L-2011-406, Response to NRC Request for Additional Information (RAI) Regarding Extended Power Uprate License Amendment Request

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Response to NRC Request for Additional Information (RAI) Regarding Extended Power Uprate License Amendment Request
ML11287A039
Person / Time
Site: Saint Lucie NextEra Energy icon.png
Issue date: 10/12/2011
From: Richard Anderson
Florida Power & Light Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
L-2011-406
Download: ML11287A039 (17)
v • d • e


Text

0IPL.

October 12, 2011 L-2011-406 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Re:

St. Lucie Plant Unit 2 Docket No. 50-389 Renewed Facility Operating License No. NPF-16 Response to NRC Request for Additional Information (RAI)

Regarding Extended Power Uprate License Amendment Request

References:

(1) R. L. Anderson (FPL) to U.S. Nuclear Regulatory Commission (L-2011-021), "License Amendment Request for Extended Power Uprate," February 25, 2011, Accession No. ML110730116 (2) Email from NRC (T. Orf ) to FPL (C. Wasik), "St. Lucie 2 EPU -- draft RAIs from Balance-of-Plant (SBPB)," August 17, 2011 (3) U.S. Nuclear Regulatory Commission (H. N. Berkow) to Siemens Westinghouse Power Corporation (S. Dembkowski), "Final Safety Evaluation Regarding Referencing the Siemens Technical Report No. CT-27332, Revision 2, 'Missile Probability Analysis for the Siemens 13.9 M2 Retrofit Design of Low-Pressure Turbine by Siemens AG' (TAC No.

MB7964," March 30, 2004, Accession No. ML040930616 By letter L-2011-021 dated February 25, 2011 [Reference 1], Florida Power & Light Company (FPL) requested to amend Renewed Facility Operating License No. NPF-16 and revise the St.

Lucie Unit 2 Technical Specifications (TS). The proposed amendment will increase the unit's licensed core thermal power level from 2700 megawatts thermal (MWt) to 3020 MWt and revise the Renewed Facility Operating License and TS to support operation at this increased core thermal power level. This represents an approximate increase of 11.85% and is therefore considered an Extended Power Uprate (EPU).

By email from the NRC Project Manager dated August 17, 2011 [Reference 2], additional information was requested by the NRC staff in the Balance-of-Plant Branch (SBPB) to support their review of the EPU LAR. The draft request for additional information (RAI) identified five questions. The response to these RAIs is provided in Attachment 1 to this letter.

In accordance with 10 CFR 50.91 (b)(1), a copy of this letter is being forwarded to the designated State of Florida official.

Florida Power & Light Company 6501 S. Ocean Drive, Jensen Beach, FL 34957

L-2011-406 Page 2 of 2 This submittal does not alter the significant hazards consideration or environmental assessment previously submitted by FPL letter L-2011-021 [Reference 1].

This submittal contains no revisions to existing commitments. A new commitment is made pursuant to the conditions in the NRC Final Safety Evaluation [Reference 3] as follows:

FPL commits to inform the NRC about turbine disk inspection results and plans to reduce the probability of turbine missile generation, P1, for continued operation should cracks be detected in the inspection.

Should you have any questions regarding this submittal, please contact Mr. Christopher Wasik, St. Lucie Extended Power Uprate LAR Project Manager, at 772-467-7138.

I declare under penalty of perjury that the foregoing is true and correct to the best of my knowledge.

Executed on j* -

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-,92c911 Very truly yours, Richard L. Anderson Site Vice President St. Lucie Plant Attachment cc:

Mr. William Passetti, Florida Department of Health

L-2011-406 ATTACHMENT 1 Page 1 of 15 Response to Request for Additional Information The following information is provided by Florida Power & Light in response to the U.S. Nuclear Regulatory Commission's (NRC) Request for Additional Information (RAI). This information was requested to support the Extended Power Uprate (EPU) License Amendment Request (LAR) for St. Lucie Nuclear Plant Unit 2 that was submitted to the NRC by FPL via letter (L-2011-021) dated February 25, 2011 (Accession Number ML110730116).

