IR 05000335/2014005

IR 05000335/2014005, 05000389/2014005; on 10/01/2014 - 12/31/2014; on St. Lucie Nuclear Plant, Units 1 & 2; Problem Identification and Resolution

ML15030A323
Person / Time
Site:	Saint Lucie
Issue date:	01/30/2015
From:	Shane Sandal NRC/RGN-II/DRP/RPB3
To:	Nazar M Nextera Energy
References
IR 2014005
Download: ML15030A323 (29)

Text

UNITED STATES anuary 30, 2015

SUBJECT:

ST. LUCIE PLANT - NRC INTEGRATED INSPECTION REPORT 05000335/2014005 AND 05000389/2014005

Dear Mr. Nazar:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your St. Lucie Plant Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on January 15, 2015, with Mr. Jensen and other members of your staff.

NRC inspectors documented a self-revealing finding of very low safety significance (Green) in this report. This finding involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the St. Lucie Plant.

If you disagree with the 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 Plant. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Shane Sandal, Branch Chief (Acting)

Reactor Projects Branch 3 Division of Reactor Projects Docket Nos. 50-335, 50-389 License Nos. DPR-67, NPF-16

Enclosure:

IR 05000335/2014005, 05000389/2014005 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-335, 50-389 License Nos: DPR-67, NPF-16 Report Nos: 05000335/2014005, 05000389/2014005 Licensee: Florida Power & Light Company (FP&L)

Facility: St. Lucie Plant, Units 1 & 2 Location: 6501 South Ocean Drive Jensen Beach, FL 34957 Dates: October 1, 2014 through December 31, 2014 Inspectors: T. Morrissey, Senior Resident Inspector J. Reyes, Resident Inspector P. Capehart (Section 1R11.3)

M. Riches, Project Engineer, (Sections 4OA2.3 and 4OA3.2)

J. Rivera-Ortiz, Senior Reactor Inspector, (Section 4OA2.4)

Approved by: Shane Sandal, Branch Chief (Acting)

Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000335/2014005, 05000389/2014005; 10/01/2014 - 12/31/2014; St. Lucie Nuclear Plant,

Units 1 & 2; Problem Identification and Resolution The report covered the three-month period of inspection from October 1, 2014, to December 31, 2014. The inspection activities were performed by the resident inspectors and specialist inspectors from the Region II office. One self-revealing Green NCV was documented during this inspection period. The significance of inspection findings are indicated by their color (Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process, (SDP) dated June 2, 2011. The cross-cutting aspect was determined using IMC 0310, Components Within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements were dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision

Cornerstone: Mitigating Systems

Green.

A self-revealing, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, resulted from the licensees failure to implement work order instructions to install Unit 2 safety-related vent valve V3811 in accordance with dimensions specified by the engineering design. The failure to implement the work order instructions was a performance deficiency that resulted in inoperability of the emergency core cooling system (ECCS) Class 1 pressure boundary due to a through-wall crack and self-revealing leak. The licensee entered the issue into the corrective action program (CAP)as action request (AR) 01980340 and completed corrective actions to repair the leak and install V3811 with the correct dimensions.

The performance deficiency was more than minor because it adversely impacted the operability of safety-related equipment that mitigates the consequences of a loss of coolant accident, and therefore, was associated with the equipment reliability attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened the finding under the mitigating systems cornerstone using Attachment 4 (June 19, 2012) and Appendix A (June 19, 2012) of Inspection Manual Chapter 0609, Significance Determination Process (June 2, 2011). The inspectors determined the finding required a detailed risk evaluation because the finding was associated with a loss of high pressure safety injection (HPSI) system function and evaluated the condition using the significance determination process (SDP)module in the St. Lucie Unit 2 Standardized Plant Analysis Risk (SPAR) model. The change in core damage frequency (CDF) was greater than the 1E-7 threshold and the issue was reviewed by a regional senior reactor analyst (SRA) to confirm the result and verify that external events contribution would not cause the results to increase above 1E-6. The SRA used the same St. Lucie Unit 2 SPAR model, and made the following adjustments: set the exposure time to 51 days (half of the entire period that Unit 2 was in an operating condition),

the safety injection tank (SIT) discharge check valve and the reactor coolant system (RCS)check valve were failed in the SPAR model (i.e., set to a value of 1.0), and common cause failure events were not increased since an extent of cause evaluation did not identify additional examples of the performance deficiency. The SRA confirmed the inspectors conclusion that the issue was of very low risk significance (Green). The analyst determined that there was additional margin to the green-white threshold because: 1) the analysis assumed that the injection flows from the SIT and the high pressure injection system on one of four paths were completely failed when there would likely have been some injection flow under postulated break conditions, 2) the potential break size was limited to only a portion of the possible spectrum of small break loss of coolant accident (SBLOCA) sizes due to the physical size of the pipe, and 3) this issue was an isolated example, unlike other recent RCS leaks that have occurred in the industry which were of a repetitive and long-standing nature.

