IR 05000335/2013004

IR 05000335-13-004 & 05000389-13-004; on 07/01/2013 - 09/30/2013; St. Lucie Nuclear Plant, Units 1 & 2; Heat Sink Performance; Follow-up of Events and Notice of Enforcement Discretion

ML13302C066
Person / Time
Site:	Saint Lucie
Issue date:	10/29/2013
From:	Gregory Kolcum NRC/RGN-II/DRP/RPB3
To:	Nazar M Florida Power & Light Co
References
IR-13-004
Download: ML13302C066 (6)

Text

UNITED STATES October 29, 2013

SUBJECT:

ST. LUCIE PLANT - NRC INTEGRATED INSPECTION REPORT 05000335/2013004 AND 05000389/2013004

Dear Mr. Nazar:

On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your St. Lucie Plant Units 1 and 2. On October 11, 2013, the NRC inspectors discussed the results of this inspection with Mr. Jensen and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented two findings of very low safety significance (Green) in this report.

One of these findings involved a violation of NRC requirements. Additionally, NRC inspectors documented one Severity Level IV violation with no associated finding. Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating these violations as noncited violations (NCV)

consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of 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 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 Power Plant.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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/

Gregory J. Kolcum, Acting Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos.: 50-335, 50-389 License Nos.: DPR-67, NPF-16

Enclosure:

Inspection Report 05000335/2013004, 05000389/2013004 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-335, 50-389 License Nos: DPR-67, NPF-16 Report Nos: 05000335/2013004, 05000389/2013004 Licensee: Florida Power & Light Company (FP&L)

Facility: St. Lucie Plant, Units 1 & 2 Location: 6501 South Ocean Drive Jensen Beach, FL 34957 Dates: July 1, 2013, to September 30, 2013 Inspectors: T. Morrissey, Senior Resident Inspector J. Reyes, Resident Inspector P. Carman, Project Engineer J. Rivera-Ortiz, Senior Reactor Inspector (Section 1R07)

J. Hanna, Senior Reactor Analyst (Section 4OA3.2, 4OA3.3)

M. Riches, Project Engineer (Section 4OA5.2)

A. Sengupta, Reactor Inspector (Section 4OA5.3)

Approved by: Gregory J. Kolcum, Acting Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000335/2013004, 05000389/2013004; 07/01/2013 - 09/30/2013; St. Lucie Nuclear Plant,

Units 1 & 2; Heat Sink Performance; Follow-up of Events and Notice of Enforcement Discretion The report covered a three month period of inspection by the resident inspectors, project engineers and reactor inspectors. Two green findings were identified which included one non-cited violation. Additionally, this report documents a licensee-identified non-cited violation and a severity level IV non-cited violation without an associated finding. The significance of inspection findings were identified 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 October 28, 2011. 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 4.

Cornerstone: Initiating Events

Green: A self-revealing finding was identified for the licensees failure to establish adequate preventive maintenance (PM) activities for both units startup transformers (SUTs) 6.9kV non-segregated bus runs in accordance with site PM program requirements. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus run duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units. This issue was placed in the licensees corrective action program as action request 1809273. Corrective actions included: repair of the corroded non-segregated bus duct vent associated with this event, updating the preventative maintenance program to address periodic maintenance of non-segregated bus duct vents, and completing inspections and repairs, as necessary, of both units outdoor bus duct vents for bus runs to the SUTs and auxiliary transformers.

The performance deficiency was considered to be more than minor because it was associated with the equipment reliability attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, since 2003 when PM activities were established for SUTs (including 4.16kV non-segregated bus runs), the licensee failed to establish those same activities for both units SUT 6.9kV non-segregated bus runs. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units. The inspectors reviewed the finding in accordance with Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4,

Appendix A and Appendix G. Appendix A, The Significance Determination Process (SDP) for Findings At-Power, was used for both units because Unit 1 was operating and the failure could have reasonably occurred with Unit 2 operating prior to the fall 2012 outage. Appendix G,

Shutdown Operations Significance Determination Process, was used for the time Unit 2 was in the 2012 outage. Appendix G required a detailed risk evaluation because the finding increased the likelihood of a loss of offsite power. A Senior Reactor Analyst subsequently performed an analysis of the risk impacts to both units while at-power and while the unit was shut down. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a Loss of Offsite Power during a shutdown condition, specifically when the RCS is vented such that: 1) the steam generators cannot sustain core heat removal, and 2) a sufficient vent path exists for feed and bleed. The remaining mitigation of such an accident was comprised of the Unit 2 EDGs and recovery of power from the opposite unit. The inspectors concluded that this finding did not have a cross-cutting aspect as this was not representative of present licensee performance. (Section 4OA3.2)

Cornerstone: Mitigating Systems

Severity Level IV: An NRC-identified Severity Level IV (SL-IV) non-cited violation (NCV) of 10 CFR 50.55a(a)(3) was identified for the failure to request approval from the NRC for a proposed alternative to the code requirements in Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code applicable to the current Unit 1 in-service inspection interval. The licensee failed to request approval to use bolted patch plates for the permanent repair of degraded buried piping in several locations of the Unit 1 intake cooling water system prior to implementation. The licensee entered the issue in the corrective action program as AR 1809273 to address operability of the intake cooling water system and restore compliance with the applicable regulatory requirements.

This performance deficiency was considered for traditional enforcement because the failure to request NRC approval prior to implementation of the repair activities impacted the NRCs ability to perform its regulatory function. This performance deficiency was determined to be a SL-IV violation in accordance with the violation examples in Section 6.1 of the NRC Enforcement Policy. Cross-cutting aspects are not assigned to traditional enforcement violations. (Section 1R07)

Green: A self-revealing non-cited violation of Technical Specification (TS) 3.8.1.1.b was identified due to the licensee operating with an inoperable emergency diesel generator (EDG)for longer than the allowed outage time (AOT) of 14 days without taking the required TS actions.

Specifically, during a relay replacement, the licensee installed a diode with a lead that had an un-insulated butt splice. This un-insulated butt splice caused an electrical short circuit resulting in a blown fuse in the 2A EDG start circuitry and was the cause of the EDG failing to start on March 13, and again on June 10, 2013. Consequently, the licensee operated with an inoperable EDG for a period longer than the AOT. Immediate corrective actions included insulating the diode butt splice to prevent a repeat electrical short. The relay assembly was subsequently replaced and a new diode that did not have a butt splice was installed. The issue was entered into the licensees corrective action program as action request 1880888.

The performance deficiency was more than minor because it was associated with equipment performance attribute of the mitigating systems cornerstone and adversely affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings Table 2 dated June 19, 2012; the finding was determined to affect the Mitigating Systems Cornerstone. Manual Chapter 0609 Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2 - Mitigating Systems Screening Questions, was used to further evaluate this finding. The finding required a detailed risk evaluation by an NRC senior reactor analyst due to an actual loss of function of at least a single Train for greater than its TS AOT. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a loss of offsite power followed by a series of electrical failures leading to station blackout and ultimately a reactor coolant pump seal loss of coolant accident and core damage. The remaining mitigation of such an accident was comprised of the Unit 1 EDGs and recovery of power from the opposite unit. This finding was associated with a cross cutting aspect in the resources component of the human performance area because the licensee had not provided complete, accurate, and up-to-date procedures and work packages to ensure that the EDG wiring butt splice was insulated in accordance with plant specifications during maintenance activities in May 2008 and again in September 2012 H.2(c). (Section 4OA3.3)

Licensee-Identified Violation One violation of very low safety significance was identified by the licensee and reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and the corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at approximately 100 percent rated thermal power (RTP).

On August 7, 2013, power was reduced to 95 percent power and subsequently returned to approximately 100 percent power after performing moderator temperature coefficient testing.

On September 29, 2013, power was reduced to support a planned refueling outage. The unit was shut down on September 30, 2013, from approximately 25 percent RTP. The inspection period ended with the unit in Mode 5.

Unit 2 operated at 100 percent RTP throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

Partial Equipment Walkdowns

a. Inspection Scope

The inspectors conducted five 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. Documents reviewed are listed in the Attachment.

• 2A emergency diesel generator (EDG) while the 2B EDG was out of service (OOS)for planned maintenance

• 2B high pressure safety injection (HPSI) and low pressure safety injection (LPSI)systems while 2A emergency core cooling systems (ECCS) were OOS for preventative maintenance and surveillances

• Unit 1 control room air conditioner trains HVA/ACC-3B and -3C while HVA/ACC-3A was OOS for corrective maintenance

• Unit 1 A and B auxiliary feed water (AFW) pumps while the C AFW pump was OOS for planned maintenance

• Unit 1B HPSI while 1A HPSI OOS for planned maintenance

b. Findings

No findings were identified.

1R05 Fire Protection

Fire Area Walkdowns

a. Inspection Scope

The inspectors toured the following 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 AFW pump area

• Unit 2 2A EDG room

• Unit 2 control room

• Unit 1 control room

• Unit 1 intake cooling water (ICW) pump Area

• Unit 2 2B switch gear room

b. Findings

No findings were identified.

1R07 Heat Sink Performance

Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors interviewed plant personnel and reviewed records for a sample of heat exchangers that were directly cooled by the ICW system or the component cooling water (CCW) system (i.e. a closed loop cooling water system) to verify that heat exchanger deficiencies, potential common cause problems, or heat sink performance problems that could result in initiating events or affect multiple heat exchangers in mitigating systems were being identified, evaluated, and resolved. The inspectors selected the following heat exchangers for review based on their risk significance in the licensees probabilistic risk analysis and their safety-related mitigating system support functions.

