IR 05000335/2010003

IR 05000335-10-003, 05000389-10-003; IR 07200061-10-001; on 4/01/2010 - 6/30/2010; St. Lucie Nuclear Plant, Units 1 & 2; Identification and Resolution of Problems; Other Activities

ML102100006
Person / Time
Site:	Saint Lucie, 07200061
Issue date:	07/28/2010
From:	Rich D NRC/RGN-III/DRP/RPB3
To:	Nazar M Florida Power & Light Co
References
IR-10-003
Download: ML102100006 (41)

Text

July 28, 2010

SUBJECT:

ST. LUCIE NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000335/2010003, 05000389/2010003 AND 07200061/2010001

Dear Mr. Nazar:

On June 30, 2010, the US Nuclear Regulatory Commission (NRC) completed an inspection at your St. Lucie Plant Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on July 8, 2010, with Mr. Anderson and other members of your staff.

The inspection examined activities conducted under your license as they relate 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 inspector-identified finding and two self-revealing findings of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating the findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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 facility. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at St. Lucie.

FPL

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). Adams is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Daniel W. Rich, Chief

Rector Projects Branch 3

Division of Reactor Projects

Docket Nos. 50-335, 50-389 License Nos. DPR-67, NPF-16

Enclosure:

Inspection Report 05000335/2010003, 05000389/2010003

w/Attachment: Supplemental Information

REGION II==

Docket Nos.:

50-335, 50-389

License Nos.:

DPR-67, NPF-16

Report No:

05000335/2010003, 05000389/2010003

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:

April 1 to June 30, 2010

Inspectors:

T. Hoeg, Senior Resident Inspector

S. Sanchez, Resident Inspector

G. Kuzo, Senior Health Physics Inspector (Sections 2RS1 and 4OA5)

J. Griffis, Senior Health Physicist Inspector

A. Vargas Mendez, Reactor Inspector (Section 4OA5)

R. Carrion, Senior Reactor Inspector (Section 4OA5)

C. Fletcher, Senior Reactor Inspector (Section 4OA5)

Approved by:

D. Rich, Chief Reactor Projects Branch 3 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000335/2010-003, 05000389/2010-003; IR 07200061/2010001; 4/01/2010 - 6/30/2010;

St. Lucie Nuclear Plant, Units 1 & 2; Identification and Resolution of Problems; Other Activities.

The report covered a three month period of inspection by resident inspectors and region based inspectors. Three Green non-cited violations (NCVs) were identified. 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 0310,

Components Within the Cross-Cutting Areas; 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, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion XVI,

Corrective Action, for failure of the licensee to take timely and effective corrective actions to prevent seat leakage past containment spray isolation valves 2-MV-07-3 and 2-MV-07-4 resulting in long standing Reactor Coolant System (RCS) inventory perturbations while in reduced inventory operations and a long term operator workaround.

The finding was more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening.

Specifically, if left uncorrected the condition has the potential to become a more significant safety concern such as a loss of shutdown cooling while in mid-loop operations when the time to boil could be 15 minutes or less. Using the NRC Manual Chapter 0609, ASignificance Determination Process,@ Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, the finding was determined to be of very low safety significance because Core Heat Removal,

Inventory Control, Power Availability, Containment Control, and Reactivity Guidelines were all met. This finding was related to the appropriate and timely corrective actions aspect of the corrective action program (CAP) component in the problem identification and resolution crosscutting area (IMC 0305 Aspect P.1.d). (Section 4OA5.1)

Green.

A self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified when a reactor coolant pump (RCP) seal line weld failure resulted in RCS pressure boundary leakage in July 2009. Specifically, the licensee failed to prevent the recurrence of RCS pressure boundary leakage, a significant condition adverse to quality, caused by conditions of low stress, high-cycle fatigue affecting RCP seal line welds. Licensee personnel shutdown the reactor and entered reduced inventory operations to perform repairs. The issue was entered into the CAP.

The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding was associated with repeated RCP weld failures and affected the integrity of the RCS pressure boundary. The finding was determined to be 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 inspectors determined that the cause of this finding was related to the appropriate and timely corrective actions aspect of the CAP component in the problem identification and resolution crosscutting area (IMC 0305 Aspect P.1.d). (Section 4OA3.3)

Green.

A self-revealing NCV of Technical Specification 6.8.1 was identified for an inadequate operating procedure which resulted in the loss of the 1B Direct Current (DC) vital electrical bus and unplanned entry into Technical Specification Action 3.9.8.2.a. for losing operability of one train of shutdown cooling. Subsequently, the Unit 1 daily shutdown risk assessment changed from a low risk to a high risk condition for electric power availability.

The failure to provide adequate procedural guidance for operating the 125 volt (v)

DC vital bus is a performance deficiency. This finding was considered more than minor because it was associated with the Procedure Quality attribute of the Initiating Events cornerstone and adversely affected the objective of limiting the likelihood of a loss of the 125 v DC bus and a loss of shutdown cooling (SDC) event. If left uncorrected, the condition has the potential to become a more significant safety concern such as a loss of SDC while the reactor coolant system is open and the time to boil could be less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This finding was also determined to potentially have greater significance per IMC 06909, Appendix G, Attachment 1, Check List 3 due the increase in the likelihood that a loss of SDC will occur and the licensees ability to cope with a loss of off-site power was degraded. The phase 1 screening resulted in a need to perform a phase 2 and phase 3 evaluation due to the finding resulting in the loss of mitigating function, specifically the ability to perform decay heat removal. The finding occurred while the plant was shutdown and required entry into IMC-0609 Appendix G. A phase 2 analysis was performed by a regional project engineer and was sent to the regional SRA for review. In accordance with the guidance of NRC Inspection Manual Chapter 0609 Appendix G, the analysis was given to headquarters analysts to perform a detailed phase 3. The significance determination process phase 3 risk evaluation resulted in a risk increase for the finding <1E-6 for core damage frequency (CDF) and <1E-7 for large early release frequency (LERF). The initiators evaluated were loss of inventory (LOI), loss of offsite power (LOOP), and loss of residual heat removal (LORHR). The dominant sequences involved the LOOP initiator, failure of the DC B train resulting in the failure of RHR B, and the failure of the A train to provide a means to perform feed and bleed given the loss of RHR A. The analysis assumed the DC B train was non-recoverable. Due to the short time to boil, gravity feed was not credited. The finding was characterized as of very low safety significance (Green). This characterization was due to the very short exposure time and that the deficiency was evaluated as a condition assessment rather that as an event assessment. This finding was related to the complete procedures aspect of the Resources component in the Human Performance crosscutting area (IMC 0305 aspect H.2.c).

Licensee Identified Violations

None.

.

REPORT DETAILS

Summary of Plant Status:

Unit 1 began the period at 73% rated thermal power (RTP) coasting down to a refueling outage that started on April 4. Unit 1 remained shutdown until June 14 when the turbine generator was synchronized to the grid. Unit 1 was at 45% RTP on June 16 when two control element assemblies dropped into the core unexpectedly and the reactor was manually tripped. Unit 1 remained shutdown until June 27 when the turbine generator was synchronized to the grid. Unit 2 began the period at full RTP and remained there until April 15 when it was manually tripped due to the 2B moisture separator reheater relief valve lifting unexpectedly. Unit 2 was returned to full RTP on April 23 and operated at full RTP for the remainder of the period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity (Reactor-R)

==1R01 Adverse Weather Protection

==

.1 Hurricane Season Preparations

a. Inspection Scope

During the week of May 24, 2010, the inspectors reviewed and verified the status of licensee actions taken in accordance with their procedural requirements prior to the onset of hurricane season. The inspectors reviewed administrative procedures ADM-04.01, Hurricane Season Preparation. The inspectors performed site walkdowns of the below listed systems and/or areas to verify the licensee had made the required preparations. Condition reports (CRs) were checked to assure that the licensee was identifying and resolving weather related issues.