The inspectors concluded the finding was associated with the cross-cutting aspect of procedural adherence (H.8) in the human performance area because maintenance personnel did not adhere to work order instructions concerning the dimensions of the vent valve assembly. (4OA2.3)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power (RTP). On October 15, power was lowered to 97 percent RTP to support moderator temperature coefficient testing.

The unit was returned to 100 percent RTP on October 16. The unit was at 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent RTP. On November 12, the unit was manually tripped when the operators noticed lowering B steam generator water level due to an unplanned closure of a main feedwater isolation valve (MFIV). The unit was restarted on November 18 and reached 100 percent RTP on November 19. The unit was at 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

Seasonal Winter Weather Conditions

a. Inspection Scope

The inspectors reviewed the licensees implementation of the stations cold weather preparations as described in procedure 0-NOP-99.06, Cold Weather Preparations. The inspectors verified conditions were met for entering the subject procedure and that equipment status was verified as directed by the procedure. Action requests (ARs) were checked to ensure that the licensee was identifying and resolving weather-related issues and that corrective actions from the previous cold weather season had been satisfactorily resolved. The inspectors performed a walkdown of the following safety-related equipment on both units that are exposed to the outside weather conditions to identify any potential adverse conditions.

• Unit 1 and Unit 2 emergency diesel generator (EDG) rooms

• Unit 1 and Unit 2 MFIV areas

• Unit 1 and Unit 2 auxiliary feed water (AFW) pump areas

• Unit 1 and Unit 2 refueling water tank (RWT) areas

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Equipment Walkdowns

a. Inspection Scope

The inspectors conducted three 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 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 and that those issues were documented in the corrective action program (CAP). Documents reviewed are listed in the Attachment.

• Unit 1, 1A and 1B AFW trains while 1C AFW pump was out of service (OOS) during surveillance testing

• Unit 1, 1A and 1B EDG trains and associated 4160V Engineered Safeguards (ES)buses while 1A and 2A startup transformers were OOS for planned maintenance

• Unit 1, A and B high pressure safety injection (HPSI) and containment spray pumps while the 1A EDG was OOS for testing.

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed walkdown or review of the alignment and condition of the Unit 2 intake cooling water (ICW) system to verify its capability to meet its design basis function. The inspectors utilized the licensee procedures listed in the Attachment, as well as other licensing and design documents, to verify the system alignment was correct. During the walkdown, the inspectors verified that:

(1) valves were correctly positioned and did not exhibit leakage that would impact their function;

(2) electrical power was available as required;

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

(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;

(7) tagging clearances were appropriate; and

(8) valves were locked as required by the licensees locked valve program. 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 (WOs). 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 performed walkdowns of six 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 CAP database to verify that fire protection problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment. The following areas were inspected:

• Unit 2, A and B electrical penetration rooms

• Unit 1 and Unit 2 alternate shutdown panel rooms

• Unit 2, EDG engine rooms

• Unit 2, condensate storage tank building

• Unit 1 main and 1A / 2A start-up transformer areas

• Unit 1, 1A and 1B spent fuel pool pumps and heat exchanger rooms

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed the two fire drills listed below. The drills were 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 post drill critique meeting, and implemented 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 firefighting 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. Documents reviewed are listed in the Attachment. Inspection of the drills listed below completes the annual assessment of licensee fire brigade performance.

• December 12, 2014 announced drill associated with a simulated 2D instrument air compressor motor fire

• December 23, 2014 unannounced drill that simulated a 2D battery charger fire

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On October 6, 2014, the inspectors observed and assessed licensed operator actions during the annual training requalification exam in the control room simulator. The simulated scenario involved a failed open pressurizer power operated relief valve, a manual reactor trip subsequent to a loss of two reactor coolant pumps, a stuck open steam generator safety valve, and a reactor coolant system (RCS) leak in containment.