• Unit 1 CCW heat exchanger 1A (directly cooled by the ICW system)

• Unit 2 shutdown cooling heat exchanger 2B (cooled by the CCW system)

• Unit 2 containment cooler unit 2A (cooled by the CCW system)

For the Unit 1 CCW heat exchanger 1A, the inspectors reviewed the methods and results of heat exchanger inspection/cleaning to verify performance was maintained in accordance with the system design basis. The inspectors determined whether the inspection/cleaning methods and monitoring of biotic and macro-fouling were adequate to ensure proper heat transfer. This was accomplished by determining whether the inspection/cleaning methodology, frequency, acceptance criteria, and results were adequate to confirm the heat transfer capability and detect degradation prior to loss of heat removal capabilities below design basis values. Additionally, the inspectors reviewed the results of the performance test used to establish the current inspection/cleaning frequency to verify that the test methodology, conditions, and acceptance criteria were consistent with accepted industry practices. The inspectors also verified that the performance test results were correctly applied to the evaluation of heat transfer capability under design basis conditions.

For the Unit 2 shutdown cooling heat exchanger 2B and Unit 2 containment cooler unit 2A, the inspectors determined whether the condition and operation of the heat exchanger were consistent with design assumptions as described in the Updated Final Safety Analysis Report (UFSAR). Where applicable, the inspectors reviewed records of heat exchanger eddy current testing and tube plugging to assess structural integrity and verify that the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. The inspectors reviewed operating procedures to determine whether the licensee established adequate controls and operational limits to prevent heat exchanger degradation due to excessive flow induced vibration during operation. The inspectors review also included periodic flow testing records at or near maximum design flow to verify flow through each heat exchanger was consistent with the system design basis. The inspectors also reviewed system health reports to determine whether the licensees chemical treatment programs for corrosion control were effective in preventing system degradation.

In addition to the heat exchangers, the inspectors reviewed a sample of heat sink inspection attributes as described in the paragraphs below to verify the performance of the ultimate heat sink (UHS) and its subcomponents was adequate to ensure availability and accessibility to the in-plant cooling water systems.

The inspectors reviewed inspection records and conducted a walkdown of the barrier wall (dam structure) separating Big Mud Creek and the intake canal to verify the licensee had established a program to identify degradation and loss of structural integrity. This included the review of records for structural and diver inspections to verify the licensee was monitoring the integrity and performance of the heat sink and appropriate corrective actions were implemented. During the walkdown, the inspectors determined whether vegetation present along the slopes was maintained to prevent adverse effects on the function of the UHS. In addition, the inspectors reviewed design basis information and bathymetric surveys of Big Mud Creek, i.e. the UHS, to determine whether sufficient reservoir capacity was available to perform its design basis function.

The heat sink inspection sample included the review of in-service testing records for the ICW system valves listed below to verify that the performance of the UHS and its subcomponents was appropriately evaluated through testing or equivalent methods.

The inspectors also observed portions of the quarterly in-service test performed for the UHS barrier valves listed below (SB-37-1 and SB-37-2). The selected valves included interface valves required to isolate non-essential flow paths during design basis events, in order to determine if these valves were periodically tested, inspected, or monitored. In addition, the inspectors reviewed records of system flow balance tests to compare the test configuration with the flow assumptions during design basis accident conditions.

• SB-37-1 and SB-37-2 (Unit 1/2 air operated UHS barrier valves)

• TCV-14-4A and TCV 14-4B (Unit 1 temperature control valves)

• MV 21-2 and MV 21-3 (Unit 1 turbine cooling water/steam generator open blowdown cooling system isolation valves)

• HCV-14-8 A/B (Unit 2 hand control valves for CCW heat exchanger 1B outlet A/B loop crossover to supply header)

For a sample of buried and inaccessible piping, the inspectors reviewed the licensee's pipe testing, inspection, or monitoring program to determine whether structural integrity was ensured and that any leakage or degradation was appropriately identified and dispositioned. Specifically, the inspectors reviewed inspection records and corrective action documents for buried sections of the ICW system discharge piping. The inspectors also reviewed historical data of thru-wall pipe leakage in the ICW system to identify any adverse trends and verify that adequate corrective actions were implemented.

The heat sink inspection sample also included a system walkdown of the Unit 1 and 2 ICW system intake structures and Unit 2 CCW heat exchanger room to assess the material condition and functionality of accessible structures and components such as strainers, pumps, instrumentation, and component supports. In addition, the inspectors interviewed plant staff and reviewed inspection records for visual inspections of the intake structure to determine whether pump bay silt accumulation was monitored, trended, and maintained at an acceptable level. During the walkdown, the inspectors interviewed plant staff to assess the operation of the ICW system and UHS, including monitoring, trending, and control of macro-fouling to prevent clogging.

Additionally, the inspectors reviewed corrective action documents related to the ICW system and heat sink performance issues to determine whether the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions. The documents reviewed are listed the Attachment.

b. Findings

Introduction:

The inspectors identified a Severity Level IV (SL-IV) non-cited violation (NCV) of 10 CFR 50.55a(a)(3) for the failure to request approval from the NRC for a proposed alternative to the applicable code requirements in Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME B&PVC) for the current Unit 1 in-service inspection interval. Specifically the licensee failed to request approval to use bolted patch plates for the permanent repair of degraded buried piping in several locations of the Unit 1 ICW system prior to implementation.

Description:

During Unit 1 refueling outage SL1-24 (November 2011 - March 2012), the licensee performed visual inspections of the ICW piping internal surfaces to meet regulatory commitments in response to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The scope of visual inspections included buried piping in both trains of the ICW system discharge. The licensee identified wall thinning degradation in several locations of the A and B trains downstream of the CCW heat exchangers. The degradation involved 23 localized corroded areas in the Unit 1 ICW system discharge piping (17 in the A train and 6 in the B train) which required repair. The degradation mechanism was determined to be localized corrosion resulting from the failure of the piping internal liner in the affected areas. The affected piping was 30-inches in diameter and 3/8-inch in nominal wall thickness with a cement liner in the interior surface to protect from corrosion. The degraded piping sections were originally designed in accordance with the provisions in ASME B31.7 Code, Nuclear Power Piping, for Class 3 nuclear piping and classified as ASME Class 3 in the In-Service Inspection Program.

The repair method used by the licensee for all the defective areas consisted mainly of cleaning the degraded area, measuring the pipe wall thickness around the degraded area using non-destructive examination, filling the degraded area with epoxy material to the profile of the pipe internal diameter, covering the area with a carbon steel patch plate bolted to the internal surface of the pipe with a rubber gasket between the patch plate and the piping internal surface, and then covering the entire repaired area with epoxy coating. The licensee implemented the repairs through the design control process, and evaluated the patch plate design and resulting pipe stresses in accordance with the design criteria in ASME Section III, 1971 Edition through the Summer 1973 Addenda.

The inspectors also identified that a similar repair had been performed at another location of the Unit 1 ICW system discharge piping during the October 2008 refueling outage. The total number of repairs performed using the bolted patch plate method was as follows:

Engineering EC Unit ICW Discharge Train No. of Patch Change (EC) Date Plates Installed EC 235964 2008 1 I-30-CW-30 (Train A) 1 EC 275645 2012 1 I-30-CW-30 (Train A) 16 EC 274859 2012 1 I-30-CW-30 (Train A) 1 EC 275443 2012 1 I-30-CW-29 (Train B) 6 The regulatory requirements in 10 CFR 50.55a(g)(4) require the licensee to implement in-service inspection activities, including repair/replacement, in accordance with the provisions of ASME Section XI. The edition of ASME Section XI applicable to the current fourth in-service inspection interval of Unit 1 was the 2001 Edition through the 2003 Addenda. Article IWA-4000 of ASME Section XI contains the requirements for repair/replacement activities of ASME Class components. Paragraph IWA-4421, General Requirements, states that defects shall be removed or mitigated via mechanical processing, thermal methods, welding or brazing, or modification in accordance with IWA-4340. However, 10 CFR 50.55a(b)(2)(xxv) prohibits the use of IWA-4340 for mitigation of defects by modification if using the 2001 or later editions of ASME Section XI. The provisions in 10 CFR 50.55a(a)(3) also allow the licensee to submit proposed alternatives for the ASME Section XI requirements to the NRC for review and approval prior to implementation.

The inspectors determined that the method used by the licensee to repair defects in ASME Class 3 piping in the ICW system did not meet the established requirements in ASME Section XI, as modified by 10 CFR 50.55a. Specifically, the installation of bolted patch plates over the degraded areas did not meet the requirements in Article IWA-4000 because the defects were not removed or mitigated through any of the allowed methods in IWA-4421. That is, the installation of bolted patch plates left the defects in place and did not involve removal or mitigation via mechanical processing, thermal methods, welding or brazing. Therefore, the repair method used by the licensee constituted an alternative to the ASME Section XI requirements which required NRC approval prior to implementation.

The licensee entered this issue into the corrective action program (CAP) as action request (AR) 01888735 to evaluate system operability and restore compliance with the applicable regulatory requirements. The licensees prompt operability determination for this issue determined that the affected system should be considered operable but non-conforming. On August 5, 2013, the licensee submitted a relief request to the NRC (ML13220A029) requesting approval to use bolted patch plates as a method to permanently repair defects on portions of the ICW system discharge piping downstream of the CCW heat exchangers during the current fourth ten-year in-service inspection interval (February 11, 2008 - February 10, 2018).

