diagram
8770-G-096, Emergency Diesel Generator System Flow Diagram
1R19 Post Maintenance Testing (PMT)
EC 250013, Unit 1 Containment Spray Pump Flow Limitation Modification PMT Plan
1R20 Refueling and Other Outage Activities
1-EOP-01, Standard Post Trip Actions
1-EOP-02, Reactor Trip Recovery
1-GOP-504, Reactor Plant Heat up - Mode 5 To Mode 4
ADM-0010526, Outage Risk Assessment and Control
ADM-0010728, Unit Restart Readiness
PTP-1-3200088, Unit 1 Initial Criticality Following Refueling
1R22 Surveillance Testing
ADM-29.02, ASME Code Testing of Pumps and Valves
OP-1250020, Valve Breaker, Motor and Instrument Instructions
1EP4 Emergency Action Level and Emergency Plan Changes
EPIP-02, Duties and Responsibilities of the Emergency Coordinator, Rev. 31 and 32
EPIP-06, Activation and Operation of the Emergency Operations Facility, Rev. 27 and 28
40A1 Performance Indicator Verification
ADM-25.02, NRC Performance Indicators, Rev. 25
NAP-206, NRC Performance Indicators, Rev. 6
NEI 99-06, Regulatory Assessment Performance Indicator Guideline, Rev. 6
4OA3 Event Follow-up
0030119, Post Trip Review
1-EOP-01, Standard Post Trip Actions
1-EOP-02, Reactor Trip Recovery
1-EOP-05, Excess Steam Demand
LIST OF ACRONYMS
ALARA As Low as is Reasonably Achievable
CAP Corrective Action Program
CCW Component Cooling Water
CFR Code of Federal Regulations
CR Condition Report
CRDM Control Rod Drive Mechanism
EAL Emergency Action Level
ECCS Emergency Core Cooling System
ISFSI Independent Spent Fuel Storage Installation
IST Inservice Testing
NAP Nuclear Administrative Procedure
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
PI Performance Indicator
U1 Unit 1
U2 Unit 2
UFSAR Updated Final Safety Analysis Report
WO Work Order
Attachment