Additionally, the scenario included an Emergency Alert classification for the loss of the RCS barrier, and notification to the state and the NRC. Documents reviewed are listed in the Attachment. 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 abnormal and emergency operation procedures, and emergency plan implementing procedures

• Control board operation and manipulation, including high-risk operator actions

• Oversight and direction provided by supervision, including ability to identify and implement appropriate technical specification (TS) 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.

.2 Control Room Observations

a. Inspection Scope

The inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Specifically, the inspectors observed activities in the control room during the following evolutions:

• Unit 2, November 10, 2014 pre-job briefing, startup and testing of 2A EDG.

• Unit 2, November 16-18, 2014 control room startup activities subsequent to a forced outage. Activities include: Post maintenance testing of AFW pump discharge valve MV-09-10, reactor coolant system heat-up, and reactor plant startup to Mode 1.

The inspectors focused on the following conduct of operations attributes as appropriate:

• Operator compliance and use of procedures

• Control board manipulations

• Communication between crew members

• Use and interpretation of plant instruments, indications and alarms

• Use of human error prevention techniques

• Documentation of activities, including initials and sign-offs in procedures

• Supervision of activities, including risk and reactivity management

b. Findings

No findings were identified.

.3 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On December 11, 2014, the licensee completed the annual requalification operating examinations required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, Licensed Operator Requalification Program. These results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the performance data and associated ARs for two equipment issues 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 10 CFR 50.65, The Maintenance Rule (MR). The inspectors efforts focused on maintenance rule scoping, characterization of maintenance problems and failed components, risk significance, determination of MR 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 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. Documents reviewed are listed in the Attachment. The equipment issues reviewed are listed below:

• AR 2005927, Re-scoping intake cooling water and component cooling water systems

• AR 1910676, Instrument air 1D compressor MRFF a(1) recommendation

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 on-line and shutdown 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; and licensee administrative 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) or shutdown safety assessment (SSA) for the combinations of out of service (OOS) risk significant systems, structures, and components (SSCs) listed below. Documents reviewed are listed in the Attachment.

• Unit 1, OLRM assessment with the Unit 1A and Unit 2A startup transformers OOS for planned maintenance and high risk on the intake cooling water structure due to high density of jelly fish

• Unit 2, OLRM assessment with the A train of emergency core cooling system (ECCS) and the C instrument air compressor unavailable during AFW actuation system relay testing, and a high risk on the intake cooling water structure due to high density of jelly fish

• Unit 2, SSA while in Mode 5, pressurizer bubble with RCS pressure at 260 psi and temperature at 175 F, two reactor coolant pumps in operation and two shutdown cooling trains in operation and a containment closure crew available to close the personnel hatch

• Unit 1, OLRM assessment with 1A EDG and 1A HPSI pump OOS for testing, containment valves V25011 and V-25-12 open with a dedicated operator at controls

• Unit 2, OLRM assessment with 2B ECCS OOS due to RWT and containment sump valve surveillance; and 2C charging pump OOS for planned maintenance

• Unit 1, OLRM assessment with the1B train of ECCS unavailable while performing planned maintenance on the HPSI pump discharge valve V3654, and with the control element assembly OOS while performing full length and block circuit surveillance testing

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed five ARs interim dispositions and operability determinations or functionality assessments to ensure that they were 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. The following ARs were reviewed:

• AR 2000519, 2B EDG KW spikes outside the procedural acceptance criteria during surveillance testing

• AR 1997636, Unit 2 AFW actuation signal bypass relay slow reaction

• AR 2007918, Unit 1B EDG lube oil leak during surveillance

• AR 1943652, Unit 2 control room boundary breach

• AR 2004997, Unit 2 2A2 cold leg resistance temperature detector (RTD) reading low

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For five maintenance WOs, the inspectors reviewed the test procedures and either witnessed 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. Documents reviewed are listed in the Attachment.

The WOs are listed below:

• WO 40234106, Replace U2 AFW actuation system (AFAS) battery failure bypass relay

• WO 40345081, C instrument air compressor relief valve and engine repair

• WO 40350168, Unit 2 MFIVs valves HCV-09-2A and HCV-09-2B relay replacements

• WO 40351737, Unit 2B AFW discharge valve MV-09-10 breaker maintenance

• WO 40355115, Repair 1A ICW debris filter system cracked weld

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Unit 2 Unplanned Outage: Repair Main Feedwater Isolation Valve HCV-09-2B and Replace Control Element Assembly (CEA) 35 Coil Stack

a. Inspection Scope

On November 12, Unit 2 was manually tripped when the operators noticed lowering B steam generator water level due to an unplanned closure of MFIV HCV-09-2B. During the shutdown, the MFIV was repaired and the coil stack for Control Element Assembly 35 was replaced. In September 2014, the upper gripper coil for CEA 35 was found to be degraded and the CEA had been transferred to its lower gripper coil. The unit was cooled down to Mode 5 (<200oF) in order to replace the CEA coil stack.