Analysis:

The inspectors determined that the failure to request approval from the NRC to implement an alternative approach for the requirements in ASME Section XI was a performance deficiency. This performance deficiency was screened through the traditional enforcement processes because the failure to request NRC approval prior to the implementation of the repair method impacted the regulatory process in that the NRC was not able to perform its regulatory function in determining if the selected repair method provided an acceptable level of quality and safety.

The inspectors used the guidance in Part II, Section 2.1.3, of the NRC Enforcement Manual, dated September 9, 2013, for issues involving the request of NRC review and approval prior to implementation (e.g. violations of 10 CFR 50.59) to assess the significance of the performance deficiency. This performance deficiency was determined to be a SL-IV violation in accordance with the violation examples in Section 6.1 of the NRC Enforcement Policy, dated July 9, 2013, because it was consistent with the criteria set forth in example 6.1.d.2 for a violation of 10 CFR 50.59 resulting in a condition evaluated as having very low safety significance (i.e., Green) by the significant determination process. Cross-cutting aspects are not assigned to traditional enforcement violations.

Enforcement:

10 CFR 50.55a(a)(3) states, in part, that proposed alternatives to the requirements of paragraph

(g) of this section, or portions thereof, may be used when authorized by the Director, Office of Nuclear Reactor Regulation. Any proposed alternatives must be submitted and authorized prior to implementation. The applicant or licensee shall demonstrate that:

(i) the proposed alternatives would provide an acceptable level of quality and safety; or

(ii) compliance with the specified requirements of this section would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

10 CFR 50.55a(g)(4), In-service inspection requirements, states, in part, that throughout the service life of a pressurized water-cooled nuclear power facility, components (including supports) which are classified as ASME Code Class 3 must meet the requirements, except design and access provisions and preservice examination requirements, set forth in Section XI of editions and addenda of the ASME B&PVC that become effective subsequent to editions specified in paragraphs (g)(2) and (g)(3) of this section and that are incorporated by reference in paragraph

(b) of this section, to the extent practical within the limitations of design, geometry and materials of construction of the components.

The 2001 Edition through the 2003 Addenda of ASME Section XI, Article IWA-4000, paragraph IWA-4421, General Requirements, states that defects shall be removed or mitigated via mechanical processing, thermal methods, welding or brazing, or modification in accordance with IWA-4340. However, 10 CFR 50.55a(b)(2)(xxv) states that the use of the provisions in IWA-4340, "Mitigation of Defects by Modification,"

Section XI, 2001 Edition through the latest edition and addenda incorporated by reference in paragraph 10 CFR 50.55a(b)(2) are prohibited.

Contrary to the above, during the Unit 1 refueling outages in October 2008 and November 2011, the licensee failed to submit to the NRC a proposed alternative to the requirements in 10 CFR50.55a(g)(4) prior to implementation. Specifically, the method used by the licensee to repair defects in several locations of the Unit 1 ICW system discharge piping, designated as ASME Class 3, did not meet the applicable repair/replacement requirements in ASME Section XI in that the identified defects were left in place and not removed or mitigated via the methods established in paragraph IWA-4421, as modified by 10 CFR 50.55a. Therefore, the repair method constituted an alternative to the existing ASME Section XI requirements in 10 CFR 50.55a(g)(4), which required NRC approval prior to implementation pursuant to 10 CFR 50.55a(a)(3).

Because this violation was determined to be SL-IV and the licensee entered the issue in the CAP as AR 01888735, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy, dated July 9, 2013. This finding will be tracked as NCV 05000335/2013004-01, Failure to Request NRC Approval prior to implementation of an Alternative Repair Method for ASME Class 3 Piping in the Intake Cooling Water System.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On August 20, 2013, the inspectors observed and assessed licensed operator actions during their annual training requalification exam in the control room simulator. The simulated scenario involved a loss of offsite power and a small break loss of coolant accident. 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. In particular, on July 26, the inspectors observed Unit 2 control room Operations and Maintenance activities during the removal and replacement of the qualified safety parameter display system monitor that was located directly above the reactor coolant pump control switches. On September 29 and 30, the inspectors observed portions of Unit 1 control room Operations activities in shutting down the unit from approximately 70 percent power to Mode 5 (<200oF). These activities complete two inspection samples.

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.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the performance data and associated ARs 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 10 CFR 50.65, The Maintenance Rule (MR). The inspectors efforts focused on MR 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.

• AR 1891033, Unit 1 and 2 Start-up Transformers Non-segregated bus systems moved to MR a(1)

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 five 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 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. Documents reviewed are listed in the Attachment.

• Unit 2 2A EDG, 2A charging pump, and 2C charging pump OOS for planned maintenance

• Unit 2 control room air conditioner train HVA/ACC-3B, B Channel Qualified Safety Parameter Display System and Pressurizer B-4 Back-up Heaters OOS

• Unit 2 HPSI injection valves HCV-3615, HCV-3617,and 2A ECCS train OOS for planned maintenance

• Unit 2 2B Charging Pump, 2B ECCS, and 2B 120 VAC Instrument Inverter OOS

• Unit 1 1A HPSI, Steam bypass control valve PCV-8802 and 1A EDG OOS

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following 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 sections of the UFSAR, and associated supporting documents and procedures, and interviewed plant personnel to assess the adequacy of the interim disposition.

• AR 1888735, Unit 1 and Unit 2 Prompt Operability Determination of Intake Cooling Water Code Patch Plate Repairs

• AR 1890707, Unit 2 Safety Injection Tank 2B1 approaching TS Boron Concentration Limit

• AR 1894423, Unit 1 AFW pump 1A Discharge Pipe Corrosion

• AR 1895515, 2B Instrument Inverter Manual Bypass Switch High Temperature

• AR 1900484, 1C AFW Trip/Throttle solenoid ground

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the engineering change (EC) documentation for the two temporary modifications listed below. The inverter temporary modification was in response to an irregular high temperature profile obtained during preventive maintenance thermography of the 2B Instrument Inverter manual bypass switch. The Unit 1 nuclear instrument system (NIS) temporary modification provided an alternate NI signal to the B train reactor protection system. The licensee determined that the NI detector normally providing this signal had degraded. The inspectors reviewed the 10 CFR 50.59 screenings and evaluation, fire protection reviews, and environmental reviews, to verify that the modifications had not affected system operability and availability. The inspectors reviewed associated plant drawings and UFSAR documents impacted by these modifications and discussed the changes with licensee personnel to verify the installations were consistent with the modification documents. The inspectors observed the installation of the inverter bypass switch modification and inspected the installed NI modification. Additionally, the inspectors verified that any issues associated with the modifications were identified and entered into the licensees CAP. Documents reviewed are listed in the Attachment.

• EC 279780, Unit 2, 2B Instrument Inverter Bypass Switch

• EC 279977, Unit 1, Alternate NIS Excore Detector Arraignment (NI-10 instead of NI-06)

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the four maintenance work orders (WOs) listed below, 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.

• WO 40256912, Unit 2 HVA/ACC-3A Gravity Damper Repair

• WOs 40177137, 40178121 and 40210949, Unit 2 PMs HPSI loop injection valve HCV-3615

• WO 40262821, Replace Automatic Control Module for Unit 2 Control Element Assembly 75

• WO 40264826, Unit 1 B Channel Reactor Protection System NI ASI Deviation

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Unit 1 Refueling Outage SL1-25

a. Inspection Scope

Outage Planning, Control and Risk Assessment The Unit 1 planned refueling outage started on September 30, 2013. The inspectors reviewed the licensees outage risk control plan and verified that the licensee had appropriately considered risk, industry experience and previous site specific problems.

The inspectors also reviewed the outage work schedule for Operations, Maintenance, and the Fire Brigade to confirm the licensee has scheduled covered workers such that the minimum days off for individuals working on outage activities was in compliance with 10 CFR 26.205(d)(4) and (5).

Monitoring of Shutdown Activities The inspectors observed portions of the Unit 1 reactor plant cooldown beginning on September 30, 2013. The inspectors reviewed operating logs and plant parameters to verify reactor plant shutdown activities were conducted in accordance with TSs and applicable operating procedures, including 1-GOP-123, Turbine Shutdown - Full Load to Zero Load; 1-GOP-305, Reactor Plant Cooldown - Hot Standby To Cold Shutdown; and 1-NOP-03.05, Shutdown Cooling. The inspectors performed walk downs of important systems and components used for decay heat removal from the reactor core including the ICW system and CCW system.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors either reviewed or witnessed the following six surveillance tests to verify that the tests met technical specifications (TSs), 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 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 Attachment.

In-Service Tests:

• 2-OSP-21.01A, 2A Intake Cooling Water Pump Code Run Surveillance Tests:

• 1-OSP-09.01C, 1C Auxiliary Feedwater Pump Code Run (Monthly Operations Check Only)

• 1-OSP-59.01A, 1A Emergency Diesel Generator Monthly Surveillance (fast start)

• 1-OSP-01.05, At Power Determination of Moderator Temperature Coefficient and Power Coefficient

• 1-SMI-63.11A, Reactor Protection System -Local Power Density Channel Calibration Channel A

• 1-SMI-01.21, RCS Low Temperature Overpressure Protection (LTOP) Functional Test

b. Findings

No findings were identified.