• Unit 1 Component Cooling Water (CCW)

• Unit 1 Intake Cooling Water (ICW)

• Unit 2 ICW

b. Findings

No findings were identified.

==1R04 Equipment Alignment

==

.1 Partial Equipment Walkdowns

a. Inspection Scope

The inspectors conducted four partial equipment 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 that the critical portions of the systems were correctly aligned to support operability. The inspectors also verified that 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).

• 2B CCW While 2A CCW Out of Service (OOS)

• 1A 4-Kilovolt (kV) Electrical Bus While 1B 4kV Bus De-energized

• 1A Emergency Diesel Generator (EDG) While 1B EDG OOS

• 2A EDG While 2B EDG OOS

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed walkdown/review of the alignment and condition of the Unit 2 A-train emergency core cooling system (ECCS) exhaust ventilation to verify its capability to meet its design basis function. The inspectors utilized licensee procedure 2-NOP-25.03, Ventilation Systems Initial Alignment, and drawing 2998-G-879, HVAC Control Diagrams, as well as other licensing and design documents to verify the system alignment was correct. During the walkdown, the inspectors verified, as appropriate, that:

(1) dampers were correctly positioned and did not exhibit a condition that would impact their function;

(2) electrical power was available as required;

(3) major portions of the system and components were correctly labeled;

(4) hangers and supports were correctly installed and functional;

(5) essential support systems were operational; (6)ancillary equipment or debris did not interfere with system performance; and

(7) tagging clearances were appropriate. Pending design and equipment issues were reviewed to determine if the identified deficiencies significantly impacted the systems functions.

Items included in this review were the operator workaround list, the temporary modification list, system health reports, system description, and outstanding maintenance work requests/work orders. In addition, the inspectors reviewed the licensees CAP to ensure that the licensee was identifying and resolving equipment alignment problems.

b. Findings

No findings were identified.

==1R05 Fire Protection

==

.1 Fire Area Walkdowns

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, 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 10 CFR Part 50, Appendix R. The licensees fire impairment lists, updated on an as-needed basis, were routinely reviewed. In addition, the inspectors reviewed the CR database to verify that fire protection problems were being identified and appropriately resolved. The following areas were inspected:

• Unit 2 ICW Pump Area

• Unit 1 Spent Fuel Pool Pumps and Heat Exchanger Area

• Unit 1 B EDG Room

• Unit 1 Vital Electrical Switchgear Rooms

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed one fire drill during this inspection period. On June 30, 2010, an unannounced fire drill took place in the Unit 2 Turbine Building Switchgear Room.

The drill was observed to evaluate the readiness of the plant fire brigade to fight fires.

The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the debrief, 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 firefighting 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.

==1R06 Flood Protection Measures

Internal Flooding

a. Inspection Scope

==

The inspectors conducted walkdowns of the following areas which included checks of building structure sumps to ensure that flood protection measures were in accordance with design specifications. The inspectors reviewed Updated Final Safety Analysis Report (UFSAR), Section 3.4, Water Level (Flood) Design and UFSAR Table 3.2-1, Design Classification of Systems, Structures, and Components (SSC). The inspectors also reviewed plant procedures that discussed the protection of areas containing safety-related equipment that may be affected by internal flooding. Specific plant attributes that were checked included structural integrity, sealing of penetrations, control of debris, and operability of sump pump systems.

• Unit 2 CCW Building

• Unit 1 ECCS Room

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Training Program

Resident Inspector Quarterly Review

a.

==

Inspection Scope

On June 23, 2010, the inspectors observed and assessed licensed operator actions during a simulated Loss of Off-Site Power followed by a Station Blackout in accordance with St. Lucie Simulator Evaluation Guide 0815048, Revision 1. 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 the required Maintenance Rule (MR) a(3) periodic evaluation and the system performance data and associated CRs for the one system listed below to verify that the licensees maintenance efforts met the requirements of 10 CFR 50.65 (Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants) and licensee Administrative 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 reviewed associated system health reports.

The inspectors verified that equipment problems were being identified and entered into the licensees CAP.

• Unit 2 High Pressure Safety Injection

• MR a(3) Periodic Evaluation

b. Findings

No findings were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors completed in-office reviews, plant walkdowns, 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 10 CFR 50.65(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 the 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 out of service (OOS) risk significant systems, structures, and components (SSCs) listed below:

• 2A-ICW, 2A-CCW, 2A-HPSI, and 2A-Containment Spray (CS) Pumps OOS

• 2B-HPSI Pump and Fan HVS-4B OOS

• 2B-CS Pump and Fan HVS-4B OOS

• Unit 1 Yellow Risk While in Mode 3

• Unit 1 Green Risk While in Mode 4

• 2B-Charging Pump, 2B-CCW Pump, 2C-ICW Pump, and 1B-EDG OOS

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed the following six CR interim dispositions and operability determinations to ensure that operability was properly supported and the affected SSCs remained available to perform its safety function with no increase in risk. The inspectors reviewed the applicable UFSAR, and associated supporting documents and procedures, and interviewed plant personnel to assess the adequacy of the interim disposition.

• CR 2010-9914, Unit 1 Auxiliary Feedwater Actuation Signal

• CR 2010-12285, 1A CCW Heat Exchanger Tube Plugging

• CR 2010-12579, 1A CCW Pipe CC-26 Corrosion

• CR 2010-14142, Unit 1 Sump Suction Valve MV-07-2A Increased Stroke Time

• CR 2010-15076, Unit 1 Channel D Wide Range Nuclear Instrumentation Reads Low

• CR 2010-15747, 1B-EDG Failed Surveillance Test

b. Findings

No findings were identified

==1R18 Plant Modifications

a. Inspection Scope

==

The inspectors reviewed the documentation for the temporary and permanent modifications listed below. The inspectors reviewed the 10 CFR 50.59 screening and evaluation, fire protection review, environmental review, and license renewal review, to verify that the modifications had not affected system operability/availability. The inspectors reviewed associated plant drawings and UFSAR documents impacted by these modifications and discussed the changes with licensee personnel to verify that the installations were consistent with the modification documents. The inspectors walked down the modifications to determine if they were installed in the field as described in the associated documents. Additionally, the inspectors verified that problems associated with modifications were being identified and entered into the CAP.

• Change Request Notice CRN 07127-19426, Unit 2 Fan HVS-4A/B Plenum Modification

• Temporary System Alteration TSA 1-10-020, Temporary Cooling Fans for Pressurizer Heater Cable Connection Area

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

For the six post maintenance tests (PMTs) 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 work orders (WO) and/or work requests (WR):

• WO# 37003801, Re-Installment of 2B CCW Pump Motor

• WO# 31018400, 1B EDG Governor Replacement

• WO# 40009116, Unit 2 Fan HVS-4B Motor Replacement

• WO# 38022878, Unit 1 Sump Suction Valve MV-07-2A

• WO# 40011091, 1A1 Reactor Coolant Pump Upper Oil Cooler CCW Line Repair

• WO# 40010833, Wide Range Nuclear Instrumentation Channel B Spiking Into Alarm

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

==

.1 Unit 2 Forced Outage

a. Inspection Scope

On April 15, 2010, Unit 2 operators performed a manual reactor plant shutdown when the 2B moisture separator reheater relief valve opened unexpectedly. The inspectors observed control room activities, including the reactor shutdown. The inspectors also observed the reactor startup, including synchronizing the turbine generator to the grid.

Monitoring and Shutdown Activities

The inspectors observed portions of the plant shutdown to hot standby to verify that operating restrictions and similar procedural requirements were followed. The inspectors observed control room operator communications, place keeping, and reviewed chronological log entries.