Outage Planning, Control and Risk Assessment The inspectors reviewed the licensees outage risk control plan and schedule to verify that the licensee had appropriately considered risk, industry experience and previous site specific problems.

Monitoring of Shutdown Activities The inspectors observed portions of the cooldown process to verify that technical specification cooldown restrictions were followed. The inspectors conducted a containment walkdown after the shutdown to assess the condition of the systems within containment that are inaccessible with the unit at power. The inspectors performed walkdowns of important systems and components used for decay heat removal from the reactor core during the shutdown period including the intake cooling water and component cooling water systems.

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:

• 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 operation

• Evaluated implementation of reactivity controls

• Examined containment foreign material exclusion controls put in place for the limited work inside containment 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 verified containment integrity was properly established. The inspectors performed a containment closeout inspection prior to startup. The inspectors witnessed portions of the RCS heat up, reactor startup, and power ascension. On November 18, the inspectors verified that startup activities were performed in accordance with licensee general operating procedures 2-GOP-302, Reactor Startup - Mode 3 to Mode 2, and 2-GOP-201, Reactor Startup - Mode 2 to Mode 1.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors either reviewed or witnessed four surveillance tests to verify that the tests met 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 standby alignment required for the system to perform its safety function. The inspectors verified that surveillance issues were documented in the CAP. Documents reviewed are listed in the

. The following surveillances were reviewed:

Surveillance Tests:

• 2-OSP-69.24, Engineered Safeguards Test, Train A

• 2-SMI-08.05A, Steam Generator Pressure Loop Check and Calibration Channel A, P8013A, P8023A (channel P8013A only)

• 1-OSP-59.01A, 1A Emergency Diesel Generator Monthly Surveillance

• 1-OSP-66.01, Control Element Assembly Quarterly Exercise

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation Emergency Preparedness Drills

a. Inspection Scope

On October 29, 2014, the inspectors observed the simulator control room and the technical support center staff during a drill of the site emergency response organization to verify the licensee was properly classifying emergency events, making the required notifications, and making appropriate protective action recommendations. The scenario included a loss of offsite power that degraded into a station blackout condition. Plant conditions degraded to a point where the licensee declared an Alert and later, a General Emergency. During the drill, the inspectors assessed the licensees actions to verify that emergency classifications and notifications were made in accordance with licensee emergency plan implementing procedures (EPIPs) and 10 CFR 50.72 requirements.

The inspectors specifically reviewed the classifications and notifications to verify they were in accordance with licensee procedures EPIP-01, Classification of Emergencies, and EPIP-02, Duties and Responsibilities of the Emergency Coordinator. The inspectors also observed whether the initial activation of the emergency response centers was timely and as specified in the licensees emergency plan and that the licensee identified critique items and drill weaknesses were captured in the CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors checked licensee submittals for the Unit 1 and Unit 2 mitigating system performance indicators (PIs) listed below for the period October 1, 2013 through September 30, 2014, to verify the accuracy of the PI data reported during that period.

Performance Indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures ADM-25.02, NRC Performance Indicators, and LI-AA-204-1001, NRC Performance Indicator Guideline, 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. The PIs reviewed are listed below:

• Emergency AC power

• Residual heat removal system

• Heat removal system

• High pressure injection system

• Cooling water system

a. 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 action requests and by reviewing the licensees electronic AR 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 Semi-Annual Trend Review:

a. Inspection Scope

Inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1, plant status reviews, plant tours, and licensee trending efforts. The inspectors review nominally considered the six month period of July 2014 through December 2014, although some examples expanded beyond those dates when the scope of the issue warranted.

The inspectors reviewed AR 1960682, which documented an adverse trend associated with the quality of maintenance work instructions. This trend was identified in April 2014 after the site had accumulated several non-cited violations with cross cutting aspect H.7 (complete, accurate documentation) over the previous year. In the 3rd quarter 2014, the licensee closed an adverse trend associated with maintenance work practices to this AR.