1EP6 Drill Evaluation Emergency Preparedness Drills

a. Inspection Scope

On July 17, 2013, 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 reactor coolant leak requiring a safety injection, an emergency diesel generator failure to start, and a subsequent total loss of the ECCS. Plant conditions degraded to a point where the licensee declared a general area 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 Alert, Site Area Emergency and General Emergency classifications and notifications 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 the licensee identified critique items and drill weaknesses were captured in the CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Mitigating Systems

a. Inspection Scope

The inspectors checked licensee submittals for the performance indicators (PIs) listed below for the period July 1, 2012, through June 30, 2013, to verify the accuracy of the PI data reported during that period. Performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures ADM-25.02, NRC Performance Indicators, and 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.

• Unit 1 Safety System Functional Failures

• Unit 2 Safety System Functional Failures

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 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 Annual Sample Review - Operator Actions in Response to a Unit 2 Containment

Annulus Smoke Detector Alarm

a. Inspection Scope

The inspectors performed an in-depth review of ARs 1880805 and 1881996 to evaluate the operators response to a unit 2 containment annulus smoke detector alarm. On June 10, 2013, containment annulus smoke detector 11B went into an alarm condition. An operator was dispatched to the local alarm panel located outside the annulus and determined that smoke detector 11B, one of four detectors in the annulus, was in alarm.

Site security and radiation protection were contacted to support entering the closed annulus to inspect the area for a fire. 30 minutes after receiving the alarm, the annulus was entered and the alarm was confirmed to be spurious. Emergency plan emergency action level (EAL) HU2 would be entered for a fire not extinguished within 15 minutes of control room fire alarm. EAL HU2 was not entered for the event. The event was documented in the CAP as AR 1880805. On June 13, 2013, AR 1881996 was written to request additional procedural and EAL guidance to ensure future consistency in implementing EAL actions with a single detector alarming. AR 1881996 documented, in part, that strict compliance of the HU2 basis and several recent operating experience items would support classifying a Notice of Unusual Event (NOUE) in this circumstance.

Recommended actions include revising the St. Lucie Emergency Plan. The inspectors reviewed both ARs to determine whether St. Lucie Emergency Plan EAL entry conditions were met when smoke detector 11B went into alarm and to determine whether the proposed actions to revise the St. Lucie Emergency Plan were appropriate.

b. Findings and Observations

The inspectors interviewed the shift manager who was on duty at the time of the event.

The shift manager stated that the decision not to declare an NOUE was based on his conclusion that the single annulus smoke detector alarm was spurious and not an indication of a fire. There were no other annulus detectors in an alarm condition and no evidence of an electrical penetration fire, i.e. no changes of state of electrical equipment due to hot shorts in any penetrations. As a result of inspector questioning, the licensee initiated AR 1887960 to review the decision related to not entering the emergency plan after receiving an annulus smoke detector alarm that could not be proved to be spurious by dispatching personnel to the fire scene within 15 minutes. After further review, the licensee concluded that the shift manager made the correct decision in calling this a spurious alarm and not entering the EAL. The conclusion was based in part on the overlapping coverage of the smoke detectors in the annulus and not receiving a second alarm. This information was reviewed by an NRC Region II senior emergency preparedness (EP) inspector and the NRC headquarters EP staff. They concluded that the licensee met the entry conditions for EAL HU2 and should have declared a NOUE when they were unable to enter the annulus within 15 minutes to determine that the alarm was spurious.

The licensee initiated AR 1899134 to document NRCs interpretation of EAL HU2 entry criteria and the licensees failure to enter the emergency plan. Proposed corrective actions include providing training to operations on EAL HU2, correcting the second quarter 2013 NRC emergency preparedness performance indicator (Drill/Exercise Performance) and placing on hold any related EAL changes.

The inspectors concluded that the failure to declare an NOUE within 15 minutes of receiving the annulus fire alarm was a performance deficiency. Specifically, licensee procedure EPIP-01 F01, St. Lucie Plant Classification Tool, Hot Conditions, HU2 Unusual Event, EAL 1, requires in part, a NOUE classification if a Fire is not extinguished within 15 minutes of Control Room Fire alarm for the reactor containment building and shield building. The HU2 basis states that An alarm is assumed to be an indication of a FIRE unless it is disproved within the 15 minute period by personnel dispatched to the scene. The licensee was unable to disprove the alarm within 15 minutes due to security and radiation protection controls necessary to enter the annulus.

The inspectors screened the performance deficiency in accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined that the performance deficiency was minor. The minor determination was based on there being no impact of not declaring an unusual event since there was no actual fire. In addition, the correction to the NRC performance indicator would not cause the performance indicator to exceed a threshold. The inspectors also concluded that the performance deficiency was not a precursor to a significant event, would not have led to a more significant safety concern, and did not adversely affect a cornerstone objective.

The inspectors determined that the performance deficiency resulted in a minor violation of 10 CFR 50.54(q). 10 CFR 50.54(q) requires, in part, a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards of 10 CFR 50.47(b). Title 10 CFR 50.47(b)(4) requires, in part, a standard emergency classification and action level scheme be used by the licensee. Contrary to the above, on June 10, 2013, a NOUE was not classified within 15 minutes of receiving a fire alarm within the shield building (annulus). This issue was entered into the licensees CAP as AR 1899134. This failure to comply with 10 CFR 50.54(q) constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

.3 Annual Sample Review - Operator Workarounds

a. Inspection Scope

The inspectors reviewed the licensees implementation of the process used to identify, document, track, and resolve operator workarounds (OWAs) as described in procedure OP-AA-108, Oversight and Control of Operator Burdens, to verify the licensee was identifying workarounds at an appropriate threshold and entering them into the corrective action program. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified OWAs. The inspectors performed an evaluation of the potential cumulative effect of all outstanding operator workarounds on Unit 1 and Unit 2. Documents reviewed are listed in the Attachment.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR 1869287, Operator Burdens Program ACE Review

• AR 1892816, PSL Operator Burden Policy Differs From Fleet Guidance

b. Findings and Observations

No findings were identified.

4OA3 Follow-up of Events and Notice of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000389/2013002-00 Failure to Invoke

Technical Specification Action Statement for Failed Containment Isolation Valve On June 3, 2013, with Unit 2 at approximately 8 percent RTP, a containment isolation valve (CIV) associated with the 2A hydrogen analyzer failed to close during a functional test. Initially the valve was not identified as a CIV and consequently the action statement of Technical Specification 3.6.3 to de-energize the penetrations other valve within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> was not satisfied. The inspectors reviewed the LER to verify the accuracy and completeness of the LER and the appropriateness of the licensees corrective actions. Enforcement aspects associated with this LER are discussed in Section 4OA7 of this report.

.2 (Closed) LER 05000389/2012002-00 Non-Segregated Phase Bus Fault Resulting in a

Partial Loss of Offsite Power

a. Inspection Scope

On October 3, 2012, with Unit 2 in a defueled condition and Unit 1 at 100 percent RTP, the collapse of a corroded non-segregated duct vent screen resulted in a fault on the 6.9kV non-segregated bus run for the 2B SUT. Protective relays initiated a 1B and 2B SUT lockout resulting in a partial loss of offsite power to both units. The inspectors reviewed the LER to verify the accuracy and completeness of the LER and the appropriateness of the licensees corrective actions.

b. Findings

Introduction:

A self-revealing Green finding was identified for the licensees failure to establish adequate PM activities for both units SUTs 6.9kV non-segregated bus runs in accordance with site PM program requirements. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus run duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units.

Description:

On October 3, 2012, with Unit 2 in a defueled condition and Unit 1 at 100 percent RTP, a corroded non-segregated duct vent screen that had collapsed onto the internal bus bars resulted in a fault on the 6.9kV non-segregated bus run (bus duct #7)for the 2B SUT. Protective relays initiated a 2B SUT lockout resulting in a partial loss of offsite power to Unit 2. Due to a common high voltage side connection, the protective action also resulted in a 1B SUT lock out and a partial loss of offsite power to Unit 1.

Each unit has two SUTs that connect two physically independent feeds from the offsite transmission network to the onsite Class 1E distribution system. The fault was isolated from Unit 1 and the 1B SUT was returned to service. There were no other impacts to Unit 1. Repairs were made to the non-segregated bus duct and the 2B SUT was returned to service.

In 2005, a work request (WR) was initiated to repair rust damage on top of 2B SUT 6.9kV non-segregated bus duct #7. The work activity was not scheduled. In 2010, WOs were initiated to recoat bus duct #7 during the spring 2011 refueling outage to repair and prevent additional degradation of the bus. This work was rescheduled to the 2012 refueling outage when work associated with the 2B SUT was removed from the 2011 outage. In September 2012, a scope change request was initiated to remove the work from the 2012 outage. On October 3, 2012, the collapse of a corroded bus duct #7 vent screen caused lockouts of both units B train SUTs.

The licensees root cause evaluation determined that the root cause was that the risk associated with identified external corrosion on the 6.9kV non-segregated bus duct #7 vent assembly was not understood by station organizations responsible for scheduling and implementing maintenance resulting in the failure to detect and correct the degraded vent condition.

Contributing causes include: 1) the risk significance of the SUTs 6.9kV bus duct runs were not reflected in PM plans; and 2) preventative maintenance of bus ducts (both 6.9kV and 4.16kV) was not performed in a manner that is consistent with the equipment design and safety significance.