Monitoring of Heat up and Startup Activities

On April 22, 2010, the inspectors observed activities during the reactor restart to verify that reactor parameters were within safety limits and that the startup evolutions were performed in accordance with licensee procedure 2-GOP-302, Reactor Startup Mode 3 to Mode 2.

b. Findings

No findings were identified.

.2 Unit 1 Refueling Outage SL1-23

a. Inspection Scope

Outage Planning, Control and Risk Assessment

During pre-outage planning, the inspectors reviewed the risk reduction methodology employed by the licensee for refuel outage (RFO) SL1-23, in particular the Risk Assessment Team (RAT) notebook. The inspectors also examined the licensees implementation of shutdown safety assessments during SL1-23 in accordance with Administrative 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. Furthermore, the inspectors regularly monitored outage planning and control activities in the Outage Control Center (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 observed portions of the reactor plant shutdown and cooldown of Unit 1 beginning on April 4, 2010. The inspectors also monitored plant parameters and verified that shutdown activities were conducted in accordance with Technical Specifications and applicable operating procedures, such as: 1-GOP-123, Turbine Shutdown - Full Load to Zero Load; 1-GOP-203, Reactor Shutdown; 1-GOP-305, Reactor Plant Cooldown - Hot Standby To Cold Shutdown; and 1-NOP-03.05, Shutdown Cooling.

Outage Activities

The inspectors examined outage activities to verify that 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

• Reviewed actions taken in preparation for Hurricane season

• 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. Furthermore, the inspectors evaluated the licensees ability to close the containment equipment, personnel, and emergency hatches in a timely manner per procedure 1-MMP-68.02, Containment Closure.

Heatup, 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 plant heat up operations. The inspectors also conducted a containment walkdown on June 1, 2010, after the Unit 1 reactor plant had reached Mode 3 and was at normal operating pressure and temperature. The results of low power physics testing were discussed with Reactor Engineering and Operations personnel to ensure that the core operating limit parameters were consistent with the design. The inspectors witnessed portions of the RCS heatup, reactor startup, and power ascension in accordance with the following plant procedures:

• Pre-operational Test Procedure (POP) 1-3200088

• Unit 1 Initial Criticality Following Refueling

• POP 0-3200092, Reactor Engineering Power Ascension Program

• 1-GOP-201, Reactor Plant Startup - Mode 2 to Mode 1

• 1-GOP-302, Reactor Plant Startup - Mode 3 to Mode 2

• 1-GOP-303, Reactor Plant Heatup - Mode 3 <1750 to Mode 3 >1750

• 1-GOP-403, Reactor Plant Heatup - Mode 4 to Mode 3

• 1-GOP-504, Reactor Plant Heatup - Mode 5 to Mode 4

Correction Action Program

The inspectors reviewed CRs generated during SL1-23 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.

.3 Unit 1 Forced Outage

a. Inspection Scope

On June 16, 2010, Unit 1 operators performed a manual reactor shutdown from 45%

power when two control element assemblies (CEAs) unexpectedly dropped into the core. The inspectors observed control room activities, including the reactor shutdown.

The inspectors also observed the reactor startup, including the various step increases of reactor power.

Monitoring and Shutdown Activities

The inspectors reviewed actions to place the plant in hot standby conditions and verified that operating restrictions and similar procedural requirements were followed. The inspectors also reviewed post trip response, strip charts, and chronological log entries.

Monitoring of Heat up and Startup Activities

On June 26, 2010, the inspectors observed activities during the reactor restart to verify that reactor parameters were within safety limits and that the startup evolutions were performed in accordance with licensee procedure 1-GOP-302, Reactor Startup Mode 3 to Mode 2.

b. Findings

No findings were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors either reviewed or witnessed the following seven surveillance tests to verify that the tests met the technical specifications, 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) surveillance and one containment isolation valve (CIV) test. The inspectors verified that surveillance issues were documented in the CAP.

• 1-OSP-69.17, Engineered Safeguards Feature (ESF) 18 Month Surveillance for Recirculation Actuation Signal With Shutdown Cooling Inservice - Both Trains

• 2-OSP-09.01C, 2C Auxiliary Feedwater Pump Code Run

• 1-OP-0010125A, Inservice Stroke Test of Valve MV-09-10 (IST)

• 1-OSP-59.01B, 1B EDG Monthly Surveillance

• 2-OSP-52.02, Station Blackout Cross-Tie Load Test

• 1-OSP-69.13A/B, A/B ESF Testing

• 1-OSP-68.02, Local Leak Rate Test on Penetration 54 V00101 (CIV)

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

Cornerstones: Occupational Radiation Safety (OS)

RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to workers During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs), and Very High Radiation Areas (VHRAs) in the radiologically controlled area (RCA) of the Unit 1 (U1) containment, U1 and Unit 2 (U2) auxiliary buildings, and radioactive waste (radwaste) processing and storage locations. The inspectors directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, hot particles, airborne radioactivity, gamma surveys within areas of high dose rate gradients, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices The inspectors evaluated access barrier effectiveness for selected U1 and U2 Locked High Radiation Area (LHRA) and VHRA locations. Changes to procedural guidance for LHRA and VHRA controls were discussed with health physics (HP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool (SFP) were reviewed and discussed. Established radiological controls (including airborne controls) were evaluated for selected U1 Refueling Outage 23 (SL1-23) tasks including intermediate leg drain cut-outs and welding, LHRA barrier installation on reactor coolant piping penetrations, and resetting the upper guide structure in the reactor vessel. In addition, licensee controls for at-power entries into U1 containment were reviewed for work associated with the U1 instrument air compressor. Areas where dose rates could change significantly as a result of plant shutdown and refueling operations were also reviewed and discussed.

Occupational workers adherence to selected RWPs and HP technician (HPT)proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for LHRA penetration barrier installations and activities associated with lifting and setting the upper guide structure. ED alarm logs were reviewed and worker response to dose and dose rate alarms during selected work activities was evaluated. HPT coverage and actions at the Unit 1 containment access point were reviewed and discussed in detail.

Control of Radioactive Material The inspectors observed surveys of material and personnel being released from the RCA using small article monitor, personnel contamination monitor, and portal monitor instruments. The inspectors discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

In addition, the inspector reviewed controls for hand surveying large tools and equipment for release from the RCA and the PA. The inspectors compared recent 10 Code of Federal Regulations (CFR) Part 61 results for the Dry Active Waste radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution CRs associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure PI-AA-204, Condition Identification and Screening Process, Rev. 7. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; TS Section 6.12; 10 CFR Parts 19 and 20; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in Section 2RS1 of the attachment.

The inspectors completed all specified line-items detailed in Inspection Procedure (IP)71124.01.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Barrier Integrity

a. Inspection Scope

The inspectors checked licensee submittals for the performance indicators (PIs) listed below for the period April 1, 2009, through March 31, 2010, 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 procedure ADM-25.02, 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 that 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 Reactor Coolant System (RCS) Leakage

• Unit 2 RCS Leakage

• Unit 1 RCS Activity

• Unit 2 RCS Activity

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.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 CAP. 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.

b. Findings

No findings were identified.

.2 Annual Sample

Loss of 1B Safety Related DC Bus

a. Inspection Scope

The inspectors reviewed condition report 2010-9342, Entry into Red Risk Level Due to Loss of 1B Safety Related DC Bus and associated Root Cause Evaluation (RCE) for an unexpected loss of a vital 125 volt

(v) Direct Current (DC) bus that caused the Unit 1 daily shutdown risk assessment to change from a low to high risk category for electric power availability in accordance with the licensee procedure 0010526, Outage Risk Assessment and Control. The inspectors reviewed the licensees evaluation of the event and the associated corrective actions. The inspectors interviewed plant personnel and evaluated the licensees administration of this selected CR in accordance with their CAP as specified in licensee procedures 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.

b. Findings and Observations

Introduction:

A Green self-revealing NCV of Technical Specification 6.8.1 was identified for an inadequate operating procedure which resulted in the loss of the 1B DC vital electrical bus and unplanned entry into Technical Specification Action 3.9.8.2.a.