The inspectors also reviewed AR 2009517 that identified a potential trend with equipment issues associated with both units control rod drive systems. Two Unit 2 control rod drive system upper gripper coils were found degraded. One coil was replaced at the end of the spring 2014 refueling outage (RFO) and the other was replaced during the November 2014 forced outage. Over the last several months, Unit 1 experienced several control rod system upper gripper coil power switch failures. The power switches were replaced after placing the associated CEA on the hold bus.

The inspectors evaluated the licensees administration of both action requests in accordance with the CAP as specified in licensee procedure PI-AA-104-1000, Corrective Action. Documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings were identified. The inspectors identified two adverse trends that were also identified by the licensee. One trend was associated with maintenance work order quality and the other with control rod system equipment failures. Corrective actions implemented at the completion of this inspection period for both adverse trends appeared reasonable.

The licensees root cause evaluation (RCE) 1960682, documented that work order quality did not always support first time quality for task completion. The licensee determined that required pre-job walkdowns were not performed with adequate rigor.

Failure to perform these walkdowns adequately resulted in gaps in work order instruction quality and rework. The term walkdown used in this regard includes performing such things as: vendor manual review, work order instruction reviews, job site review and table top reviews. Corrective actions included developing criteria to measure walkdown quality and holding personnel accountable to complete pre-job walkdowns.

Degraded control rod system performance increases the probability of a dropped rod and plant transient. Licensee short term corrective actions include performing monthly monitoring (traces) of upper gripper coil and circuit performance for Unit 1 and doing the same monitoring on a weekly basis for Unit 2. By the end of this inspection period, a licensee team was established to determine long-term corrective actions.

.3 Annual Sample Review: Root Cause Evaluation Associated with Through-wall Crack on

Vent Valve V3811 Piping

a. Inspection Scope

On July 25, 2014, the licensee identified a leak on the piping associated with the V3811 valve assembly on Unit 2. V3811 is a manual vent valve mounted on the ECCS cold leg injection header and is located downstream of the 2B1 safety injection tank (SIT) and the tie-in point for the low pressure safety injection (LPSI) and high pressure safety injection (HPSI) systems. The licensee determined that, based on the leak location, the 2B1 SIT was inoperable and action statement b of LCO 3.5.1, Safety Injection Tanks (SIT) was entered. This required restoration of 2B1 SIT to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in Hot Standby condition within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Hot Shutdown condition within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Unit 2 reactor shutdown was performed on July 26, 2014. The licensee entered the event into the corrective action program as AR 1980340 and performed a root cause evaluation of the event. The root cause evaluation was reviewed by the inspectors in detail to evaluate the effectiveness of the licensees corrective actions. The inspectors verified the licensees actions were in accordance with licensee procedures, PI-AA-204, Condition Identification and Screening, and PI-AA-205, Condition Evaluation and Corrective Actions.

b. Findings and Observations

Introduction:

A Green, self-revealing, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, resulted from the licensees failure to implement work order instructions to install Unit 2 safety-related vent valve V3811 in accordance with dimensions specified by the engineering design.

Description:

On March 17, 2014, welders installed a Class 1, one-inch manual vent valve assembly (V3811) onto the ECCS cold leg injection pipe downstream of the common tie-in points of the HPSI system, the LPSI system, and the 2B1 SIT. Step 15 in the task instruction for WO 40196531-04 directed that the new valve assembly be welded in accordance with isometric drawing 2998-C-124, Sheet SI-64 (revision 15).

The isometric drawing specified that the dimension of the piping between the top of the ECCS cold leg injection pipe and the bottom of vent valve V3811 be 3-1/8 inches (in.)

long. This dimension provided for an intended 7/8 in. space between the welds.

Contrary to the work order instructions, the pipe was shortened during field installation to approximately 2-1/4 in. which allowed the toes of the top and bottom welds to make contact. This weld-to-weld physical contact contributed to a stress riser in the pipe wall below valve V3811 that resulted in a circumferential 225° through-wall crack with partial wall cracking through approximately 67.5° of the remaining pipe circumference after V3811 was returned to service. This condition was revealed when (in response to elevated Unit 2 containment particulate radiation monitor readings) the licensee made a containment entry that identified the through-wall leak on the vent pipe below V3811.

On July 26, 2014, the licensee declared the ECCS Class 1 pressure boundary inoperable due to the through-wall flaw and shut down the reactor to repair the condition.