Each SUT train is bounded by breakers in the 230kV switchyard and the breakers on the 6.9kV and 4.16kV switchgear and includes both 4.16 and 6.9kV non-segregated bus runs. In 2003, the licensee established the PM basis and implemented PMs for the SUT trains. The 6.9kV bus runs were not included in the PM program since the bus runs were not considered part of the offsite power lineup to engineered safeguards equipment. The SUT trains were determined to be Critical 2 components in accordance with licensee procedure ER-AA-204, Preventative Maintenance Program Strategy.

Licensee procedure MA-AA-204, Preventative Maintenance and Surveillance Process, section 4.7.B specifies that Critical 2 components shall have a documented, retrievable basis that includes justification for PM scope and frequency. The licensee determined that SUT 6.9kv non-segregated bus runs should have been classified the same as the rest of the SUT train and appropriate PMs established since the bus run is integral to SUT operation.

PM on the 2B SUT 4.16kV bus run was completed in February 2011. Since the associated 6.9kV bus run was not covered under the PM program, no PMs were completed on the bus. This may have been a missed opportunity to identify the scope of degradation of bus duct #7 and to implement repairs.

This issue was placed in the licensees corrective action program as AR 1809273.

Corrective actions included: repair of the corroded non-segregated bus duct vent associated with this event, updating the preventative maintenance program to address periodic maintenance of non-segregated bus duct vents, and completing inspections and repairs, as necessary, of both units outdoor bus duct vents for bus runs to the SUTs and auxiliary transformers.

Analysis:

The failure to establish adequate PM activities for both units SUTs 6.9kV non-segregated bus runs in accordance with site PM program requirements was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the equipment reliability attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, since 2003 when PM activities were established for SUTs (including 4.16kV non-segregated bus runs), the licensee failed to establish those same activities for both units SUT 6.9kV non-segregated bus runs. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units. The inspectors reviewed the finding in accordance with Inspection Manual Chapter 0609, Significance Determination Process (June 2, 2011), Attachment 4 (June 19, 2012), Appendix A (June 19, 2012), and Appendix G (February 28, 2005). Appendix A, The Significance Determination Process (SDP) for Findings At-Power, was used for both units because Unit 1 was operating and the failure could have reasonably occurred with Unit 2 operating prior to the fall 2012 outage. Appendix G, Shutdown Operations Significance Determination Process, was used for the time Unit 2 was in the 2012 outage. Appendix G required a detailed risk evaluation because the finding increased the likelihood of a loss of offsite power. A Senior Reactor Analyst subsequently performed an analysis of the risk impacts to both units while at-power and while the unit was shut down. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a Loss of Offsite Power during a shutdown condition, specifically when the RCS is vented such that: 1) the steam generators cannot sustain core heat removal; and 2) a sufficient vent path exists for feed and bleed. The remaining mitigation of such an accident was comprised of the Unit 2 EDGs and recovery of power from the opposite unit. The inspectors concluded that this finding did not have a cross-cutting aspect as this was not representative of present licensee performance.

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. The licensee entered this issue into the corrective action program as AR 1809273. Because this finding does not involve a violation and is of very low safety significance, it is identified as a Finding: (FIN 05000335,389/2013004-02, Partial Loss of Offsite Power due to Non-segregated Bus Failure)

.3 (Closed) LER 05000389/2013003-00, 2A Emergency Diesel Generator Failed to Start

a. Inspection Scope

On March 13 and on June 10, 2013, the 2A EDG failed to start during planned testing.

After the second failure, the licensee identified an un-insulated butt splice in the EDGs start circuitry had caused an electrical short which prevented the EDG from starting.

Consequently, the licensee operated with an inoperable EDG for longer than the technical specification (TS) allowed outage time (AOT). The inspectors checked the accuracy and completeness of the LER and the appropriateness of the licensees corrective actions.

b. Findings and Observations

Introduction:

The inspectors identified a Green, self-revealing, non-cited violation of TS 3.8.1.1.b for the operation of Unit 2 in Mode 1 with the 2A EDG inoperable for longer than the TS AOT of 14 days. The TS violation occurred as a result of the licensees failure to insulate an EDG diode circuit butt splice in accordance with the licensees wiring specification and resulted in the diesels inoperability.

Description:

On May 15, 2008, relay contactor FFP/957 was replaced in the 2A EDG start circuitry with a newer model relay due to part obsolescence. The obsolete relay had a coil mounting plate that was electrically isolated from the contactor circuitry by plastic non-conductive material. The new relay assembly coil mounting plate was not electrically isolated from the contactor circuitry which caused the coil mounting plate to be at a voltage potential of 125 volts direct current. During installation of the new relay, an existing diode was removed from the old relay assembly and was reinstalled onto the new relay assembly. This diode had a lead with an un-insulated butt splice. Licensee wiring specification FPL 2998-B271, Unit 2 Raychem Illustrations Conductor-To-Conductor Butt Splice, required the diode wiring butt splice to be insulated. Contrary to this specification, one of the diode lead wires contained a butt splice that was installed without insulation. Due to the design difference described above, the un-insulated butt splice would not have been a concern on the obsolete relay since that design had a coil mounting plate that was electrically isolated from the rest of the circuit. However, on the new relay design the un-insulated splice could cause a short on the circuit if it made contact with the coil mounting plate. The 2A EDG had approximately 50 successful starts following the 2008 relay replacement.

On September 07, 2012, relay contactor FFP/957 was replaced due to increasing relay coil resistance. The diode was again disconnected from the existing relay and reinstalled onto the new relay without insulating the diode wiring butt splice. This was the licensees second opportunity following the 2008 installation to properly insulate the diode butt splice. The EDG had 13 successful starts following the 2012 maintenance.

On March 13, 2013, during a 2A EDG test, the engine failed to start. The licensee identified a blown fuse FU-4N in the EDG start circuitry. Based on the intermittent control room alarms that were received prior to the failure, the licensees trouble shooting and circuit analysis, the fact that the fuse had been in service for many years, and the use of Operating Experience the licensee concluded that the problem was caused by a failed fuse. The licensee determined that the intermittent alarms received in the control room immediately prior to the EDG failure were caused by degraded fuse performance. The licensee replaced the blown fuse, started the EDG successfully and returned the engine to service. The EDG had three successful starts following the fuse replacement.

On June 10, 2013, the 2A EDG again failed to start during a test. The EDG was declared inoperable and TS 3.8.1.1.b was entered. The licensee found the same fuse FU-4N had blown. During troubleshooting, the licensee identified the un-insulated diode butt splice on relay contactor FFP/957. Burnt markings were found on the metal plate near the un-insulated diode butt splice. The licensee concluded that the fuse had blown due to an electrical short between the un-insulated diode butt splice to the metal coil mounting plate. Corrective actions included insulating the diode butt splice in accordance with wiring specification FPL 2998-B271. The licensee returned the EDG to service within the required TS 3.8.1 AOT.

The inspectors reviewed the work packages for the 2008 and 2012 relay changes and learned that the work instructions did not provide guidance for either the re-use of the diode or inspection of the diode wiring. The inspectors interviewed the maintenance technician that replaced the relay assembly in September 2012 and the engineering personnel associated with the apparent cause evaluation on this failure. The inspectors concluded that the susceptibility to a short circuit condition was introduced into the 2A EDG control circuit in May 2008 when the relay was changed to the new design.

However, because there were approximately 50 subsequent successful 2A EDG starts through September 2012, the inspectors concluded that until the 2012 relay replacement there had been sufficient clearance between the un-insulated butt splice and the relay plate which prevented a short circuit condition and subsequent failure of the FU-4N fuse.

The inspectors further concluded that the September 2012 relay replacement placed the non-conforming wiring splice in close enough proximity to the metal relay mounting plate such that a susceptibility to a short circuit condition was introduced into the EDG starting circuit. This short circuit condition significantly challenged the reliability of the 2A EDG start circuit and the failure mechanism ultimately manifested itself on March 13, 2013, and again on June 10, 2013, when the diesel failed to start during tests.

Analysis:

The licensees failure to insulate the butt splice on the EDG diode lead wire in accordance with FPL Specification 2998-B271 was a performance deficiency that resulted in the EDGs inoperability. The performance deficiency was more than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Table 2 of Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings (June 19, 2012),the inspectors concluded the finding affected the mitigating systems cornerstone. The inspectors used Exhibit 2 of Manual Chapter 0609 Appendix A, Significance Determination Process for Findings At-Power, (June 19, 2012) to further evaluate this finding. The inspectors determined that the finding required a detailed risk evaluation by an NRC senior reactor analyst due to an actual loss of function of at least a single train for greater than its TS AOT. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a loss of offsite power followed by a series of electrical failures leading to station blackout and ultimately a reactor coolant pump seal loss of coolant accident and core damage. The remaining mitigation of such an accident was comprised of the Unit 1 EDGs and recovery of power from the opposite unit. This finding was associated with a cross cutting aspect in the resources component of the human performance area because the licensee had not provided complete, accurate, and up-to-date procedures and work packages to ensure that the EDG wiring butt splice was insulated in accordance with plant specifications during maintenance activities in May 2008 and again in September 2012 H.2(c).

