turkey point, unit 3 - extended power uprate cycle 26 ...startup reports shall address startup tests...

August 12, 2013L-2013- 226

10 CFR 50.36

FPL.

U. S. Nuclear Regulatory CommissionAttn.: Document Control DeskWashington, D.C. 20555-0001

Re: Turkey Point Unit 3Docket No. 50-250Renewed Facility Operating License No. DPR-31Extended Power Uprate Cycle 26 Startup Report - Supplement 3

References:

(1) J. Page (NRC) to M. Nazar (FPL), Turkey Point Units 3 and 4 - Issuance of AmendmentsRegarding Extended Power Uprate (TAC Nos. ME4907 and ME 4908), Accession No.ML1 1293A365, June 15, 2012.

(2) M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-2012-426), RenewedFacility Operating License No. DPR-31 Extended Power Uprate Cycle 26 Startup Report,Accession No. ML12341A097, December 4, 2012.

(3) M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-2013-073), RenewedFacility Operating License No. DPR-31 Extended Power Uprate Cycle 26 Startup Report-Supplement 1, Accession No. ML13071A345, February 26, 2013.

(4) M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-2013-180), RenewedFacility Operating License No. DPR-31 Extended Power Uprate Cycle 26 Startup Report-Supplement 2, Accession No. ML13182A007, May 23, 2013.

Pursuant to Turkey Point Unit 3 Technical Specification 6.9.1.1, Florida Power & LightCompany (FPL) is providing supplement 3 to the Unit 3 Cycle 26 Startup Report submitted onDecember 4, 2012 via Reference 2. The Startup Report and supplemental reports are requireddue to the implementation of Unit 3 Amendment No. 249 for the Extended Power Uprate (EPU)Project that was issued via Reference 1. Supplement 1 to the initial Startup Report wassubmitted on February 26, 2013 via Reference 3.

Supplement 2 to the initial Startup Report was submitted on May 23, 2013 via Reference 4. At thetime that supplement 2 to the initial Startup Report was issued, the remaining 10% transient ramptests from 100% rated thermal power (RTP) to 90% RTP, and then from 90% RTP back to 100%RTP had not been completed due to three unscheduled outages. The final tests have beencompleted and the results of the completed 100% RTP power ascension transient and steady statetesting results for Unit 3 are being submitted in the attached final report.

Turkey Point Unit 3 L-2013-226Docket No. 50-250 of 2

Should you have any questions regarding this submittal, please contact Mr. Robert Tomonto,Turkey Point Licensing Manager, at 305-246-7327.

Sincerely,

Michael KileySite Vice PresidentTurkey Point Nuclear Plant

Attachment

cc: USNRC Regional Administrator, Region IIUSNRC Project Manager, Turkey Point Nuclear PlantUSNRC Senior Resident Inspector, Turkey Point Nuclear Plant

Turkey Point Unit 3Docket No. 50-250

L-2013-226Attachment

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TURKEY POINT UNIT 3 CYCLE 26SUPPLEMENT 3

EXTENDED POWER UPRATE STARTUP REPORT



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IV

V

Table of Contents

IntroductionPower Ascension Test ProgramResultsSummaryReferences

4101919

Turkey Point Unit 3 L-2013-226Docket No. 50-250 Attachment

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1. Introduction

The purpose of this Startup Report is to provide a summary description of the plant startupand power ascension testing performed at Turkey Point following the implementation ofLicense Amendment No. 249 on the Extended Power Uprate (EPU) for Renewed FacilityOperating License DPR-31 for Turkey Point Unit 3 that was issued on June 15, 2012[Reference 1]. The amendment increased the authorized maximum steady-state reactorcore power from 2300 megawatts thermal (MWt) to 2644 MWt. This Unit 3 Cycle 26Startup Report is being submitted in accordance with Turkey Point Technical Specification6.9.1.1, Items (2) and (4).

Technical Specification 6.9.1.1, Startup Report, states:

"A summary report of plant startup and power escalation testing shall be submittedfollowing: ... (2) amendment to the license involving a planned increase in power level,...and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulicperformance of the unit. The report shall address each of the tests identified in the FSARand shall in general include a description of the measured values of the operating conditionsof characteristics obtained during the test program and a comparison of these values withdesign predictions and specifications. Any corrective actions that were required to obtainsatisfactory operation shall also be described. Any additional specific details required inlicense conditions based on other conmmitments shall be included in this report. SubsequentStartup Reports shall address startup tests that are necessary to demonstrate theacceptability of changes and/or modifications."

All required testing per the Startup Test Program has been completed for Turkey Point Unit3 Cycle 26.