The licensee entered the issue into the corrective action program as AR 01980340 and completed repairs on July 28, 2014. The inspectors noted that Unit 2 operated for approximately 101 days in Mode 3 (or above) with the V3811 weld configuration described above.

The NRC performed an independent evaluation of the flaw using the criteria from Appendix C, Flaw Evaluations for Fully-Plastic Fracture Using Limit Load Criteria, in Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, of the American Society of Mechanical Engineers (ASME) Code, 2010 Edition. The inspectors concluded that the as-found flaw size exceeded acceptance criteria and challenged the assurance that the flaw would not propagate to complete failure under design basis conditions (i.e., ECCS actuation). Based on the location of the vent line, a rupture of the piping would have diverted flow from the HPSI system during a small break loss of coolant accident (SBLOCA) and the 2B1 SIT during a large break loss of coolant accident (LOCA). Although ECCS flow would also have been diverted from the LPSI system in the event of a LOCA, the inspectors concluded that the diverted flow through a one-inch vent line at the lower injection pressure would be small when compared to the overall flow capacity of the LPSI system. The inspectors determined that these factors called into question the operability of the HPSI system and the 2B1 SIT prior to the licensees discovery of the issue on July 26, 2014.

Analysis:

The licensees failure to implement WO 40196531-04 instructions to install V3811 in accordance with the dimensions specified by the design isometric drawing was a performance deficiency. The performance deficiency was more than minor because it resulted in a through-wall flaw that adversely impacted the operability of safety-related equipment intended to mitigate the consequences of a loss of coolant accident.

Therefore, the inspectors concluded that the performance deficiency was associated with the equipment reliability attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened the finding under the mitigating systems cornerstone using Attachment 4 (June 19, 2012) and Appendix A (June 19, 2012) of Inspection Manual Chapter 0609, Significance Determination Process (June 2, 2011).

The inspectors determined the finding required a detailed risk evaluation because it was associated with a loss of HPSI system function and evaluated the condition using the significance determination process (SDP) module in the St. Lucie Unit 2 Standardized Plant Analysis Risk (SPAR) model. The change in core damage frequency (CDF) was greater than the 1E-7 threshold and was subsequently reviewed by a regional senior reactor analyst (SRA) to confirm the result and verify that external events contribution would not cause the results to increase above 1E-6. The SRA used the same St. Lucie Unit 2 SPAR model, and made the following adjustments: set the exposure time to 51 days (half of the entire period that Unit 2 was in an operating condition), the SIT discharge check valve and the reactor coolant system (RCS) check valve were failed in the SPAR model (i.e., set to a value of 1.0), and common cause failure events were not increased since an extent of cause evaluation did not identify additional examples of the performance deficiency. The SRA confirmed the inspectors conclusion that the issue was of very low risk significance (Green). The analyst determined that there was additional margin to the green-white threshold because: 1) the analysis assumed that the injection flows from the SIT and the high pressure injection system on one of four paths were completely failed when there would likely have been some injection flow under postulated break conditions, 2) the potential break size was limited to only a portion of the possible spectrum of small break loss of coolant accident (SBLOCA) sizes due to the physical size of the pipe, and 3) this issue was an isolated example, unlike other recent RCS leaks that have occurred in the industry which were of a repetitive and long-standing nature. The inspectors concluded the finding was associated with the cross-cutting aspect of procedural adherence (H.8) in the human performance area because maintenance personnel did not adhere to work order instructions concerning the dimensions of the vent valve assembly.

Enforcement:

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances; and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on March 17, 2014, the licensee failed to accomplish WO 40196531-04 instructions to install ECCS cold leg injection vent valve V3811 with 3-1/8 in. clearance between the cold leg injection header and the bottom of the valve. This created stress risers in the pipe wall that resulted in a through-wall leak and inoperability of the ECCS Class 1 pressure boundary. The licensee entered the issue into the corrective action program (CAP) as action request (AR) 01980340 and completed immediate corrective action to repair V3811 and restore the correct weld configuration on July 28, 2014. (NCV 05000389/2014005-01, Failure to Follow Work Instructions during Installation of Unit 2 Vent Valve V3811)