Enforcement:

St. Lucie Unit 2 TS limiting condition for operation 3.8.1.1.b requires that while the plant is in Mode 1, two separate and independent diesel generators be operable. TS 3.8.1.1 Action b, states, in part, that with one diesel generator inoperable, restore the diesel generator to operable status within 14 days or be in at least hot standby within the next six hours and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

Contrary to the above, from at least March 13, 2013, to June 10, 2013, the licensee operated with the 2A EDG inoperable due to an un-insulated butt splice on the EDG start circuitry for a period of time that was greater than the 14 days allowed by the TS and did not take the required action as described in the TS 3.8.1.1 Action b. Immediate corrective actions included insulating the diode butt splice to prevent a repeat electrical short. The relay assembly was subsequently replaced and a new diode that did not have a butt splice was installed. Since this violation was of very low safety significance (Green) and was entered into the licensees corrective action program as AR 1880888, the violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: (NCV 05000389/2013004-03, Emergency Diesel Generator Inoperable For A Period Greater Than The Allowed Outage Time)

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 Completion of Inspection Activity associated with Inspection Procedure (IP) 71004,

Power Uprate All inspection samples have been completed for the extended power uprates (EPUs) on Units 1 and 2 as required by IP 71004, Power Uprate. A table in the Attachment to this report summarizes the samples that were inspected during the EPU project for each unit. The table is organized by the inspection procedure used to conduct the inspection activities and identifies the inspection reports where the samples are documented as well as the applicable units.

.3 Closed - Temporary Instruction (TI) -2515/182 - Review of the Implementation of the

Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase 2

a. Inspection Scope

Leakage from buried and underground pipes has resulted in ground water contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, Nuclear Energy Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122), with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued TI-2515/182 Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

From September 16-18, 2013, the inspectors conducted a review of records and procedures related to the licensees program for buried pipe, underground pipe and tanks in accordance with Phase II of TI-2515/182. This review was done to confirm that the licensees program contained attributes consistent with Sections 3.3.A and 3.3.B of NEI 09-14 and to confirm that these attributes were scheduled and/or completed by the NEI 09-14 Revision 3 deadlines. To determine if the program attribute was accomplished in a manner which reflected good or poor practices in program management, the inspectors interviewed licensee staff responsible for the buried pipe program and reviewed buried pipe program related activities.

The licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraph 03.02.a of the TI and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase I inspections were conducted and are complete. Additionally, the licensees Buried Piping and Underground Piping and Tanks Program was inspected in accordance with Paragraph 03.02.b of the TI and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf, were submitted to the NRC Headquarters staff. Based upon the scope of the review, Phase II of TI-2515/182 was completed and this TI is closed.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

The resident inspectors presented the inspection results to Mr. Jensen and other members of licensee management on October 11, 2013. 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

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for disposition as a noncited violation.

During plant operation in Modes 1 through 4, Unit 2 TS 3.6.3 limiting condition of operation (LCO) for containment isolation valves (CIVs) requires that CIVs shall be operable. The technical specification 3.6.3 action statement specifies with one or more containment isolation valve(s) inoperable, maintain at least one isolation valve operable in each affected penetration that is open and either: 1) Restore the inoperable valve to operable status within four hours; 2) isolate each affected penetration within four hours by use of at least one deactivated automatic valve secured in the isolation position; 3) isolate each affected penetration within four hours by use of at least closed manual valve or blind flange; or 4) be in hot standby within the next six hours and cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

Contrary to the above, on June 2, 2013, when a CIV associated with the 2A hydrogen analyzer became inoperable, the TS required actions above were not met until the CIV was de-energized approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> later. The TS was violated when the unit was not placed in hot standby within ten hours of finding the CIV inoperable.

The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, (June 19, 2012). The inspectors used Exhibit 3 - Barrier Integrity Screening Questions, for the reactor containment. The finding screened as very low safety significance (Green) because there was no actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components; and there was no impact on the hydrogen control function in containment. This finding has been entered into the licensees corrective action program as AR 1878888. Additional information regarding this finding can be found in Section 4OA3.1 of this report.

ATTACHMENT: SUPPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee personnel:

N. Bach, Chemistry Manager M. Baughman, Training Manager E. Belizar, Projects Manager C. Bible, Engineering Director D. Calabrese, Emergency Preparedness Manager B. Castiglia, Performance Improvement Manager B. Coffey, Plant General Manager D. DeBoer, Operations Director R. Filipek, Engineering Design Manager J. Jensen, Site Vice President E. Katzman, Licensing Manager C. Martin, Health Physics Manager R. McDaniel, Fire Protection Supervisor J. Piazza, Maintenance Director P. Rasmus, Assistant Operations Manager M. Snyder, Nuclear Quality Assurance Manager D. Tanis, Site Safety Manager C. Workman, Security Manager NRC personnel:

G. Kolcum, Acting Chief, Branch 3, Division of Reactor Projects LIST OF ITEMS OPENED, CLOSED AND DISCUSSED Opened and Closed 05000335/2013004-01 NCV Failure to Request NRC Approval prior to implementation of an Alternative Repair Method for ASME Class 3 Piping in the Intake Cooling Water System (Section 1R07)05000335, 389/2013004-02 FIN Partial Loss of Offsite Power due to Non-segregated Bus Failure (Section 4OA3.2)05000389/2013004-03 NCV Emergency Diesel Generator Inoperable for a Period Greater Than the Allowed Outage Time (Section 4OA3.3)

Closed 05000389/2013002-00 LER Failure to Invoke Technical Specification Action Statement for Failed Containment Isolation Valve (Section 4OA3.1)05000389/2012002-00 LER Non-Segregated Phase Bus Fault Resulting in a Partial Loss of Offsite Power (Section 4OA3.2)05000389/2013003-00 LER 2A Emergency Diesel Generator Failed to Start (Section 4OA3.3)05000335, 389/2515/182 TI Review of the Implementation of the Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase 2 (Section 4OA5.3)

LIST OF

DOCUMENTS REVIEWED

Section 1R04: Equipment Alignment

2-NOP-59.01A, 2A Emergency Diesel Generator Standby Lineup

2-NOP-03.11, High Pressure Safety Injection Initial Alignment

2-NOP-03.21, Low Pressure Safety Injection Initial Alignment

1-NOP-25.07, Control Room Ventilation System

1-NOP-25.03, Ventilation Systems Initial Alignment

Section 1R05: Fire Protection

ADM-0005729, Fire Protection Training, Qualification and Requalification

1-1800023, Unit 1 Fire Fighting Strategies

2-1800023, Unit 2 Fire Fighting Strategies

Section 1R07: Heat Sink Performance

Procedures:

0-OSP-37.01, Emergency Cooling Water Canal-Periodic Test, Rev. 5

0-PMM-14.01, Component Cooling Water Heat Exchanger Clean / Repair, Rev. 9

1-NOP-14.02, Component Cooling Water System

1-NOP-21.03A, 1A Intake Cooling Water System

Operation, Rev. 5

1-OSP-21.03, Shiftly Intake Cooling Water Operability Test, Rev. 2

2-OSP-25.02, Containment Fan Cooler Monthly Operability Run, Rev. 4

ADM-27.17, Land Utilization Routine and Inspection Program, Rev. 2

OP-1-0010125A, Surveillance Data Sheets, Rev. 150

OP-2-0010125A, Surveillance Data Sheets, Rev. 143

SPEC-M-081, CCW Heat Exchangers Tube Integrity Inspection, Rev. 0

Calculations:

08-185, Test Data Evaluation and Uncertainty Analysis for the CCW Heat Exchangers,

Rev. A (12/10/08)

PSL-1FSM-12-007, Min Wall Thickness and Bolted Plate Repairs-Line I-30-CW-29 and

CW-30 - ICW Discharge to Canal, Rev. 1

PSL-1FSM-05-031, Review of Fastener Substitution CRN 05192-12929, Revision 1

CN-OA-09-9, St. Lucie 2 EPU CCW/ICW Temperature Response Analysis, Rev. 0

CN-OA-09-10, CCW/ICW Temperature Response for St. Lucie Unit 1 EPU, Rev. 0

Drawings:

2998-G-082, Flow Diagram: Unit 2 Circulating & Intake Cooling Water System-Sheet 2,

Rev. 56

2998-G-125, Unit 2 Large Bore Piping Isometric Circulating Water, Sheet CW-F-14, Rev. 29

8770-G0082, Flow Diagram: Unit 1 Circulating & Intake Cooling Water System-Sheet 2,

Rev. 27

8770-G-082, Flow Diagram Circulating & Intake Cooling Water System, Sheet 2, Rev. 27

8770-G-125, Unit 1 Large Bore Piping Isometric Circulating Water, Sheet CW-F-10, Rev. 5

8770-G-125, Unit 1 Large Bore Piping Isometric Circulating Water, Sheet CW-F-3, Rev. 23

8770-G-712, Emergency Cooling Water System: Barrier Wall - Plan & Sect - MAA, Rev. 10

Heat Exchanger Inspection/Cleaning Reports:

AR 00475200, 2010-12285-1A CCW As-Found Condition Based on 100% ECT

Inspection, 06/10/2010

AR 00475919, 2010-124481 WO 38025245-01, Repair for the 1A CCW HX Outlet Channel

Head, 06/10/2010

AR 00532586, 2010-12119-1A and 1B CCW HX As Found Inspections in SL1-23R, 05/07/2010

AR 01711852, 1A CCW HX Exceeded 20 Tubes Block Criteria, Evaluation

Required, 02/17/2012

AR 01713217, As-Found Condition of 1A CCW Based on 100% ECT, 05/01/12

Eddy Current Examination Final Results, FPL-PSL Unit 1-1A Shutdown Cooling HX (SDC),