In an email dated August 17, 2011 from NRC (Tracy Orf) to FPL (Chris Wasik),

Subject:

"St.

Lucie 2 EPU -- draft RAIs from Balance-of-Plant (SBPB)," the Balance-of-Plant Branch identified five questions as part of their review of the EPU LAR. The questions relate to: (1) loss of normal feedwater event; (2) auxiliary feedwater system motor-driven pump design; (3) spent fuel pool water temperature; (4) turbine missile evaluation methodology; and (5) transient testing of the feedwater system prior to EPU implementation. These five draft RAI questions and the FPL responses are documented below.

SBPB-1:

Appendix 10.4.9A, "Auxiliary Feedwater System Requirements Evaluation," to Amendment 19 of the St. Lucie Unit 2 Updated Final Safety Analysis Report (UFSAR),

describes that the analysis of the loss of main feedwater with offsite power available was the limiting event with respect to steam generator inventory. The loss of normal feedwater (LNF) analysis discussed in Section 2.5.4.5.2.4, "Results," of the license amendment request (LAR) supporting the extended power uprate (EPU) license amendment request states that the auxiliary feedwater (AFW) system is sized to remove the decay heat and pump heat associated with the event, based on an analysis at nominal plant conditions. However, the results do not directly address the assumptions used in the analysis, the AFW pump flow, and the minimum steam generator inventory determined by the analysis. In addition, the analysis notes that nominal parameter values were used in the analysis.

Provide the assumptions, boundary conditions, and results of the LNF accident analysis.

Include the assumed AFW pump flow, the steam generator pressure, the minimum steam generator water inventory, and the basis for concluding the minimum inventory would support continued removal of decay and pump heat. Explain how the use of nominal parameter values in the limiting accident analysis for steam generator inventory would satisfy the design control requirements of Appendix B to 10 CFR Part 50 for operation at EPU conditions.

Response

The Loss of Normal Feedwater (LNF) analysis described in Section 2.5.4.5 of the EPU LAR is not the licensing basis, Chapter 15 safety analysis. It is an auxiliary analysis performed to ensure that the Auxiliary Feedwater (AFW) system is sized sufficiently for the EPU. According to the St. Lucie Unit 2 UFSAR Section 10.4.9A, the AFW design bases are to ensure:

1. Sufficient capability exists for removal of decay heat from the reactor core.
2. The ability to reduce Reactor Coolant System (RCS) temperatures to entry temperatures for activating the shutdown cooling system.

L-2011-406 ATTACHMENT 1 Page 2 of 15

3. Prevent lifting of the pressurizer safety valves (PSVs) when considered in conjunction with the power operated relief valves (PORVs).

Item 1, above, is satisfied by assuring that the steam generators do not reach a dryout condition. As such, as long as inventory remains in the steam generators, the AFW system provides sufficient capability for decay heat removal. Item 2, above, is not explicitly analyzed in the LNF analysis, however, it is demonstrated that subcooling margin is maintained throughout the entire event and inventory remains in the steam generators. Item 3, above, is satisfied by assuring the maximum pressurizer pressure remains below the PSV opening setpoint.

In addition to these three requirements, an additional criterion is imposed on the LNF analysis.

Maximum pressurizer water volume must remain less than 1519 ft3, thus ensuring a water solid state is not reached and the accident does not propagate into a more severe event.

Consistent with the analyses performed in UFSAR Section 10.4.9A, the LNF AFW analysis performed for the EPU is a best estimate analysis with some parameters biased in the conservative direction. Thus, nominal initial parameters were considered. Cases with and without offsite power were considered. Table 1 illustrates the key analysis parameters for both offsite power available (LNF) and offsite power unavailable (LNF + LOOP).