.4 Annual Sample Review: Design Basis Review for Unit 2 Steam Generator

Tube-to-Tubesheet Joint

a. Inspection Scope

The inspectors selected AR 01955927, Root Cause Evaluation: Unit 2 S/G Hot Leg Foreign Object, and AR 02011678, Design Basis Review for Steam Generator Tubesheet Design, for a more in-depth review of the circumstances and licensees evaluation. The AR reports were reviewed to verify that the licensee had planned, and/or implemented, corrective actions commensurate with the significance of the identified issue. The inspectors evaluated the licensees assessment of operability for the Unit 2 steam generators (SGs), to verify adequate technical justification for operation was provided. The inspectors interviewed plant personnel and evaluated the action request in accordance with the requirements of the licensees corrective action process, as specified in procedure PI-AA-104-1000, Corrective Action.

b. Findings and Observations

(Opened) Unresolved ltem 05000389/2014005-02, Design Basis Review for Unit 2 Steam Generator Tube-to-Tubesheet Joint

Introduction:

The inspectors identified an unresolved item (URI) associated with the design of the tube-to-tubesheet joint for the Unit 2 replacement SGs.

Description:

In April 2014, the channel head of Unit 2 SG-2B experienced impingement damage in the hot leg side, due to a foreign object in the reactor coolant system. The extent of the damage included impingement marks on the tube-to-tubesheet welds. The licensee entered the issue in the CAP as AR 01955927. The inspectors reviewed the licensees one-cycle operability evaluation for this condition (Areva Report 51-9222481-000) to verify that the licensee provided adequate technical justification demonstrating that the SG would be capable of performing its design function, particularly to maintain tube integrity, during the current cycle. The inspectors did not identify an issue of concern with the licensees operability conclusions, but issued a URI to determine if the foreign material intrusion issue constituted a performance deficiency and/or a violation of NRC requirements. In October 2014, the NRC closed the URI with a non-cited violation for the failure to follow the requirements in reactor vessel maintenance procedures. The inspectors review and disposition of this issue was documented in NRC Inspection Report 05000389/2014004 (ADAMS Accession Number ML14293A668).

From October to December 2014, the inspectors had further discussions with the licensee, and reviewed the planned corrective actions to address Unit 2 SG-2B operability for future plant operating cycles. In their review, the inspectors identified an issue of concern related to the design approach for the tube-to-tubesheet welds in the Unit 2 replacement SGs. Specifically, the licensees operability evaluation addressing the impingement damage for the current cycle described the weld at the end of each tube as a seal weld, without further discussion about the structural function of the weld.

The inspectors determined that it was necessary to confirm whether the Unit 2 SG tube end welds were credited in the structural analysis of the tube-to-tubesheet joint under design basis loads. The inspectors determined that additional information from the SG vendor was needed to understand the design approach and qualification for the tube-to-tubesheet joint, including the welds.

This issue of concern with the tube-to-tubesheet welds did not adversely affect the licensees operability conclusions for the current cycle. The operability evaluation for SG-2B contained technical data from the vendor to demonstrate that the tube structural integrity and primary-to-secondary leakage criteria would not be challenged due to the performance of the mechanically expanded portion of the tube inside the tubesheet. The licensee provided sufficient information about the tube-to-tubesheet joint design to provide reasonable assurance that the joint, considering the impingement damage to the tube end welds, would meet the performance criteria for SG tube integrity required in the plants Technical Specifications.

This issue is unresolved pending review of additional information from the licensee on the specific design and qualification approach for the Unit 2 SG tube-to-tubesheet joint, particularly the tube end weld. The licensee communicated to the inspectors that this issue only applies to Unit 2 because the tube-to-tubesheet welds of Unit 1 SGs were designed as structural welds, with no credit for the tube-to-tubesheet expansion. The inspectors will address the extent of this condition for Unit 1 SGs as part of the resolution of this issue. The licensee entered this issue in the CAP as AR 02011678, Design Basis Review for Steam Generator Tubesheet Design. This issue will be tracked as URI 05000389/2014005-02, Design Basis Review for Unit 2 Steam Generator Tube-to-Tubesheet Joint.

4OA3 Followup of Events and Notice of Enforcement Discretion

.1 Unit 2 Manually Tripped Due to Loss of Feed to B Steam Generator

On November 12, 2014, Unit 2 was operating at approximately 100 percent RTP when the control room operators noticed a lowering B steam generator water level due to closing of a MFIV. The operators initiated a manual reactor trip when the B steam generator water level reached 50 percent as indicated on the narrow range water level instruments. Further reduction of water level to 35 percent would have resulted in an automatic reactor trip.