The plant startup and power escalation testing verifies that key EPU core and plantparameters are operating as predicted. The major parts of this testing program include:

1) Cycle 26 core design summary,2) Low power physics testing, and3) Power ascension testing.

The test data collected during EPU power ascension summarized in this report concludesthat all major systems, structures, and components (SSCs) performed as predicted and therewas no adverse impact to the performance of the unit. All startup testing results related tocore performance were found acceptable and previously reported in Reference 5.Therefore, they are not repeated in this report. The EPU power ascension test data wasfound acceptable and previously reported in Reference 5. Copies of the completed EPUpower ascension test procedures are available on site for review.


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II. Power Ascension Test Program

The EPU power ascension test program consisted of a combination of normal startup andsurveillance testing, post-modification testing, and power ascension testing deemed necessaryto support acceptance of the proposed EPU. During the EPU start-up, power was increased in aslow and deliberate manner, stopping at pre-determined power levels for steady-state datagathering and formal parameter evaluation. These pre-determined power levels are referred toas test plateaus. The typical post-refueling power plateaus were used until the previouslylicensed full power condition (2300 MWt) was attained (approximately 87% of the EPU fullpower level of 2644 MWt). Above 2300 MWt, 3% intervals between test plateaus wereestablished for data acquisition and evaluation. A summary of the power ascension test planfrom LAR-205 [Reference 2] for power levels beginning at 2300 MWt is provided in Tables2.12-1 and Table 2.12-2.



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Table 2.12-1

PTN Extended Power Uprate Power Ascension Test Plan

Test Test Prior Rated Thermal Power - % of 2644 MWt (Allowance +0%, -5%) (Allowance +0%, -1%)

Modification Description ToStartup 0 5 10 15 20 25 30 40 45 50 55 60 65 70 75 80 87 89 92 95 98 100

NuclearSteam Supply Data

System Collection X X X X X X X X X(NSSS) Data Cleto

Record

Balance of DataPlant Data Collection X X X X X X X X X X

Record

Transient DataData Collection X X X X X X X X X

Recordl6 C

PowerDistribution X09 X XOl X XO) XO) XO) XO) X

Core Map and COLR

Parameters

NSSSCalorimetric Verify Thermaland Power Power and Adjust X X X X X X X X X X

Range NuclearChannel Instrumentation

Adjustment

ReactorCoolant RCS Flow

System (RCS) Calorimetric XFlow

Measurement



Page 6 of 20Table 2.12-1

PTN Extended Power Uprate Power Ascension Test Plan



Calibrate ExcoreIncore-Excore ntueaio

Axial Offset Instrumentation X(2) X(3) X(4)

Calibrations to Incore AxialOffset

10% Ramp to XLoad Changes Verify System X

Response

OST Turbine

Turbine Trip to Verify XSystem

Response

Turbine StopValve, Standard

Governor turbine valveValve, and tests w/post- X(6)

Intercept modificationValve tests

Testing.

SteamGenerator Manuallyinserted level

Level setpoint step-Feedwater changes in the X X X

Flow steamResponse generator.Testing

MonitorVibration Vibration in X X X X X

Monitoring Plant Pipingand Supports



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Table 2.12-1PTN Extended Power Uprate Power Ascension Test Plan



MonitorThermal Thermal X X X X X X X

Expansion Expansion inPlant Piping

Plant VerifyRadiation Expected X XSurveys Dose Rates

Plant VerifyTemperature Expected X X

Surveys Temperatures

NOTES:

(1) If required.(2) Incore flux map for data acquisition will be performed at less than 50% of 2644 MWt or when annunciator B2/2 or B2/3 alarms, whichever comes first.(3) Incore flux map for data acquisition will be performed at approximately 87% of 2644 MWt, if required.(4) At steady state equilibrium Xenon conditions.(5) Not in LAR-205, performed as part of normal startup procedures(6) Test moved from 35% to 50% to ensure that ESFAS high steam flow and AMSAC arming setpoint are not adversely affected by steam flow imbalance.



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Table 2.12-2

Large Plant Transient Tests in Turkey Point EPU Power Ascension Test Plan

Proposed Test Description Expectation

Turbine Overspeed Trip The turbine will be, with the This test will verify proper operation offrom 5% EPU Power reactor at approximately 5% the overspeed mechanism for the new

power, automatically tripped EHC turbine control, and properas speed exceeds the electronic operation of the new turbine controloverspeed trip setpoint. valves.

10% Ramp Load Change Ramp load change limited by These ramps will test NSSS and BOPat new 30% and 100% station license conditions and control system operation, to ensureEPU Power fuel pre-conditioning that no unanticipated aggregate effects

considerations. have been produced by interaction ofthe plant modifications.