Subsequently, the Unit 1 daily shutdown risk assessment changed from a low to high risk condition for electric power availability. The licensee restored the DC vital electrical bus within 20 minutes.

Description:

On April 11, 2010, Unit 1 was in Mode 6 (Refueling) with the reactor vessel head de-tensioned and RCS level at 34 feet or just below the reactor vessel flange and about 10 feet above irradiated fuel. Both trains of shutdown cooling were in operation with RCS temperature at about 97 degrees Fahrenheit with a time-to-boil (TTB) of 23.9 minutes. Both the 1A and 1B 125 v DC busses were energized from their respective 1A and 1B batteries.

The Unit 1 refueling outage schedule required the 1B battery to be removed from service for maintenance. The licensee chose to place the 1D battery on the 1AB and 1B 125 v DC bus while maintenance was to be performed on the 1B battery. The 1D battery had been taken off of its battery charger the previous day and had a reduced charge of 114 v DC. During the process of switching the battery lineup per Operations procedure 1-NOP-50.01B, 125 v DC Bus 1B Normal Operation, the cross-tie breakers aligning the 1D battery to the 1AB and 1B 125 v DC bus were closed and the 1B battery breaker opened. After several minutes of the 1D battery being aligned to the 1AB and 1B 125 v DC busses, one of the cross-tie breakers opened on thermal overload due to the excessive current flow from the battery chargers to the undercharged 1D battery. As a result, the safety-related 1B 125 v DC bus became de-energized and the 1B shutdown cooling train was declared inoperable due to not having a DC control power source of electricity to the operating 1B low pressure safety injection pump. The licensee determined Operations procedure 1-NOP-50.01B was inadequate since it did not provide special precautions or warnings associated with switching the battery breaker lineup. The licensee determined this was a root cause of losing the 1B 125 v DC bus.

The safe shutdown risk assessment changed from Yellow to Red per licensee procedure 0010526, Outage Risk Assessment and Control, during this event due to the second train of DC power becoming unavailable. The operators restored the 1B 125 v DC bus with the 1B battery within 20 minutes and exited the increased risk condition. The operation of the cross-tie breaker opening on over-current was as designed under the system conditions.

Licensee non-safety-related procedure WM-AA-1000, Work Activity Risk Management is used to determine the risk of performing various maintenance activities during outages. The procedure requires work which involves a potential impact on electrical systems that could impact shutdown cooling operations, be characterized as high risk and that a risk management plan be developed prior to performing the work. This plan was not developed prior to the maintenance. The licensee determined this missed high risk activity as a root cause of losing the 1B 125 v DC bus.

Analysis:

The failure to provide adequate procedural guidance for operating the 125 v DC vital bus is a performance deficiency. This finding is more than minor because it was associated with the Procedure Quality attribute of the Initiating Events cornerstone and adversely affected the objective in that the loss of the 125 v DC bus increased the likelihood of a loss of shutdown cooling (SDC) event. If left uncorrected, the condition has the potential to become a more significant safety concern such as a loss of SDC while the RCS is open and the time to boil could be less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This finding was also determined to potentially have greater significance per IMC 06909, Appendix G, 1, Check List 3 due the increase in the likelihood that a loss of SDC will occur and the licensees ability to cope with a loss of off-site power was degraded. The phase 1 screening resulted in a need to perform a phase 2 and phase 3 evaluation due to the finding resulting in the loss of mitigating function, specifically the ability to perform decay heat removal. The finding occurred while the plant was shutdown and required entry into IMC-0609 Appendix G. A phase 2 analysis was performed by a regional project engineer and was sent to the regional SRA for review. In accordance with the guidance of NRC Inspection Manual Chapter 0609 Appendix G, the analysis was given to headquarters analyst to perform a detailed phase 3. The significance determination process phase 3 risk evaluation resulted in a risk increase for the finding <1E-6 for core damage frequency (CDF) and <1E-7 for large early release frequency (LERF). The initiators evaluated were loss of inventory (LOI), loss of offsite power (LOOP), and loss of residual heat removal (LORHR). The dominant sequences involved the LOOP initiator, failure of the DC B train resulting in the failure of RHR B, and the failure of the A train to provide a means to perform feed and bleed given the loss of RHR A. The analysis assumed the DC B train was non-recoverable. Due to the short time to boil, gravity feed was not credited. The finding was characterized as of very low safety significance (Green). This characterization was due to the very short exposure time and that the deficiency was evaluated as a condition assessment rather that as an event assessment. This finding was related to the complete procedures aspect of the Resources component in the Human Performance crosscutting area (IMC 0305 aspect H.2.c).

Enforcement:

TS 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 3 of Appendix A, states that operation of electrical systems should be covered by written procedures.

Contrary to the above, on April 11, 2010, instructions for the operation of the 1B 125 v DC Bus were not adequate in that they did not provide specific special precautions or limitations in Operations procedure 1-NOP-50.01B, 125 v DC Bus 1B Normal Operation when cross-tying 125 v DC busses. As a result, the 1B 125 v DC bus was lost following alignment to the 1D battery. Because the failure to correct and comply with NRC requirements is considered to be of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000335/2010003-01, Inadequate Operations Procedure Results in Loss of 1B 125v DC Bus.

.3 Annual Sample

Review of Anonymous CR

a. Inspection Scope

The inspectors reviewed CR 2010-12809, Contaminated Rigging Placed in the Hot Tool Room Garbage. The inspectors reviewed the licensees evaluation of the event and the associated corrective actions. The inspectors interviewed plant personnel and evaluated the licensees administration of this selected CR in accordance with their CAP as specified in licensee procedures 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.

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) LER 2009-003, Reactor Coolant Pump (RCP) 2B2 Lower Seal Cavity Line Leak

On July 12, 2009, Unit 2 was in Mode 1 at 100% reactor power when the reactor was down powered and manually tripped due to an increasing trend in reactor coolant system (RCS) unidentified leakage. The leakage source was identified as a cracked weld where the lower cavity seal line connects to the 2B2 RCP seal housing. A metallurgical failure analysis concluded that the failure mechanism was outside diameter initiated low stress high cycle fatigue caused by resonance vibration. Corrective actions included replacement of the cracked seal housing, cutting and capping of the RCP seal lines susceptible to resonance vibration, installation of additional vibration monitoring equipment on the seal piping, and plan to install flexible piping during a future outage.

Violation of NRC requirements associated with this issue is discussed in Section 4OA5.3 of this report. This LER is closed.

.2 Unit 2 Trip Due to Moisture Separator Reheater (MSR) Relief Valve Lifting

a. Inspection Scope

On April 15, 2010, the inspectors observed licensee activities associated with a manual reactor trip due to the 2B MSR relief valve opening unexpectedly. The inspectors discussed the trip with operations, engineering, and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors reviewed operator actions taken in accordance with licensee procedures, unit and system indications to verify that actions and system responses were as expected, and the Post Trip Review Report. The inspectors discussed the repairs with the licensees Failure Investigation Process team and assessed the teams actions to gather, review, and assess information leading up to and following the event. The inspectors also observed licensee activities to place the turbine back online and increase reactor power to full RTP.

b. Findings

No findings were identified.