Table 1: Key Analysis Parameters LNF LNF + LOOP Core Power 100% + Uncertainty 100% + Uncertainty (3030 MWt)

(3030 MWt)

Thermal Design Flow Thermal Design Flow (187500 gpm)

(187500 gpm) prior to coastdown Hi & Low nominal Hi & Low nominal RCS Temperature (578.5 & 563 °F)

(578.5 & 563 °F)

Initial Pressure Nominal (2250 psia)

Nominal (2250 psia)

Initial Water Level Nominal (63%)

Nominal (63%)

CharginglLetdown Available Unavailable Pressurizer Heaters Available Unavailable PORV Available Available Available (for conservatism in pressurizer fill)

Initial Water Level Nominal (65%)

Nominal (65%)

Tube Conditions &

Steam Steam Generator Fouled, 10%

Fouled, 10%

Generator Tube Plugging Atmospheric Dump Modeled to mimic steam bypass, Conservatively modeled to minimize SG inventory, SG Valves (ADVs)*

SG pressure controlled to 900 psia pressure controlled to 900 psia*

L-2011-406 ATTACHMENT 1 Page 3 of 15 Table 1: Key Analysis Parameters, continued LNF LNF + LOOP Pumps 2 Motor Driven AFW Pumps 2 Motor Driven AFW Pumps Flowrate 275 gpm per Motor Driven AFW 275 gpm per Motor Driven AFW Auxiliary Pump Pump Feedwater Delay 330 sec. 330 sec.

Setpoint Nominal - Uncertainty (13.0 %

Nominal - Uncertainty (13.0 %

Actuation Narrow Range Setpoint)

Narrow Range Setpoint)

Loss of Offsite Power Not Assumed Assumed on Reactor Trip Pressurizer Hi 2370 psia 2370 psia Reactor Trip Pressure Setpoint Low-Low SG Level Nominal - Uncertainty (14.5 %

Nominal - Uncertainty (14.5 %

Narrow Range Setpoint)

Narrow Range Setpoint)

Beginning of Cycle w/ maximum Beginning of Cycle wI maximum Reactivity value of delayed neutron value of delayed neutron fraction,

fraction, 1

Note that during a LOOP, the steam bypass system is unavailable. ADVs are still modeled in the LOOP case to conservatively minimize SG inventory during the event.

The LNF analysis performed in accordance with UFSAR Section 10.4.9A shows that greater than 10% of the initial steam generator mass exists in either generator at the end of the transient. The pressurizer water volume remains below 1519 ft3, and as such, the pressurizer does not reach a water solid condition. Pressurizer pressure, despite rising initially, remains below the PSV setpoint and the PSVs do not open during the event. Subcooling margin is maintained throughout the entire event.

The sequence of events for the limiting LNF case (offsite power available) is presented below along with the plots for the RCS temperature (Figure 1) and the SG water inventory (Figure 2).

The analysis has been run conservatively for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with no operator action.

Table 2: LNF with Offsite Power Available - Sequence of Events Time (sec)

Event SetpointlValue 0 - 20 Steady State Period 20.0 Loss of feedwater to both steam generators 57.8 Reactor trip signal on high pressurizer pressure 2370 psia 57.8 PORV Actuates 58.2 Reactor Trip 60.2 Turbine Trip*

63.7 Low steam generator level auxiliary feedwater actuation signal 13.0 % Narrow Range setpoint reached Setpoint 393.7 Auxiliary feedwater flow reaches the steam generators 275 gpm/SG 1162.5 Maximum pressurizer level 1512.2 ft3 1222.5 Minimum steam generator inventory 14,444 Ibm/SG 3620.0 Operator takes action to commence plant cooldown (1 hr from start of event)

Turbine Trip is not credited in the transient analysis.

L-2011-406 ATTACHMENT 1 Page 4 of 15 0-E U) 0 1000 2000 3000 Time (s)

Figure 1:

LNF With Offsite Power Available:

Hot and Cold Leg Temperature vs. Time 4000 E)

U) 0 UD UD E

0 Lo 140000 120000 100000 80000 60000 40000 20000 0 0 1000 2000 3000 Time (s) 4000 Figure 2:

LNF With Offsite Power Available: Steam Generator Mass vs. Time

L-2011-406 ATTACHMENT 1 Page 5 of 15 The Loss of Normal Feedwater (LNF) Chapter 15 safety analysis is described in Section 2.8.5.2.3 of the St. Lucie Unit 2 EPU licensing report. Section 2.8.5.2.3 indicates that the LNF accident analysis is not explicitly analyzed for the St. Lucie Unit 2 EPU.