Turbine Stop Valve, Standard turbine valve testing Validate dynamic performance of newGovernor Valve, and augmented by post- governor valve design to ensureIntercept Valve Testing at modification tests associated adequate transient response. Verify35% EPU Power with EHC Turbine control acceptable dynamic performance of

and Governor Valve the new HP turbine rotor duringReplacement. changes in individual arc steam flows.

Steam Generator Level / Verify response to manually Verify SG level control systemFeedwater Flow Dynamic inserted level setpoint step- response and acceptability of over-testing at 30%, 87% and change of 5% in the steam shoot, damping and steady-state limit95% EPU Power generator. Both up-going and cycling at the new licensed power

down-going setpoint changes level. Verify acceptable operation ofof different magnitudes will the feedwater control system.be inserted.

FPL provided specific acceptance criteria in response to NRC request for additionalinformation [Reference 3] for the 10% ramp load change list in Table 2.12-2 above asfollows:

* Reactor coolant system (RCS) average temperature, pressurizer pressure, andpressurizer water level will be controlled to the programmed values.

" Steam generator water level will demonstrate good feedwater level control andmaintain acceptable margin to the trip level setpoint.

" Nuclear power peak overshoot/undershoot should be less than 3 percent reactorthermal power.

" Steam generator water level should return to programmed level setpoint within ±2percent narrow range with dampening oscillations within 15 to 20 minutes.


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Prior to exceeding the previous licensed core thermal power of 2300 MWt, the datagathered at the pre-determined power plateaus, as well as observations of the slow, butdynamic power increases between the power plateaus, allowed verification of theperformance of the EPU modifications. The steady-state data collected at approximately87% power was especially significant because this test plateau corresponded to theprevious licensed core power level of 2300 MWt. Data collected at this plateau formedthe basis for comparison of data collected at higher plateaus.

Once testing was completed at the 2300 MWt plateau, power was slowly and deliberatelyincreased through four additional test plateaus, each differing by approximately 3% of theEPU rated thermal power. Both dynamic performance during the ascension and steady-stateperformance for each test plateau were monitored, documented and evaluated against pre-determined acceptance criteria and expected values. The acceptance criteria for the powerascension test plan were established as discussed in Regulatory Guide (RG) 1.68, Initial TestPrograms for Water-Cooled Nuclear Power Plants and NUREG 0800, Standard Review Planfor the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition, Section14.2.1. Criteria were provided against which the success or failure of the test was judged.In some cases, the criteria were qualitative where applicable. Quantitative criteria hadappropriate tolerances.

Specific acceptance criteria and expected values were established and incorporated intothe power ascension test procedures. Level 1 acceptance criteria are values for processparameters assigned in the design of the plant that are safety significant. If a Level Icriterion is not satisfied, the power ascension will be stopped and the plant will be placedin a condition that is judged to be safe based upon prior testing. Resolution of the issue thatresulted in exceeding the Level 1 criterion must be resolved by equipment changes or throughengineering evaluation, as appropriate. Level 2 acceptance criteria are values that relate toplant functions or parameters that are not safety significant. If Level 2 criteria are not met,the Power Ascension Test Plan may continue. Investigation of the issue that resulted inexceeding the Level 2 criterion may continue in parallel with the power escalation. Theseinvestigations would be handled by existing plant processes and procedures.

Following each increase in power level, test data was evaluated against its performanceacceptance criteria (Level 1 and 2 and expected values, i.e., prediction targets for powerlevel). If the test data satisfied the acceptance criteria, then system and componentperformance were considered to have complied with their design requirements. Predictedvalues are used for optimizing SSC performance only and are not acceptance criteria.

In addition to the steady-state parameter data gathered and evaluated at each test condition,the dynamic parameter response data gathered during the ascension between test plateauswas also evaluated and demonstrated overall stability of the plant.

Hydraulic interactions between the new main feedwater pumps and the steam generator flowcontrol valves, as well as the impact of the higher main feedwater flow, were monitored andevaluated. Individual control systems, such as steam generator level control and feedwaterheater drain level control, were optimized for the new EPU conditions, as required. Thepower ascension testing adequately identified any unanticipated adverse system interactionsand allowed them to be corrected in a timely fashion prior to operation at higher powerlevels.


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Vibration Monitoring

A piping and equipment vibration monitoring program, including plant walkdownsand monitoring of plant equipment pre- and post EPU, was established to ensure that anysteady-state flow induced piping vibrations following EPU implementation were notdetrimental to the plant, piping, pipe supports, or connected equipment.

The predominant way of assessing piping and equipment vibrations was to monitor thepiping during the plant heat-up and power ascension. The methodology used formonitoring and evaluating vibration was in accordance with ASME OM-S/G-2007,Standards and Guides for Operation and Maintenance of Nuclear Power Plants, Part 3,Requirements for Preoperational and Initial Startup Vibration Testing of NuclearPower Plant Piping Systems.