.3 Unit 1 Trip Due to Dropped Control Element Assemblies (CEAs)

a. Inspection Scope

On June 18, 2010, the inspectors reviewed licensee activities associated with a manual reactor trip due to two CEAs unexpectedly dropping into the core. The inspectors discussed the trip with operations, engineering, and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors reviewed operator actions taken in accordance with licensee procedures, unit and system indications to verify that actions and system responses were as expected, and the Post Trip Review Report. The inspectors discussed the repairs with the licensees Failure Investigation Process team and assessed the teams actions to gather, review, and assess information leading up to and following the event. The inspectors also observed licensee activities to place the turbine back online and increase reactor power to full RTP.

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 that the activities 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 (Closed) URI 05000389/2009004-01: Seat Leakage of Containment Spray Valves 2-MV-

07-3/4

a. Inspection Scope

During the third quarter of 2009, the inspectors selected CR 2007-41688, MV-07-3 and MV-07-4 Repetitive Failures and Rework Including Operator Work Around, for a more in-depth review. An URI was identified by the inspectors relating to the timeliness of corrective actions associated with the operator workaround and seat leakage of the subject valves. This URI was documented in NRC Inspection Report No.

05000389/2009004 dated October 30, 2009.

b. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for failure of the licensee to take timely and effective corrective actions to repair known RCS leakage past containment spray isolation valves 2-MV-07-3 and 2-MV-07-4 while in shutdown cooling operations and RCS reduced inventory dating back to 1990.

Description:

While reviewing condition report 2007-41688, the inspectors determined that seat leakage past valves 2-MV-07-3 and 2-MV-07-4 dates back to 1990. The valves are Pacific 12 inch gate valves with SB-0 Limitorque motor operators. Leakage has been as much as 3.37 gallons per minute (gpm) measured in 2004. Repairs on the valve seats and wedges have been ineffective. The valve repairs have consisted of lapping the valves seating surfaces and performing a satisfactory blue dye check of the seating surfaces. The valves are not containment isolation valves and require no periodic in-service test. The licensee continues to plan replacement of the valves with a better flexible wedge style valve; but, as the refueling outages approach the repair is cancelled for scheduling conflicts and to further evaluate the seat leakage condition.

This has been noted by the inspectors during the last two refueling outages while the documented operator workaround remains open.

The inspectors determined that in 1996 the licensee created a compensatory measure and procedure change to install a temporary hose from a drain valve downstream of 2-MV-07-3/4 to allow the seat leakage to drain to the floor drain system in the auxiliary building vice leaking into the containment spray system and filling up the ring header and discharging down into containment during shutdown cooling operations. Licensee procedure 2-NOP-03.05, Shutdown Cooling, prescribes this alignment but provides no information or controls that may be required to avoid operations which could cause perturbations to RCS level control while in reduced inventory operations and more importantly mid-loop conditions. In addition, procedure 2-ONP-1.04, Shutdown Cooling Operations in Reduced Inventory, makes no mention of this compensatory action or safety implications while in mid-loop operations. The licensee has created an operator workaround affecting shutdown cooling operations and RCS inventory control while in mid-loop conditions and requires routine charging to maintain reactor vessel inventory and a net positive suction head (NPSH) on the operating shutdown cooling pump. The inspectors determined that the licensee has not taken timely and effective corrective actions to remedy RCS leakage past containment spray isolation valves 2-MV-07-3 and 2-MV-07-4 while in reduced inventory operations dating back to 1996.

Analysis:

The finding was considered more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening. Specifically, if left uncorrected the condition has the potential to become a more significant safety concern such as a loss of shutdown cooling while in mid-loop operations. Using the NRC Manual Chapter 0609, ASignificance Determination Process,@ Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, the finding was determined to be of very low safety significance because Core Heat Removal, Inventory Control, Power Availability, Containment Control, and Reactivity Guidelines were all met. The inspectors also determined that the cause of this finding was related to the appropriate and timely corrective actions aspect of the corrective action program component in the problem identification and resolution crosscutting area (IMC 0305 aspect P.1.d).

Enforcement:

Criterion XVI of 10 CFR Part 50, Appendix B, Criterion XVI states in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to this requirement, the licensee failed to take timely and effective corrective actions to repair seat leakage past valves 2-MV-07-3 and 2-MV-07-4 during RCS reduced inventory operations.

Because the failure to correct and comply with NRC requirements is considered to be of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000389/2010003-02, Untimely Corrective Actions to Resolve Seat Leakage of Containment Spray Valves 2-MV-07-3/4. Unresolved Item 05000389/2009004-01 is closed.

.3 (Closed) URI 05000389/2009004-02: Reactor Coolant Pump (RCP) Failed Seal Injection

Line

a. Inspection Scope

The inspectors selected CR 2009-19624, RCP 2B2 Failed Seal Line Weld, for a detailed review of the circumstances that led to a pressure boundary leak through a weld on a RCP seal housing. The inspectors reviewed the licensees evaluation of the conditions that caused the weld failure and the corrective actions generated to prevent recurrence.

The inspectors evaluated the CR in accordance with the licensees corrective action process as specified in licensee procedures 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.

b. Findings

Introduction:

A self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified when a RCP seal line weld failure resulted in reactor coolant system (RCS) pressure boundary leakage. Specifically, the licensee failed to prevent the recurrence of RCS pressure boundary leakage, a significant condition adverse to quality, caused by conditions of low stress, high-cycle fatigue affecting RCP seal line welds.

Description:

On July 8, 2009, during mid-shift operation, operators performed a RCS inventory balance and calculated a 0.065 gallon per minute (gpm) unidentified leak rate.

Additionally, a Containment Atmosphere Particulate Radiation Monitor indicated an upward trend. Licensee personnel performed a robotic inspection of containment in an attempt to identify the source of the leak and then performed a required shutdown of the unit on July 13, 2009. Upon further investigation, licensee personnel found leakage from a 2B2 RCP lower cavity pressure instrument line weld. The licensee entered this issue into their CAP as CR 2009-19624 and categorized it as a significant condition adverse to quality.

In order to perform corrective maintenance, the licensee placed the plant into a reduced inventory configuration, which is a higher risk plant operating status. The licensees immediate corrective action included replacing the seal assembly, flange removal, cutting and capping of the upper cavity lines and replacing middle cavity piping between the flange and next piping flange.

The licensee determined that the 2B2 RCP lower cavity pressure instrument line weld had failed due to low stress, high cycle fatigue. The inspectors noted that similar weld failures had taken place on three other occasions and that these failures shared common causes.

The first failure took place August 18, 2007, on the 2B1 RCP pipe-to-elbow weld on the outboard side of the first flanged coupling of the 2B1 RCP seal injection 3/4 inch diameter line. The licensees evaluation of this weld failure determined that the root cause was low stress, high cycle fatigue induced by RCP vibration in combination with a resonance condition of the seal injection line with the RCP operating vibration frequency.

Corrective actions included replacing the affected section of the seal injection line on all RCPs using different socket weld dimensions (2:1 tapered leg ratio) to improve fatigue resistance.

The second failure occurred on December 21, 2007, when the 2B2 RCP weld connecting the 3/4 inch diameter seal injection line with the seal housing failed. The licensees evaluation of the failure determined that the cause was also related to low stress, high cycle fatigue driven by RCP vibration. Also, the licensee identified an additional contributing condition of pre-existing stress. During disassembly of the affected line, the outboard face of the seal injection line flange sprang away from the assembled position to a misaligned position relative to the other face of the flange.

Corrective actions included replacing the affected seal injection housing assembly and generating an action item to develop a plan to monitor vibration on the RCP seal injection lines to support long term solution.