November 14, 2005

Final Inspection Report, Component Cooling Water - 1A (1A-CCW), St. Lucie Power Plant -

Unit 1 SL1-24, December 2011

PMID 00030703, CCW HX1A: Clean/Inspect/ECT Test

WO 38028212-01, CCW HX 1A-Clean/Inspect/ECT, 5/19/10

WO 40051673-01, CCW HX 1A-Clean/Inspect/ECT, 12/30/11

Corrective Action Documents:

AR 00585332, 2A ICW Discharge Line I-30-CW-30 Downstream of Orifice SO-21, 07/12/2011

AR 01712438, Thru-Wall Hole in U1 ICW Line CW-30, 04/30/2012

AR 01730604, Unit 1 ICW Discharge Line CW-29 Corrosion Cells, 03/15/2012

AR 01738262, 1A ICW Discharge Header - Coating Refurbishment Degradation, 02/29/2012

AR 01740921, Unit 1 Intake Cooling Water Discharge Pipe Failure, 03/03/2012

AR 01793151, CW-29: 2B ICW Discharge, Dry Pipe Section Thru-Wall Hole, 09/17/2012

AR 01887969, ICW PP 2C SPA HTR Conduit 20933F-SAB Conduit Cover Missing, 07/09/13,

07/09/13

AR 01888120, Corrosion on Bottom of ICW Support CW-3002-7141 for CW-77, 07/09/13

AR 01888747, UHS - Stop Log Guides Are Degraded, 7/11/13

Surveillance/In-Service Testing Records:

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 8, Valves SB-37-1 and SB-37-2 (Completed on 12/29/2011)

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 8, Valve 1-TCV-14-4A (Completed on 2/2/2012)

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 8, Valve 1-TCV-14-4B (Completed on 8/17/2009)

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 1, Valves 1-MV-21-2 and 1-MV-21-3 (Completed on 5/14/2001)

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 0, Valve 2-HCV-14-8A (Completed on 7/18/1998)

IST Evaluation Sheet: ADM-29.02, ASME Code Testing of Pumps and Valves, Appendix B,

Rev. 0, Valve 2-HCV-14-8B (Completed on 7/29/1998)

Surveillance Test: Procedure 0-OSP-37.01, Emergency Cooling Water Canal - Periodic Test,

Rev. 5 (Completed on 10/11/2012)

Surveillance Test: Procedure 0-OSP-37.01, Emergency Cooling Water Canal - Periodic Test,

Rev. 5 (Completed on 01/10/2013)

Surveillance Test: Procedure 0-OSP-37.01, Emergency Cooling Water Canal - Periodic Test,

Rev. 5 (Completed on 04/10/2013)

Technical Report No. 06-0632-TR-001, St. Lucie Inservice Testing Program Basis Document:

Component Cooling Water (CCW)-Unit 1-Valves, Rev. 0

Technical Report No. 06-0632-TR-012, St. Lucie Inservice Testing Program Basis Document:

Intake Cooling Water (ICW)-Unit 1- Valves, Rev. 0

Technical Report No. 06-0632-TR-101, St. Lucie Inservice Testing Program Basis Document:

Component Cooling Water (CCW)-Unit 2-Valves, Rev. 0

Technical Report No. 06-0632-TR-112, St. Lucie Inservice Testing Program Basis Document:

Component Cooling Water (ICW)-Unit 2-Valves, Rev. 0

Other Documents:

2-PTP-34, Pre-Operational Test Procedure: CCW Flow Adjustment for New HPSI and CS Pump

Seals, (Completed on 12/17/07)

AR 00583878, OE31993 DC Cook Unit 1: Component Design Basis identified that partial

blockage by algae adhering to the tube sheet in the heat exchanger.

AR 01725276, OE35042 Indian Point Unit 2: Unanticipated Debris Intrusion into the

Service Water

AR 01796918, OE36527 Limerick Unit 1: Update to OE35058 - Lower than expected residual

heat removal service water and emergency service water flow rates during system testing

AR 01812320, OE300859 Vogtle 1 and 2: OE300498R20121011 Service Water Supply Header

Pin Hole Leak

Bathymetric Survey of Big Mud Creek, South Hutchinson Island, St. Lucie County, FL for Florida

Power Light, February 28, 2011

Bathymetric Survey of the St. Lucie Nuclear Plant Intake and Discharge Canals for Florida

Power Light, March 2011

DBD-CCW-1, Design Basis Document: Unit 1 Component Cooling Water System, Rev. 4

DBD-ICW-1, Design Basis Document: Unit 1 Intake Cooling Water System, Rev. 4

Flow Balance Test: Procedure 2-NOP-14.02, Component Cooling Water System Operation,

Rev. 28 (Completed on 11/30/12)

Inspection of St. Lucie Ocean Cooling Water System: Intake Final Report, Aquatic Sciences

Project R20027OP, June 29, 2007

L-2000-215, NRC Commitment Change Generic Letter 89-13, 11/9/2000

L-2013-005, Clarification to NRC Commitment Regarding Generic Letter 89-13, 01/10/2013

L-90-28, Service Water System Problems Affecting Safety Related Equipment - Generic Letter 89-13, 01/25/1990

Operations Surveillance: Procedure 2-OSP-100.1, Schedule of Periodic Tests, Checks, and

Calibrations Week 1, Rev. 42 (Completed on 7/6/13)

Operations Surveillance: Procedure 2-OSP-100.12, Schedule of Periodic Tests, Checks, and

Calibrations Week 12, Rev. 48 (Completed on 6/22/13)

Operations Surveillance: Procedure 2-OSP-100.13, Schedule of Periodic Tests, Checks, and

Calibrations Week 13, Rev. 43 (Completed on 6/29/13)

PSL-ENG-SEMS-13-008, Eliminate Mid-Cycle Component Cooling Water (CCW) Heat

Exchanger Cleaning, Rev.0

System Health Report - Unit 1 Component Cooling Water System, 1/1/13 to 03/31/13

System Health Report - Unit 1 Intake Cooling Water System, 1/1/13 to 03/31/13

System Health Report - Unit 1 Ultimate Heat Sink, 1/1/13 to 03/31/13

System Health Report - Unit 2 Component Cooling Water System, 1/1/13 to 03/31/13

System Health Report - Unit 2 Intake Cooling Water System, 1/1/13 to 03/31/13

Updated Final Safety Analysis Report, Section 9.2.7, Ultimate Heat Sink, Amendment 22

Walkdown Inspection Report for Zone 42, Maintenance Rule Walkdown of Ultimate Heat Sink

per Procedure SCEG-009, Rev. 1C (Completed on 4/22/2013).

WO 39012461-09, AR No. 1712438 ENG Finding: Repair CW-30, EC#274859 Patch

Plate, 1/13/12

WO 39018367-01, UHS: Divers Inspection SB-37-1, 07/13/2010

WO 39018367-03, UHS: Divers Inspection SB-37-2, 07/14/2010

Section 1R11: Licensed Operator Requalification Program and Licensed Operator

Performance

2-EOP-01, Standard Post Trip Actions

2-EOP-03, Loss of Reactor Coolant

2-EOP-09, Loss of Offsite Power/Loss of Forced Circulation

2-AOP-09.04, Rapid Down Power

Section 1R12: Maintenance Effectiveness

ER-AA-100-2002, Maintenance Rule Program Administration

SCEG-004, Guideline for Maintenance Rule Scoping, Risk Significant Determination, and

Expert Panel Activities

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

OP-AA-104-1007, Online Aggregate Risk

WCG-016, Online Work Management

Section 1R15: Operability Determinations and Functionality Assessments

EN-AA-203-1001, Operability Determinations and Functionality Assessments

AR 1894701 1C AFW Pump Discharge Pipe Corrosion

Section 1R18: Plant Modifications

ADM-17.18, Temporary Modifications

ADM-17.11, 10 CFR 50.59 Screening

FPL Control Wiring Diagram 2998-B-327, Instrument Busses & Inverter 2MB & 2MD

Section 1R19: Post Maintenance Testing

ADM-78.01, Post Maintenance Testing

2-PME-25.08, Preventive Maintenance of Control Room Air Conditioning Units 2HVA/ACC-3A,

3B & 3C

OP-2-0010125A, Surveillance Data Sheets, sheet 8A

2-OSP-66.01, Control Element Assembly Quarterly Exercise

1-SMI-64.06, Linear Power Range Safety and Control Channel Monthly Calibration

1-SMI-64.10B, NI-006 Linear Power Range Safety Channel B Quarterly Calibration

Section 1R20: Refueling and Other Outage Activities

OM-AA-101-1000, Shutdown Risk Management

Section 1R22: Surveillance Testing

ADM-29.02, ASME Code Testing of Pumps and Valves

Section 4OA2: Identification and Resolution of Problems

OP-AA-108, Oversight And Control Of Operator Burdens

Section 4OA3: Follow-up of Events and Notice of Enforcement Discretion

ADM-07.04, Corrective Action Program Requirements

EN-AA-203-1001, Operability Determinations/Functionality Assessments

PI-AA-204, Condition Identifying and Screening Process

PI-AA-205, Condition Evaluation and Corrective Action

2-PME-59.01, 2A Emergency Diesel Electrical Periodic Maintenance and Inspection

Section 4OA5: Other Activities

Corrective Action Documents Generated

AR 01904765

AR01904633

AR01904151

AR01873582

AR01723581

Corrective Action Documents Reviewed

AR 01740921

AR01712438

AR01901172

AR 01874207

Drawings

Drawing #8770-G-125, Sheet CW-F-2, LARGE BORE PIPING ISOMETRIC CIRCULATING

WATER, Rev. 01

Drawing #8770-G-149, Sheet 2, MAIN STEAM & FEEDWATER PIPING - SECT and DETAILS,

Rev. 13

Drawing #8770-G-387, Intake Structure Cathodic Protection, Rev. 13

Drawing #8770-G-153, CONDENSATE PIPING PLAN, Rev. 29

Procedures

1-PME-75.01, Preventive Maintenance Procedure For Surveying Cathodic Protection System,