The scope of the piping and equipment vibration monitoring program included accessiblepiping that experienced an increase in process flow rates. Branch lines attached to thispiping that experienced increased process flows were also monitored as operatingexperience has shown that branch lines are susceptible to vibration-induced damage. Thescope of the program included the following systems:

* Main steam (outside of containment) including Reheater Inlet,* Main Steam modified supports (inside containment),* Feedwater (outside of containment),• Condensate,* Extraction Steam,* Heater Drains,* Moisture Separator Drains, and* Turbine Gland Steam and Drains.

III. Results

NSSS Data Collection

The Turkey Point Unit 3 nuclear steam supply system (NSSS) significant parameters wereobserved at the 20%, 30%, 50%, 75%, 87%, 89%, 92%, 95%, 98%, and 100% EPU powerplateaus. During power ascension to 100%, the NSSS significant parameter values at thevarious power plateaus met all Level 1 and Level 2 criteria with the exception of RCS Trefand steam flow.

RCS Tref is affected by the turbine inlet pressure (TIP). The Tref circuit was normalized tothe actual TIP value at approximately 95% power for the expected value at 100% power. At99.3% power the TIP value is only 5 psi below the predicted value which results in the actualTref only 0.2 degree Tref below the predicted value. This minor deviation is well within theexpected range and meets Level 1 and Level 2 criteria. The main steam flow and mainfeedwater flow safeguards signals experienced excessive flow oscillation above 99% poweras previously reported in Reference 4. Single channel Hi steam flow and feed flow/steamflow mismatch alarms were received at approximately 99.7% power which exceeded testacceptance criteria. Unit 3 power was lowered to approximately 99.5% power to reduce theseoscillations to normal levels while the cause of the alarms was determined and corrective


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actions implemented. The alarms were found to be caused by instrument signal spiking as aresult of flow induced turbulence in the feedwater and main steam lines. FPL has takencorrective actions to modify the steam flow and feedwater flow circuits which eliminated thealarms such that Unit 3 was able to reach 100% rated thermal power (RTP).

Below provides a brief summary of major control parameters observed during the powerascension test program. In addition, Table 1 provides a summary of the NSSS significantparameters at the 100% power plateau.

* RCS temperatures - As can be seen from Table 1, the maximum measured averageRCS temperature at the100% EPU power plateau is 579.5°F which is below theEPU full power limit of 581.5°F.

* Pressurizer pressure - remained at 2235 psia +/- 5% within normal operating bandthroughout the power ascension and transient test.

" Pressurizer level - The pressurizer level program changes from 22.5% at RCSaverage temperature 547 OF to 56.9% at full load RCS average temperature of580'F. Pressurizer level was maintained on program throughout the powerescalation within normal control system tolerances.

* Containment temperature - temperature ranged from 99.5°F to 1 14.7°F throughoutthe power ascension well below the 125 OF limit.

* Steam generator pressure - ranged between 975 psig at 20% EPU power and 785psig at 100% EPU power.

" Steam generator level - remained constant at 50% narrow range scale withinnormal control system tolerances throughout the power ascension.

Balance of Plant (BOP) Data Collection

The Turkey Point Unit 3 balance of plant (BOP) significant parameters were observed at the20%, 30%, 50%, 75%, 87%, 89%, 92%, 95%, 98% and 100% EPU power plateaus. As themajority of the EPU hardware changes were made to BOP equipment, extensive monitoring ofthe secondary side was performed during the EPU power ascension. Major systems andcomponents monitored included:

* High pressure turbine, low pressure turbine, main generator and exciter vibration,• High pressure turbine, low pressure turbine, main generator and exciter bearing

temperatures,• High and low pressure turbine steam pressure and temperature,* Moisture separator reheater (MSR) pressure and temperature,* Turbine digital controls,* Main generator gas temperatures,* Turbine cooling water system performance,* Condensate, main feedwater, and heater drain system pressure and temperature,* Condensate, main feedwater, and heater drain pump performance,* Feedwater heater performance,* Heater drain valve performance,* Main condenser performance,* Main transformer performance,* Isolated phase bus cooling performance, and


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* Main generator electric output.

There were no BOP parameters that exceeded level 1 criteria at 100%. There were no BOPparameters that exceeded level 2 criteria other than those previously reported in Reference 5and all were found acceptable upon further evaluation. The BOP data collected during theEPU power ascension testing is too extensive to include in this summary report but Table 1provides a summary of major control parameters at 100% power. The completed testprocedure and all BOP data collected at the 20%, 30%, 50%, 75%, 87%, 89%, 92%, 95%,98% and 100% EPU power plateaus are available for review on-site, if required.