The third failure occurred on January 28, 2008. The licensee manually tripped the plant due to failure of the 2B1 RCP pipe-to-flange weld on the outboard side of the first flanged coupling of the upper cavity pressure sensing line. The licensee also determined that the root cause of the weld failure was low stress, high cycle fatigue caused by RCP vibration. Licensee personnel identified trans-granular cracking indications in the weld root. Corrective actions included: the replacement of an additional 12 seal assembly lines using the aforementioned 2:1 tapered leg ratio; performance of an additional impact test and vibration analysis to identify resonance; and acquisition of RCP seal line vibration data during plant shutdown and startup. The licensee performed an analysis that determined that a potential resonance issue may exist for the upper seal cavity line because one of its natural frequencies was close to a multiple of the RCP vane pass frequency. This January 28, 2008, RCP weld failure was the subject of a finding and non-cited violation (NCV 05000389/2008002-02).

The inspectors noted that licensees corrective actions following the January 2008 pressure boundary leakage due to RCP seal line weld failure did not prevent recurrence in July 2009.

Analysis:

The inspectors determined that the licensees failure to implement adequate corrective actions to prevent recurrence of RCS pressure boundary leakage due to RCP seal line weld failure following January 2008 event was a performance deficiency warranting significance determination. The inspectors determined that the performance deficiency was more than minor in accordance with IMC 0612, Appendix B, Issue Disposition Screening, because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding was associated with repeated RCP weld failures and affected the integrity of the RCS pressure boundary.

The inspectors evaluated the risk of this finding using IMC 0609, Significance Determination Process, Attachment 0609.04, 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. RCP seal injection flow is isolated during normal plant operations; it is only used during RCS fill and vent operations to provide flushing flow to prevent foreign material (e.g., crud) in the RCS water from entering the seal cavity. Therefore, the loss of seal injection flow to the RCP would have no adverse impact on RCP operation or on plant safe shutdown capability. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, P.1.d, because the licensees corrective actions were not adequate to prevent recurrence of RCS pressure boundary leakage due to RCP weld failure.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to the above, between January 2008 and July 2009 the licensee failed to assure that adequate corrective action was taken to preclude repetition of RCS pressure boundary leakage due to failed RCP seal line welds, a significant condition adverse to quality.

Because the licensee entered the issue into their CAP as CR 2009-19624 and the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000389/2010003-03: Failure to Take Timely and Effective Corrective Actions to Prevent RCS Pressure Boundary Leakage through the RCP Seal Lines. URI 05000389/2009-004-02, which was opened during NRC Inspection Report 05000389/2009-004, is considered closed.

.4 (Closed) Temporary Instruction 2515/173 Review of the Implementation of the Industry

Ground Water Protection Voluntary Initiative

a. Inspection Scope

The inspectors reviewed elements of the licensees environmental monitoring program to evaluate compliance with the voluntary Groundwater Protection Initiative (GPI) as described in Nuclear Energy Institute (NEI) 07-07, Industry Ground Water Protection Initiative - Final Guidance Document, August 2007 (ADAMS Accession Number ML072610036). Inspectors interviewed personnel, performed walk-downs of selected areas, and reviewed the following items:

• Records of the site characterization of geology and hydrology

• Evaluations of systems, structures, and or components that contain or could contain licensed material and evaluations of work practices that involved licensed material for which there is a credible mechanism for the licensed material to reach the groundwater

• Implementation of an onsite groundwater monitoring program to monitor for potential licensed radioactive leakage into groundwater

• Procedures for the decision making process for potential remediation of leaks and spills, including consideration of the long term decommissioning impacts

• Records of leaks and spills recorded, if any, in the licensees decommissioning files in accordance with 10 CFR 50.75(g)

• Licensee briefings of local and state officials on the licensees groundwater protection initiative

• Protocols for notification to the local and state officials, and to the NRC regarding detection of leaks and spills

• Protocols and/or procedures for thirty-day reports if an onsite groundwater sample exceeds the criteria in the radiological environmental monitoring program

• Groundwater monitoring results as reported in the annual effluent and/or environmental monitoring report

• Licensee and industry assessments of implementation of the groundwater protection initiative. (Note the NEI audit of GPI implementation was in-progress at the time of the inspection but unavailable for NRC review).

Documents reviewed are listed in section 4OA5 in the attachment. The inspectors completed all specified line-item samples detailed in Temporary Instruction 2515/173.

b. Findings

No findings were identified with the licensees implementation of NEI 07-07. This completes the Region II inspection requirements.

.5 (Closed) Temporary Instruction 2515/180, Inspection of Procedures and Processes for

Managing Fatigue

a. Inspection Scope

The objective of this TI was to determine if the licensees implementation procedures and processes required by 10 CFR 26, Subpart I, Managing Fatigue are in place to reasonably ensure the requirements specified in Subpart I are being addressed. The TI applies to all operating nuclear power reactor licensees but is intended to be performed for one site per utility. The inspector interfaced with the appropriate station staff to obtain and review station policies, procedures, and processes necessary to complete all portions of this TI.

b. Findings

No findings were identified.

.6 On-Site Fabrication of Components and Construction of an ISFSI (60853, Revision 0)

a. Inspection Scope

The inspectors conducted a review of licensee and vendor activities in preparation for moving spent fuel from the spent fuel pool to the ISFSI pad for storage, including the recently constructed Unit 2 cask handling facility (CHF) and the revised haul path for compliance with 72 CFR, Part 48, Changes, tests, and experiments, and Part 212, Conditions of general license issued under §72.210. Specifically, the inspectors walked down the cask handling facility and discussed its features and design with the licensees ISFSI manager, and walked down the revised haul path to assure that potential radiation and explosive threats were identified so that their effects were mitigated. In addition, the inspectors reviewed related drawings, reports, and engineering evaluations to determine if the requirements of the Certificate of Compliance (CoC), Technical Specifications (TSs), and 10 CFR 72 had been met.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

Radiation Protection

On May 14, 2010, the inspectors discussed preliminary results of the onsite radiation protection inspection with Mr. R. Anderson, Site Vice President, and other responsible staff. The inspectors noted that proprietary information was reviewed during the course of the inspection but would not be included in the documented report.

During a June 16, 2010, teleconference with site Licensing and Chemistry representatives, the inspectors discussed their review and evaluation of current licensee documents regarding the licensing basis and adequacy of UFSAR descriptions for use of the Unit 1 Liquid Waste Monitor Tanks for processing Unit 2 liquid waste. Although no items of significance were identified, the inspectors discussed challenges in adequately implementing the specific NEI Ground Water Protection initiative to identify and mitigate leakage from the U1 outside waste monitor and other U1 processing tanks and piping.

On-Site Fabrication of Components and Construction of an ISFSI

A meeting was held with licensee management on June 30, 2010. Comments by the inspectors with respect to observed activities were discussed with the Site Vice President and other members of the licensees staff. The inspectors noted that proprietary information was reviewed during the course of the inspection but would not be included in the documented report.

Resident Inspection

The resident inspectors presented the inspection results to Mr. Anderson and other members of licensee management on July 8, 2010. 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.

4OA7 Licensee-Identified Violations

None.