The inspectors were notified of the reactor trip and responded to the control room to assess plant conditions and determine if any complications occurred during the trip and reactor plant shutdown. The inspector observed Unit 2 control room activities following the shutdown to hot standby. The inspector reviewed control room chronological logs, control room indications, post trip procedures, and interviewed control room operators to verify that operating restrictions and procedural requirements were met. The inspector observed control room operator communications, procedure place keeping, and control room annunciator responses by the reactor operators at the control boards. The inspector reviewed documentation and operator actions associated with licensee emergency operating procedures 2-EOP-01, Standard Post Trip Actions, and 2-EOP-02, Reactor Trip Recovery. Licensee troubleshooting determined that a high resistive short across two terminals for a relay associated with the MFIV caused the valve to slowly close. The short appeared to be caused by a buildup of corrosion products between the terminals. The shorted relay terminals resulted in a B steam generator MFIV closing and lowering steam generator water level. Corrective actions included: replacement of two relays and sealing of all conduits connected to the four MFIV relay boxes. On November 18, the reactor was restarted subsequent to replacement of several relays and sealing of the MFIV relay box. The inspectors observed portions of the restart activities.

.2 (Discussed) Licensee Event Report (LER) 05000389/2014-001-00, Unit Shut Down due

to Leak on Safety Injection Tank Vent Valve Piping On June 22, 2014, Unit 2 was operating at 100 percent power, when the licensee received indications of a leak inside primary containment. Based on a trend review of level in the 2B1 SIT and increased readings on containment particulate process radiation monitors, the licensee concluded the leak was associated with piping in communication with the 2B1 SIT. After several containment entries, on July 25, 2014 the licensee obtained detailed video imaging that confirmed the leak was on a one-inch pipe between the ECCS cold leg injection header and vent valve V3811. The licensee subsequently performed a reactor shutdown and replaced the V3811 vent valve assembly. The licensee performed a root cause evaluation, which determined that the root cause of the event was due to the failure to install the vent valve assembly in accordance with the instructions contained in the work order, which directed the valve assembly to be welded as specified by isometric drawing 2998-C-124, Sheet SI-64, revision 15. The dimensions of the piping associated with the valve assembly were not in accordance with the drawing. The licensee also determined that a contributing cause to the event was the failure of the maintenance personnel and the non-destructive examination (NDE) inspector to verify the dimensions of the field-cut pipe nipple before the vent valve assembly was welded to the ECCS inlet header. The inspectors reviewed the LER. The inspectors evaluated the accuracy of the information submitted in the LER, and the licensees conformance with regulatory requirements. The inspectors evaluated the licensees root cause evaluation as well as the corrective actions to determine if the actions appropriately addressed the causes that were identified in the licensees root cause evaluation. A Green non-cited violation associated with the circumstances that resulted in the formation of the leak is discussed in Section 4OA2 of this report. The licensee is currently evaluating a supplement to the LER. This LER will remain open until the inspectors have reviewed any changes to the revised LER.

4OA6 Meetings

Exit Meeting Summary

The resident inspectors presented the inspection results to Mr. Jensen and other members of licensee management on January 15, 2015. 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

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

J. Jensen, Site Vice President

N. Bach, Chemistry Manager

M. Haskin, Projects Manager

M. Jones, Engineering Director

D. DeBoer, Operations Director

M. Baughman, Training Manager

B. Coffey, Plant General Manager

E. Katzman, Licensing Manager & Emergency Preparedness Manager

R. McDaniel, Fire Protection Supervisor

C. Martin, Health Physics Manager

J. Piazza, Maintenance Director

D. Pitts, Assistant Operations Manager

M. Snyder, Nuclear Quality Assurance Manager

C. Workman, Security Manager

NRC personnel

Shane Sandal, Branch Chief (Acting), Branch 3, Division of Reactor Projects

John Hanna, Senior Reactor Analyst, Division of Reactor Projects

LIST OF ITEMS

Opened and Closed

05000389/2014005-01 NCV Failure to Follow Work Instructions during Installation of Unit 2 Vent Valve V3811 (Section 4OA2.3)

Opened

05000389/2014005-02 URI Design Basis Review for Unit 2 Steam Generator Tube-to-Tubesheet Joint (Section 4OA2.4)

Discussed

05000389/2014-001-00 LER Unit Shut Down Due to Leak on Safety Injection Tank Vent Piping (Section 4OA3.2)