Vibration Monitoring

The Turkey Point Unit 3 piping and equipment within the scope of the EPU vibrationmonitoring program were observed at several different plant operating conditions, namelythe 30%, 50%, 87%, 89%, 92%, 95%, 98% and 100% EPU power plateaus. The firstobservations were conducted prior to the shutdown in which the EPU modifications wereimplemented. Data from these observations was used to develop the list of priorities andbaseline data for observation during the EPU power escalation. By comparing the observedpipe vibrations / displacements at various power levels with previously establishedacceptance criteria, potentially adverse pipe vibrations were identified, evaluated andresolved.

Engineering has reviewed the vibration and thermal expansion data from each of theapplicable plateaus through 100% and determined that all lines in the monitoring programhave met their acceptance criteria.

A screening criteria was established where piping/tubing/supports with vibration levels withdisplacements of 1/16" to 1/8" required further engineering analysis. For the piping, tubing,and supports within the program that experienced vibration levels exceeding the screeningcriteria, nine items showed low margin but were still below the acceptance criteria at the100% power level. Modifications were implemented to improve margin for these items.

Thermography Checks and Temperature Profiles

Temperature monitoring of the Main and Auxiliary Transformers and the Isophase Bus ductusing thermography was performed at the 30%, 50%, 75%, 87%, 89%, 92%, 95%, 98% and100% power levels. The thermography checks were performed to ensure none of theequipment was overheating due to the EPU power increase. The test data was evaluated andfound that all temperatures were below the alert range and within the expected values at 100%power.

10% Load Ramp

Two 10% load changes are required at a ramp rate of 1 %/min. The first test was a downpower equivalent to a 10% turbine load change starting at 100% power +0% - 1%. Thesecond load change was a load increase equivalent to a 10% turbine load change starting atapproximately 90%.

As stated above in Section II, the purpose of these tests are to provide additionalconfidence in the validity of the analytical models and assumptions used in the analysis of


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plant modifications and integrated plant response to transients, and also verify that no newthermal hydraulic phenomena or adverse system interactions are created by the EPU.

The dynamic behavior of the various plant control systems are observed and evaluatedagainst Level 1 and Level 2 acceptance criteria to ensure that the combination of increasedEPU power and changes to the plant configuration (EPU modifications) have not resultedin an unacceptable aggregate impact. Test acceptance criteria are:

" RCS average temperature, pressurizer pressure, and pressurizer water level will becontrolled to the programmed values.

* Steam generator water level will demonstrate good feedwater level control andmaintain acceptable margin to the trip level setpoint.

" Steam generator water level should return to programmed level setpoint within ±2percent narrow range with dampening oscillations within 15 to 20 minutes.

* Nuclear power peak overshoot/undershoot should be less than 3 percent reactorthermal power.

10% Down Power

Due to performance issues with a feedwater pump, Unit 3 performed a rapid down poweron 5/4/13 from approximately 98.3% indicated nuclear power to 85.4% over a 13 minuteperiod reducing turbine load by 118 MWe. This rapid down power achieved a ramp rategreater than 1 %/min and reduced power greater than the prescribed 10% turbine load(13.6%). However, the initial power level was 0.7% less than 99% rated thermal poweridentified in Table 12.2-1 of the test program.

The initial condition for the ramp test is specified in table 2.12-1 above which covers bothsteady state plateau data gathering done at 3% intervals and the dynamic 10% ramp tests.Since the tolerance covers both types of test and the steady state plateaus are only 3%apart, a 1% tolerance is needed to ensure an adequate power increase that will result inobservable changes in parameters.

Table 2.12-1 has "(down)" applied to the box for the 10% ramp test under the 100%column. The intent of this note is to indicate that the 1% tolerance on initial power doesnot apply to the ramp up from 90% to minimize the potential for an overpower conditionto occur due to turbine control system tolerance. As stated in References 1, 2 and 3 theintent of the test is to determine there are no adverse system interactions or new thermalhydraulic phenomena introduced to plant systems from EPU changes and to sufficientlytest NSSS and BOP control systems.