ATTACHMENT: SUPPPLEMENTAL INFORMATION KEY POINTS OF CONTACT

Licensee Personnel:

C. Ali, Licensing Engineer R. Anderson, Site Vice President E. Belizar, Projects Manager D. Calabrese, Emergency Preparedness Manager D. Cecchett, Licensing Engineer J. Connor, Systems and Component Engineering Manager A. Day, Chemistry Manager M. Delowery, Extended Power Uprate Manager S. Duston, Training Manager K. Frehafer, Licensing Engineer J. Hamm, Site Engineering Director D. Hanley, Maintenance Programs Supervisor M. Haskin, Maintenance Manager J. Heinold, Chemistry Technical Supervisor M. Hicks, Recovery Team Manager D. Huey, Work Control Manager B. Hughes, Plant General Manager J. Klauck, Assistant Operations Manager R. Lingle, Operations Manager C. Martin, Radiation Protection Manager R. McDaniel, Fire Protection Supervisor M. Moore, Performance Improvement Department Manager P. Paradis, Fix-It-Now Team Supervisor J. Porter, Design Engineering Manager M. Snyder, Site Quality Assurance Manager G. Swider, Engineering Manager - Programs T. Young, Security Manager

NRC personnel:

D. Rich, Chief, Branch 3, Division of Reactor Projects S. Ninh, Senior Project Engineer, Division of Reactor Projects W. Rogers, Senior Risk Analyst, Division of Reactor Safety LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened and Closed 05000335/2010003-01 NCV Inadequate Operations Procedure Results in Loss of 1B 125 v DC Bus (Section 4OA2.2). 05000389/2010003-02 NCV Untimely Corrective Actions to Resolve Seat Leakage of Containment Spray Valves 2-MV-07-3/4 (Section 4OA5.2)05000389/2010003-03 NCV Failure to Take Timely and Effective Corrective Actions to Prevent RCS Pressure Boundary Leakage through the RCP Seal Lines (Section 4OA5.3)

Closed 05000389/2009004-01 URI Untimely Corrective Actions to Resolve Seat Leakage of Containment Spray Valves 2-MV-07-3/4 05000389/2009004-02 URI Failure to Take Timely and Effective Corrective Actions to Prevent RCS Pressure Boundary Leakage through the RCP Seal Lines

05000335, 389/2515/173 TI Review of the Implementation of the Industry Ground Water Protection Voluntary Initiative (Section 4OA5)

05000335, 389/2515/180 TI Inspection of Procedures and Processes for Managing Fatigue (Section 4OA5)

05000389/2009-003-00 LER Reactor Coolant Pump 2B2 Lower Seal Cavity Line Leak (Section 4OA3.1)

Discussed

None LIST OF

DOCUMENTS REVIEWED

Nuclear Policy Procedure NP-910, Plant Readiness for Operations

ADM-29.03, Boric Acid Corrosion Control Program, Revision 6D

St. Lucie Nuclear Oversight Report PSL-09-064, Fire Protection Audit

Maintenance Rule Program Administration, NAP-415

Conduct of Operations, NAP-402

2-AOP-09.02, Auxiliary Feedwater System

SY-AA-100-1011, Fatigue Management, Rev. 1

AD-AA-101-1004, Work Hour Controls, Rev. 4

Section 2RS01: Occupational Dose

Procedures, Guidance Documents, and Manuals

FPL Nuclear Process Description PI-AA-204, Condition Identification and Screening Process,

Rev. 7

FPL Radiological Protection Procedure (RP)-SR-102-1001, Area Radiological Surveys and

analysis, Rev. 1

FPL RP-SR-103-1002, High Radiation Area Controls, Rev. 2

PSL Administrative Procedure (ADM)-09.05, Containment Entries Mode 1-4, Rev. 23

PSL Health Physics Procedure (HPP)-3, High Radiation Areas, Rev. 27

PSL HPP-22, Air Sampling, Rev. 22A

PSL HPP-30, Personnel Monitoring, Rev. 45

PSL HPP-42, Identification, Survey, and Release of Material, Rev. 4

PSL HPP-43, Control Inventory and Leak Testing of Radioactive Sources, Rev. 18A

PSL HPP-70, Personnel Contamination Monitoring, Rev. 25D

PSL HPP-74, Access Control Using Alarming Dosimeters, Rev. 8

PSL HPP-112, Multibadging, Rev. 25B

PSL HPP-116, Electronic Personnel Dosimeter Program, Rev. 20

HP-100-090630 Technical Basis Document: Alpha Characterization and Contamination

Monitoring, June 30, 2009

Records and Data Reviewed

CFR Part 61 Analysis Report, DAW Smears09-115, 8/19/2009

ALARA Plan SL1-23, Alloy 600 Project, Rev. 0

ALARA Package No. 2010-1042 task 1, Rev. 0

ALARA Package No. 2010-1424 task 1, Rev. 0

Air Sample 101-0019, U1 23 1A Instrument Air Compressor

Air Sample 101-1105, U1 RAB 19.5 Elevation Letdown Hallway

Alpha Air Sample Analysis Results U1, 4/18 - 5/05/2010

Form HP-43.1, Source Leak Test and Inventory Form, 2/16/10

Material Release Permit 05-266, 4/21/2010

Material Release Permit 05-290, 5/06/2010

Nuclear Materials Transaction Report AEC-741, 7/31/1975

Radiological Work Permit (RWP) 10-1042, UGS: Remove to lower cavity / Replace in reactor

vessel, Rev. 1

RWP 10-1424, LHRA Penetration Barriers - install, support, Rev. 2

RWP 10-1429, Alloy 600: I/L Drains Cut Outs and Welding, Rev. 4

Spreadsheet of Personnel Contamination Events (PCEs) for 2009, printed on 5/19/10

Spreadsheet of Personnel Contamination Events (PCEs) for 2010, printed on 5/19/10

St. Lucie 2010 Positive Whole Body Counts 4/19 - 4/22/2010

VSDS Survey PSL-M-20100119-6, HPS-170 ISFSI

VSDS Survey PSL-M-20100203-11, U1 RCB Lower Level - 18 / 23

VSDS Survey PSL-M-20100224-5, U2 FHB Spent Fuel Pool 62

VSDS Survey PSL-M-20100405-52, HPS-170 ISFSI

VSDS Survey PSL-M-20100424-11, U1 RCB 1A1 RCP Cold Leg Side View 18

VSDS Survey PSL-M-20100504-31, U1 RCB Top of Pressurizer 62

VSDS Survey PSL-M-20100510-33, Survey for Wagon Wheel Installation

VSDS Survey PSL-M-20100510-34, Survey for Wagon Wheel Installation

VSDS Survey PSL-M-20100510-35, Survey for Wagon Wheel Installation

VSDS Survey PSL-M-20100511-8, U1 RCB Top of Pressurizer 62

VSDS Survey PSL-M-20100510-59, U1 RCB 1B2 RCP Cold Leg Side View 18

VSDS Survey PSL-M-20100511-16, U1 RAB Daily Area Surveillance All

Corrective Action Program (CAP) Documents

2009 Annual RP Programmatic Assessment 2009-35688, December 2009

2009 Radioactive Source Control Assessment, December 2009

Condition Report (CR) 2009-3283, Personnel Contamination Event 2009-3, 2/4/09

CR 2009-9093, Individual received a rate alarm while deconning the lower cavity, 4/8/09

CR 2009-13870, EPD dose rate alarm, 5/7/09

CR 2009-14098, Dose rate alarm, 5/9/09

CR 2009-15125, Emergency responder entered RCA with EPD and no TLD, 5/19/09

CR 2010-3196, Individual logged into RCA dosimeter turned on but no transaction event in

sentinel, 2/8/10

CR 2010-9396, Dose alarm / Wrong RWP, 4/12/10

CR 2010-12596, Discrepancy discovered in Unit-1 FSAR, 5/12/10

CR 2010-12621, Typo in Unit 1 UFSAR Table 12.2-2,

CR 2010-9312, Procedure-HPP-39 Needs Reinforcement

Section 4OA5: Temporary Instruction 2515/173 - Review of the Implementation of the Industry

Ground Water Protection Voluntary Initiative

Procedures, Guidance Documents, and Manuals

Offsite Dose Calculation Manual, Revision (Rev. 32)

EV-AA-01, Fleet Groundwater Protection Program, Revision (Rev.) 0

EV-AA-100. FPL Nuclear Fleet Ground Water Protection Program, Rev. 1

EV-AA-100-1000, Groundwater Protection Program Communication/Notification Plan, Rev. 3