Rev. 5

1-ISP-100.01, ASME Section XI Pressure Test Procedure For Class 2 & 3 Systems, Rev. 10

ER-AA-102-1000, Underground Piping and Tanks Integrity Examination Procedure, Rev. 2

ER-AA-102, Underground Piping and Tanks Integrity Program, Rev. 5

Other Documents

1A AFW Pump Suction & Discharge to V09119, Data Sheet 1, 1-ISP-100.01, ASME SECTION

XI PRESSURE TEST PROCEDURE FOR CLASS 2 and 3 SYSTEMS, 12/2/2010

1C AFW Pump Suction & Discharge Header Piping to V09157 and V09151, Data

Sheet 1, 1-ISP-100.01, ASME SECTION XI PRESSURE TEST PROCEDURE FOR

CLASS 2 and 3 SYSTEMS, 12/16/2010

Suction Piping from CST to 2A AFW Pump and Discharge and Recirc Piping to V09119, Data

Sheet 1, 2-ISP-100.01, ASME SECTION XI PRESSURE TEST PROCEDURE FOR

CLASS 2 and 3 SYSTEMS, 2/5/2013

2C AFW Pump Suction, Discharge and Recirc Piping to V09157 and V09151, Data Sheet 1,

2-ISP-100.01, ASME SECTION XI PRESSURE TEST PROCEDURE FOR CLASS 2 & 3

SYSTEMS, 2/7/2013

Buried Piping Integrity Program System Health Report, 4/1-6/30/2013

Buried Piping Owner Certification for Krumins Coating Inspection of CW 29 Piping - B, 2/2012

EPRI Technical Report 1016456, Recommendations for an Effective Program to Control the

Degradation of Buried and Underground Piping and Tanks, Rev. 1

Inspection Program, Rev. 0, 6/2011Laboratory Results for Work Order 11F0033, Soil

Analysis, 6/2011

Laboratory Results for Work Order 12D0257, Soil Analysis, 5/2012

Laboratory Results for Work Order 13B0146, Soil Analysis, 3/2013

Laboratory Results for Work Order 13G0317, Soil Analysis, 8/2013

NACE Certification of Colemary

NACE Certification of Brooks

Report# PC/M 037-195, Supplement 2, Condenser Tube Cleaning and Debris Filter Systems

Report# NUC-RSC-13795, 2012 Annual Survey of the Cathodic Protection Systems at St Lucie

Nuclear Plant, Aug 2012

Project# 05271, Adhesion and Atlas Cell Qualification Testing of Carboguard 2012 N/

Carboguard 6250 N, Dec 2011

SPEC-C-004, Protective Coatings for Area Outside the Reactor Containment, Rev. 9

SPEC-M-023, ICW and CW System Inspection and Repair, Rev. 7

Storm Drain Inspection Report, Bartlett Nuclear, Feb. 2012Long Range Guided Wave

Inspection Report, 1/11/2009, FBS, Job Number SL001

Work Order# 40177238, Internal Plastic Coating for CW-30-1A ICW Discharge Pipe

Work Order# 40201965 01, U1 Cathodic Protection Monthly Inspection

Work Order# 20000028 01, U/1 Cathodic Protection Monthly Inspection

Work Order# 40246585 04, CW-90 Buried Piping Dig#1; perform Exploratory Excavation

EXTENDED POWER UPRATE (EPU) INSPECTION SUMMARY

U-1,

Inspection Inspection Report

Sample Summary U-2,

Procedure (ML Number)

Both

Reviewed Erosion Corrosion and Flow-accelerated

Corrosion controls for the following:

49001 Both

• High pressure extraction steam system

• Feedwater heater drains system

Reviewed the following sections of the safety

evaluation report (SER): Integrated

• 2.4, Instrumentation and Controls Inspection Report

• 2.2.2, Pressure-Retaining Components and 05000335/2012004, Both

Component Supports 05000389/2012004

71004 * 3.26, TS 3/4.5.1, Emergency Core Cooling (ML12304A067)

Systems (ECCS) - Safety Injection Tanks

Reviewed the following sections of the SER:

• Section 4.0, Regulatory Commitments Both

• Section 5.0, Recommended Areas of Inspection

MSIV Closure Test U-2

Observed simulator training on Main Feedwater Integrated

control malfunctions. Inspection Report

71111.11 05000335/2012002, Both

05000389/2012002

(ML12117A005)

Reviewed the following Engineering Change (EC)

packages:

• EC 246559, RCS Hot Leg Injection Modification

• EC 246543, Feed Water Regulator Valve

Modification Integrated

71111.17 Inspection Report U-1

• EC 249980, NSSS Set Point and Scaling

Modification 05000335/2012004,

• EC 246564, Safety Injection Tank Requalification 05000389/2012004

• EC 246556, Main Steam Isolation Valve (ML12304A067)

Modification

• EC 249981, Control Room Heating Ventilation and

71111.18 U-2

Air Conditioning Modification

U-1,

Inspection Inspection Report

Sample Summary U-2,

Procedure (ML Number)

Both

Reviewed the post-maintenance testing for the

following modifications:

• WO 40049782 Task 2, 1A Containment Spray

Pump Min-flow Piping Modification Engineering Integrated

Inspection Report U-1

Change (EC) 250013-M-220

• WO 40065765 Task 2, 1B Containment Spray 05000335/2012002,

Pump Min-flow Piping Modification EC 250013-M- 05000389/2012002

219 (ML12117A005)

• WO 40139405, Unit 2 Feed Water Regulating

U-2

Valve 9021B maintenance

• WO 40145261, 1B2 Safety Injection Tank

Pressure Alarm PIA-3341

• WO 40145261, 1B2 Safety Injection Tank

71111.19 Pressure Switch PS-3342

• WO 40145261, 1B2 Safety Injection Tank Integrated

Inspection Report U-1

Pressure Switch PS-3343

• WO 40145261, 1B2 Safety Injection Tank Level 05000335/2012004,

Alarm Switch LIA-334 05000389/2012004

• WO 40145261, 1B2 Safety Injection Tank Level (ML12304A067)

Transmitter LT-3341

• WO 40095052, 2C Control Room Ventilation

U-2

modification

• WO 40095070, 2B Containment Spray Flow Integrated

Limitation EC 249990 Inspection Report

• WO 40157020, 2B Charging Pump Safety 05000335/2012005, U-2

Injection Actuation System (SIAS) Circuit Change 05000389/2012005

EC 275025 (ML13031A341)

Reviewed Unit 1 integrated power ascension test

plan.

Integrated

Monitored power ascension from startup to 87 Inspection Report

71111.20 percent power and reviewed power ascension data 05000335/2012004, U-1

for the following power levels: 05000389/2012004

• 30 percent (ML12304A067)

• 50 percent

• 70 percent

U-1,

Inspection Inspection Report

Sample Summary U-2,

Procedure (ML Number)

Both

Reviewed Unit 2 integrated power ascension test

plan.

Integrated

Monitored power ascension from startup to 87 Inspection Report

percent power and reviewed power ascension data 05000335/2012005, U-2

for the following power levels: 05000389/2012005

• 30 percent (ML13031A341)

• 50 percent

• 70 percent

Monitored Unit 1 power ascension from 87 percent to

100 percent power and reviewed power ascension

data for the following power levels:

• 89 percent Integrated

• 92 percent Inspection Report

• 95 percent 05000335/2012004, U-1

• 98 percent 05000389/2012004

• 100 percent (ML12304A067)

Reviewed vibration data on critical piping at 100

percent power.

Monitored Unit 2 power ascension from 87 percent to

100 percent power and reviewed power ascension

data for the following power levels:

• 89 percent Integrated

• 92 percent Inspection Report

• 95 percent 05000335/2012005, U-2

• 98 percent 05000389/2012005

• 100 percent (ML13031A341)

Reviewed vibration data on critical piping at 100

percent power.

Component Design

Evaluated modifications to the following systems on Bases Inspection

Units 1 and 2 Report

71111.21 Both

• High pressure safety injection (HPSI) system 05000335/2012008,

• Main steam isolation 05000389/2012008

(ML13036A144)

U-1,

Inspection Inspection Report

Sample Summary U-2,

Procedure (ML Number)

Both

Integrated

Inspection Report 05000335/2012002,

05000389/2012002

(ML12117A005)

U-1

Integrated

Inspection Report 05000335/2012004,

05000389/2012004

Reviewed Action Requests (ARs) related to the EPU (ML12304A067)

71152

project Integrated

Inspection Report 05000335/2012004,

05000389/2012004

(ML12304A067)

U-2

Integrated

Inspection Report 05000335/2012005,

05000389/2012005

(ML13031A341)

Attachment