Each of the system parameters impacted by the test is affected by a change in either Tref orTavg. The turbine, control rod, pressurizer level, pressurizer pressure and steam generator


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level control system will respond to the magnitude and rate of either Tavg or Tref changeeither through thermodynamic/hydraulic changes. The maximum Tavg change is afunction of the turbine ramp rate, reactivity feedback from the core (power defect) andcontrol rod system response to Tref. Given the same ramp rate and control system settingfor a ramp test done at two different initial power conditions, only power defect wouldaffect Tavg response. A review of the power defect curves for Unit 3 shows that between100% power and 80% power, the power defect is linear with reactor power. Therefore, theamount of negative reactivity added to the core per degree change of Tavg will be the sameanywhere between 100% power and 80% power. Therefore, starting the test at a slightlylower initial power will not change the magnitude or rate of RCS temperature change andthe challenge to the control systems will be the same. Secondary system response is afunction of feedwater flow which is linear with turbine load/steam flow. There is a slightincrease in the differential pressure across the feedwater regulating valve as FW flowdecreases which make it more challenging for steam generator level control. Therefore,starting the test at a slightly lower initial power level will not change the magnitude or rateof feedwater and steam flow changes. Since it has been concluded that the slightly lowerinitial power level will not reduce the challenge to control systems and thermal hydraulicresponses, the power reduction performed on 5/4/13 is acceptable for demonstratingintegrated plant response to transients and verifying that no new thermal hydraulicphenomena or adverse system interactions are created.

A review of system transient data for the 5/4/13 10% load reduction shows that:

* RCS average temperature, pressurizer pressure, and pressurizer water level werecontrolled to their programmed values.

" Steam generator water level demonstrated good feedwater level control andmaintained acceptable margin to the trip level setpoint.

" Steam generator water level returned to programmned level setpoint within ±2 percentnarrow range with dampening oscillations within 15 to 20 minutes.

" Nuclear power peak overshoot/undershoot was less than 3 percent reactor thermalpower.

In addition, level 1 and 2 criteria for each of the above control systems were met sinceeach controlled their respective process parameter within technical specification limitswith margin. There were no new thermal hydraulic phenomena or adverse systeminteractions observed.

All acceptance criteria were met for the 10% load down power test.

10% Power Increase

The 10% power increase was performed on 6/25/13 starting at 88.5% of RTP. Starting1.5% below 90% power provided ample margin to avoid over power at the end of the


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ramp. As stated above in the 10% down power discussion, starting slightly lower than 89%power does not impact control system response.

Over a 10 minute period, the turbine load was increased by 78 MWe which is equal to a9.2% load increase. The ramp test did achieve the full 84 MWe 10% load change over anadditional 4 minute period. The turbine control system (TCS) response is designed toreduce the ramp rate as turbine load approaches its target. However, the TCS decreased theramp rate at more than expected as the target was approached. LAR-205 Section2.12.1.2.3.5 and Table 12.2-2 do not specify tolerances for the ramp rate or the turbineload. The following system responses were observed for the ramp increase test:

* RCS temperature was increased with manual rod control since the automatic out rodmotion feature has been removed at Turkey Point. Operators maintained Tavg within1.5 degrees of Tref for the entire transient.

" Pressurizer pressure reached a maximum of 2238.6 psig and was reduced byincreased spray to a minimum value of 2217.6 psig and then returned to to theprogram setpoint of 2235 psig +/- 3 psi.

" Pressurizer level followed RCS Tavg and maintained level within 0.6% of theprogrammed value throughout the transient demonstrating excellent control.

* The load increase achieved over the 10 minute ramp was 78 MWe which equates to9.2% of 100% turbine load. Average Nuclear power increased from 88.3% to 96.9for a 8.6% change which is well with the 3% undershoot criteria.

* All 3 steam generator level control systems demonstrated very good feedwater levelcontrol maintaining within 2% of the setpoint from the beginning of the transient.This also demonstrated the ability to maintain adequate margin to trip.

The power increase ramp test met all the control system acceptance criteria identifiedabove in the power decrease ramp test. In addition, level 1 and 2 criteria for each of theabove control systems were met since each controlled their respective process parameterwithin technical specification limits with margin. There were no new thermal hydraulicphenomena or adverse system interactions observed.

However, the 10% load change and 1% ramp rate test conditions were not met. Given theobserved control system response and the available margin to acceptance criteria and thecontrol system response observed during the down power when a 1 %/min ramp rate and10% load change were achieved, the test results adequately demonstrate that the testacceptance criteria would also be met for the slightly higher load increase and ramp rate.Therefore, the test deviation for the 10% load and 1% ramp rate are acceptable.


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Plant Radiation Surveys

The purpose of the survey is to verify plant areas remain as low as reasonable achievable(ALARA) per 10 CFR 20 and doses remain within current limits. 10 CFR 20 criteria is metby confirming doses remain low in normally accessible areas, and dose rate postings withineach area are maintained. Turkey Point also has design basis dose limits. Per UFSARChapter 11.2 and Chapter 8A normal operation doses are considered in shielding design andenvironmental qualification of electrical equipment. Normal operational doses limits arebased on the radiation zones identified in UFSAR Table 11.2-1. In addition, the secondaryshield wall inside containment is designed to attenuate normal operational doses such thatthe dose rate at the outside of the containment wall is less than 1 mrem/hr.