Administrative Procedure (ADM)-02-04, St. Lucie Ground Water Protection Program

0-Chemistry Operating Procedure (COP)-02.18, Chemistry Department Groundwater Protection

Sampling, Rev. 4A

0-COP-05.04, Chemistry Department Surveillances and Parameters, Rev. 49

HPP-101, Identification and Reporting of Radiological Events, Rev. 17D

Records and Data Reviewed

PSL 10 CFR 50.75(g) Records, January 1, 2008 - September 16, 2009

Radiological Evaluation of Effluent Releases from Remediation Well-2, April 2008

CAP Documents

Groundwater Assessment for FPL Saint Lucie Plant, September 25-29, 2006

FPL Quick Hit Self-Assessment, Industry Ground Water Protection Initiative - NEI 07 - 07

NEI Groundwater Protection Initiative, NEI Peer Assessment Report, 10/02/09

CR 2008-0065, Elevated groundwater tritium activity detected in RW-2 and GIS-MW-EI

CR 2008-01545, Packing leak on V07101 Unit 1 RWST

CR 2008-07351, Document and track items from February 26, 2008 groundwater tritium

meeting

CR 2008-16382, Lack of multi-discipline groundwater intrusion team change management plan

resulted in corrective action not brought to closure

CR 2008-16657, Track installation of proposed wells at selected locations

CR 2008-23299, U1 RWST V07101, clean area contamination

CR 2008-37241, November 2008 groundwater tritium results for 2 wells require CR and

notification of CFAM and site management

CR 2008-37391, Elevated tritium in U1 CCW sump

CR 2008-29957, July 2008 groundwater tritium results for 2 wells exceeding MDA

CR 2009-01561, Elevated tritium results for December 2008 samples on MW-15 and MW-4

CR 2009-07397, As found corrosion issues at U1/1B/ Waste Monitor Tank

CR 2009-07429, Leak in bottom of U1/ 1A/ Waste Monitor Tank

CR 2009-11408, MW-33 and MW-005 initial tritium results after installation >12,000 pCi/l

CR 2009-11409, Newly installed monitoring wells (MW)-30, U2 MW-004, and S-MW-17 had

initial samples positive for tritium

CR 2009-11418, Elevated tritium results for February 2009 samples on S-MW-6 and U2 MW-

2

CR 2009-19530, Elevated tritium results for June 2009 samples on MW-4 and U1 MW-005

CR 2009-21571, U1 SFP tell-tale (SH-25202) had 4 mls of liquid in catch container

CR 2009-23102, U1 SFP leakage

CR 2009-23110, NEI audit of PSLs groundwater protection program not completed within

appropriate time period

CR 2009-27896, S-MW-16 and S-MW19 showing positive results

CR 2009-29010, MW-6 and U1 MW-005 had elevated results for September 2009

CR 2009-30691, Results of completion of NEIs peer assessment of PSLs implementation of

GW protection initiative

CR 2010-00425, CCW leak at FE-14-1A

CR 2010-05448, Provide basis for reducing U1 ECCS trench inspection frequency from monthly

to every six months

CR 2010-12606, U1 Waste Monitor Tank licensing/design bases need clarification

Condition Reports

2010-8178

2010-8179

2010-8224

2010-8262

2010-8389

2010-8395

2010-8433

2010-8093

2010-8424

2010-8442

2010-8464

2010-8500

2010-8529

2010-8548

2010-8669

2010-8694

2010-8749

2010-8851

2010-10126

2010-10141

2010-10148

2010-10163

2010-10165

2010-11597

2010-12249

2010-12261

2010-12287

2010-12289

2010-12107

2010-12469

2010-12480

2010-12485

2010-12497

2010-12596

2010-12607

2010-12648

2010-13035

2010-13051

2010-13054

2010-13254

2010-13291

2010-13371

2010-13399

2010-13509

2010-13719

2010-13730

2010-13951

2010-13959

2010-14041

2010-14640

2010-14818

2010-14933

2010-14985

2010-15069

2010-15076

2010-15148

2010-15747

2010-15773

2010-15776

2010-15924

2010-15992

2010-16023

2010-16084

2010-16339

2007-24941

2007-4383

2007-42387

2008-3080

2009-19624

Section 4OA5: On-Site Fabrication of Components and Construction of an ISFSI (60853,

Revision 0)

Procedures

St. Lucie Plant Mechanical Maintenance Procedure 0-MMP-116.14 ISFSI DSC Transport from

CHF to HSM, Revision 6,

Plant Changes/Modifications (PCMs)

PC/M 08-060, Addition of New Unified Maintenance Facility

PC/M 08-093, Hurricane Hardening Modifications

Drawings

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 1,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 2,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 3,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 4,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 5,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 6,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 7,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 8,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 9,

Revision 0

ENG-08093-001, Off-Site Non-Power Block Outage and Utility Power System - Sheet 10,

Revision 0

ENG-08093-017, Yard Duct Runs, Revision 0

ENG-08060-002, Power Ductbank Relocation Plan & Profile, Revision 0

ENG-08060-003, Telecommunications Ductbank Relocation Plan & Profile, Revision 0

ENG-08060-004, Fire Protection Main Relocation Plan Profile, Revision 0

ENG-08060-007, Sanitary Sewer Relocation Plan, Revision 0

ENG-08060-008, Drainage Plan, Revision 0

ENG-08060-009, Miscellaneous Utilities Relocation Plan, Revision 0

Other

Consultant Report DRS-10-022, St. Lucie Independent Spent Fuel Storage Installation Project

Haul Path Report and Calculations, dated June 9, 2010. Note: This report was a detailed

review of the licensees calculations FPL 009-CALC-010, Fire Hazards Evaluation,

Revision 1; FPL 009-CALC-011, Explosion Hazards Evaluation for the St. Lucie ISFSI Cask

Hauling and Storage, Revision 1; and FPL029-PR-01, ISFSI Haul Path Walkdown,

Revision 0.

PSL-ENG-10-014, Engineering Evaluation for St. Lucie Unit 1 and 2 10CFR72 Exemption

Request, Revision 2

LIST OF ACRONYMS

AFW

Auxiliary Feedwater

AV

Apparent Violation

CAP

Corrective Action Program

CCW

Component Cooling Water

CFR

Code of Federal Regulations

CIV

Containment Isolation Valve

CR

Condition Report

CS

Containment Spray

DAW

Dry Active Waste

ECCS

Emergency Core Cooling System

ED

Electronic Dosimeter

EDG

Emergency Diesel Generator

EOP

Emergency Operating Procedure

GPI

Groundwater Protection Initiative

HP

Heath Physics

HPT

Health Physics Technician

HRA

High Radiation Area

HVAC

Heating, Ventilation, and Air Conditioning

ICW

Intake Cooling Water

IP

Inspection Procedure

IST

Inservice Testing

LER

Licensee Event Report

LHRA

Locked High Radiation Area

LIV

Licensee Identified Violation

MFIV

Main Feedwater Isolation Valve

MSIS

Main Steam Isolation Signal

MSIV

Main Steam Isolation Valve

NEI

Nuclear Energy Institute

NRC

Nuclear Regulatory Commission

OS

Occupation Radiation Safety

Radwaste

Radioactive Waste

RCA

Radiologically Controlled Area

Rev.

Revision

RG

Regulatory Guide

RP

radiation protection

RS

Public Radiation Safety

RTP

Rated Thermal Power

RWP

Radiation Work Permit

SAM

Small Article Monitor

SFP

Spent Fuel Pool

TI

Temporary Instruction

TS

Technical Specification

U1

Unit 1

U2

Unit 2

UFSAR

Updated Final Safety Analysis Report

VHRA

Very High Radiation Area

WO

Work Order