Radiation surveys were performed at the 87% power plateau for a baseline at the pre-EPU100% equivalent power level and at the EPU 100% power level in accessible areas that wereexpected to have increased dose rates. The expected increase in dose rates should beapproximately 15% for those areas that are subject to nitrogen- 16 gamma or neutron flux.

Inside Containment

The dose rates measured just inside the secondary shield wall (RCS piping area) andoutside the secondary shield walls showed measured dose rate increases in some locationsthat are larger than expected. A review of historic survey maps for the same areas from2005 prior to EPU show readings higher than at EPU 100% power. The surveys in theprimary piping loop area are performed by mounting a detector on the end of a pole andinserting the pole into the loop area while the RP technician stands behind the secondaryshield wall. Using this type of measurement cannot reproduce the same survey dose pointwith any precision. A review of the dose rates inside the secondary shield wall showssignificant differences based on minor changes in physical locations. Measurementsoutside the secondary shield wall have similar challenges due to the streaming affect fromshield wall penetrations. A small change from target survey locations will change dosesignificantly and the dose rates at 100% power do not allow for a precision map to bemade.

Containment is classified as a locked high radiation area. The measured dose rates did notincrease the level of the posting beyond a locked high radiation area. The controls imposedby the Technical Specifications and 10 CFR 20 for locked high radiation areas willmaintain personnel dose ALARA.

Inside the secondary shield wall (RCS loop area) the Environmental Qualification (EQ)program assumed a dose rate of 60 R/hr and the measured value at the entrance to the RCSpiping area was 1.8 R/hr. The EQ program assumed a dose rate of 1.125 R/hr outside thesecondary shield wall and the maximum measured dose was 0.6 R/hr.

The dose rates measured adjacent to the containment wall did not change from measuredvalues prior to EPU and remain less than 1 mremnhr.

Outside Containment


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Measurements outside containment did not show any appreciable increase in dose exceptfor the Charging pump room and pipe and valve room. The charging pump room radiationmeasurements showed that half of the locations had decreased radiation levels and halfincreased in radiation level. The largest increase went from 0.5 mrem to 8 mrem in the nonRegenerative Heat Exchanger room. This was the highest dose for the locations thatincreased. In the pipe and valve room the largest increase went from 2.0 mrem to 17 mremnear the Residual Heat Removal penetration.

While these areas exceeded the expected 15% increase, the actual dose rates are very lowand do not affect the postings or radiation zone classifications for any area. The AuxiliaryBuilding areas surveyed are controlled radiation areas. The measured dose rates do notincrease the level of the posting beyond a radiation area. The controls imposed by thetechnical specification and 10 CFR 20 for radiation areas will maintain personnel doseALARA. The EQ program assumed dose rates at the maximum allowed for the radiationzone classification. All surveyed areas remained below the radiation zone classifications.

The measured dose rates inside and outside containment at 100% EPU power meet the10 CFR 20 and Turkey Point limits.

Plant Temperature Surveys

Plant ambient temperature survey data was collected with data recorders in those areaspotentially impacted by EPU equipment heat loads. Most areas did not see any appreciabletemperature change. All area temperatures remain below the general outside area designlimit of 104 'F except the condensate pump area and main feedwater pump room.

As part of the EPU design changes for the Condensate pumps general area supply andexhaust fans were added for the condensate pump area. However, temperatures wereobserved between 120 'F and 130 'F even with the addition of the fans. The condensatepump and motor design temperature limits are above 140 'F except for the motor lowerradial bearing. The lower radial bearing does not have an oil cooler and relies on ambientcooling. The bearing has experienced alarms which actuate at a bearing temperature of185 'F. A review of the air flow in the condensate pump area shows some portions maynot be receiving adequate flow. Temporary fans have been installed to augment air flow tothe low flow areas and it is maintaining bearing temperatures below their alarm point untila permanent solution can be implemented. Procedural guidance directs shutting down thepump if bearing temperatures reaches 200 'F. The high area temperature condition hasbeen entered into the Turkey Point Corrective Action Program for resolution.

The Steam Generator Feed Pump (SGFP) Room temperature reached 11 0IF during someperiods. While the EPU did increase feedwater flow the heat load to the feedwater pumproom did not increase. This higher room temperature condition is a pre-EPU issue whichhas been compensated for by vane axial fans which provide forced circulation through theSGFP Motors. An exhaust plenum is located above each SGFP motor and is attached to25,000 cfm exhaust fans. The additional fans maintain the feedwater pump motors below


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their design maximum operating temperatures. All other equipment within the feedwaterpump room is rated for temperature well above 11 0IF. Based on past plant operation, theelevated temperatures have not caused a reduction in feedwater pump reliability.

Leading Edge Flowmeter (LEFM) Commissioning

As described in Reference 2, the Turkey Point EPU project included a 1.7% MeasurementUncertainty Recapture (MUR) thermal power increase. To achieve the MUR power increaseof 1.7%, the Cameron Leading Edge Flow Meter (LEFM) CheckPlusTM ultrasonic flowmeasurement instrumentation was installed to improve feedwater flow measurementaccuracy. An individual LEFM CheckPlusTM system flow element (spool piece) wasinstalled in each of the three main feedwater lines and was calibrated in a site-specific modeltest at Alden Research Laboratories with traceability to National Standards.

The LEFM CheckPlusTM system was installed and commissioned in accordance with FPLprocedures and Cameron installation and test requirements. LEFM CheckPlusTMcommissioning included verification of ultrasonic signal quality and evaluated the actualplant hydraulic velocity profiles as compared to those documented during the AldenResearch Laboratories testing. Final verification of the site-specific uncertainty analysesoccurred as part of the LEFM CheckPlusTM system commissioning process. Thecommissioning process provides final positive confirmation that actual performance in thefield meets the uncertainty bounds established for the instrumentation which satisfieslicensing comnmitment 13 in Section 3.3 (a) of the EPU Safety Evaluation Report. Inaddition to the Cameron commissioning test and evaluations, FPL evaluated LEFMperformance as follows:

A review of feedwater parameters for LEFM and the Venturi based measurements werecompleted to determine deviations and reasonableness of the Venturi correction factor.There are no operational alarms or other deficiencies noted. Steam Generator Heat rates andcalorimetric calculations were performed using the LEFM and Venturi based data. TheLEFM ultrasonic flow transmitters are performing as expected. After repair of the "B" loopVenturi flow transmitter used for calorimetric calculation, the LEFM is showing a 1.3%greater thermal power than the Venturi based value at 100%. The Venturi LEFM correctionfactor adjusts the Venturi flowrate down such that the 1.3% deviation is eliminated andVenturi flow matches LEFM flow.

IV. Summary

The test data collected during EPU startup and power ascension and summarized in this reportdemonstrates that all major systems, structures, and components performed as predicted andthere was no adverse impact to the performance of the unit. The EPU startup and powerascension test data satisfied all acceptance criteria. Copies of the completed EPU startup andpower ascension test procedures are available on site for review.


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V. References

1. J. Page (NRC) to M. Nazar (FPL), Turkey Point Units 3 and 4- Issuance ofAmendments Regarding Extended Power Uprate (TAC Nos. ME4907 and ME4908), Accession No. ML11293A365, June 15, 2012.

2. FPL Letter, M. Kiley (FPL) to U.S. Nuclear Regulatory Commission (NRC)(L-2010-113), License Amendment Request No. 205: Extended Power Uprate(EPU), (TAC Nos.ME4907 and ME4908), Accession No. ML103560169, October21, 2010.

3. M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-201 1-101),Turkey Point Units 3 and 4 Docket Nos. 50-250 and 50-251 Response to NRCRequest for Additional Information Regarding Extended Power Uprate LicenseAmendment Request No. 205 and Balance of Plant Issue, Accession No.ML11105A146, April 14, 2011.

4. M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-2013-073),Renewed Facility Operating License No. DPR-31 Extended Power Uprate Cycle 26Startup Report-Supplement 1, Accession No. ML 13071 A345, February 26, 2013.

5. M. Kiley (FPL) to U. S. Nuclear Regulatory Commission (NRC) (L-2012-426),Renewed Facility Operating License No. DPR-31 Extended Power Uprate Cycle 26Startup Report, Accession No. ML 12341 A097, December 4, 2012.



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Table 1BOP and Primary Parameter Summary

Primary Major Parameter 100%tAvg Power % 99.33Avg Thot 'F 613.8AvgTcold 'F 546.2Avg Tavg 'F 580.0SG A Press psig 784SG B Press psig 786SG C Press psig 784Pzr Avg % Level 56.2Turbine Inlet Avg Press (TIP) psig 652.2Tref 579.5Containment Temp TF Highest 100.5

BOP Major ParameterSG A Level % 48.6SG B Level % 51.0SG C Level % 48.4Avg Steam flow MPPH 3.78Avg FW flow MPPH 3.91Final Venturi FW Temp TF 438.8Condenser Backpressure in-Hg 1.5Generator Output Mwe 860.4Thermal Output MWt 2624.9

(1) All feedwater flow and thermal output values are based on the Venturi flow meter except at 98% and100% power which are based on the LEFM flow meter

turkey point, unit 3 - extended power uprate cycle 26 ...startup reports shall address startup tests...

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