The LNF event is classified as an Anticipated Operational Occurrence (AOO). An AOO has the following acceptance criteria:

Maximum pressure in the Reactor Coolant System (RCS) and Main Steam System (MSS) will be maintained below 110% of the design pressure.

The Specified Acceptable Fuel Design Limits (SAFDLs) are not exceeded, in particular the Departure from Nucleate Boiling Ratio (DNBR).

The event does not propagate to a more serious event. For the LNF event, long term cooling must be verified by demonstrating the pressurizer does not become water solid.

This ensures that a more limiting event is not generated.

With respect to RCS and MSS overpressurization criteria, the LNF event is bounded by the loss of condenser vacuum event. With respect to SAFDLs and core consequences for the Chapter 15 LNF safety analysis, the LNF event is bounded by the loss of forced reactor coolant flow event. With respect to the propagation to a more serious event, the LNF analysis performed for UFSAR Section 10.4.9A at EPU conditions demonstrates that a water solid condition does not result.

SBPB-2:

Table 10.4.1, "Component Design Parameters," of Amendment 19 of the St. Lucie Unit 2 UFSAR lists the motor driven AFW pump capacity as 300 gallons per minute (gpm),

including minimum recirculation flow of 50 gpm, at a pump head of 2660 feet [-1 150 psid]. However, the bases for TS 3/4.7.1.2, which were provided in Attachment 4 to the LAR, specify a delivered flow to the entrance of the steam generators of 320 gpm at 1000psia (MSSV setpoint) for each motor-driven pump. Reconcile these flow values considering the flow head loss at 320 gpm and the elevation difference between the pump discharge and the steam generator water surface. Provide the motor driven AFW pump performance curves and the results of full-flow inservice testing supporting the specified performance.

Response

The capacity of 300 gpm in Table 10.4-1 of the St. Lucie Unit 2 UFSAR is based on the original sizing for the AFW pumps as demonstrated by the manufacturer's pump curve. A St. Lucie calculation, which considers flow head loss and elevation head, demonstrates that using this curve, the motor driven AFW pumps are capable of supplying 320 gpm to the entrance of the steam generators at 1000 psia as stated in the Bases for Technical Specification (TS) 3/4.7.1.2.

The EPU accident analysis input for AFW flow is 275 gpm per motor driven pump to a steam generator at 1000 psia.

In-Service full flow performance testing for the motor-driven AFW pumps is provided in plant procedures. These procedures test the pumps at a flow of 246 gpm which, as required by the ASME OM Code, is within +/- 20% of the 300 gpm flow rate identified in UFSAR Table 10.4-1.

L-2011-406 ATTACHMENT 1 Page 6 of 15 The manufacturer's pump curve and the results of the latest full flow test for each pump are provided in Figures SBPB2-1 through SBPB2-3, respectively.

SBPB-3:

Section 9.1.3.3 of the St. Lucie 2 UFSAR states that, prior to commencing a full-core offload, an outage specific engineering evaluation will be preformed to evaluate the spent fuel pool (SFP) coolant temperature while assuming a cooling capacity equivalent to a single train of the SFP cooling system, and this evaluation will outline the need for contingency actions. Section 2.5.4.1.2 of the LAR supporting the EPU states the following for the scenario involving a full core offload with the failure of a fuel pool cooling train:

The maximum SFP bulk temperature rise (also called the thermal overshoot) that could result from a worst-case spent fuel pool cooling train failure has been determined to be 27°F for a full core fuel offload initiated 140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> after reactor shutdown. The procedural upper limit for the spent fuel pool temperature during a full core offload will be set so as to ensure the 1500F limit is not exceeded in the event of a failure of one fuel pool cooling train, after accounting for the maximum thermal overshoot.

Clarify how the procedural upper limit would ensure the pool temperature limit would not be exceeded, considering the committed heat load once the fuel is placed in the spent fuel pool and the large thermal inertia of the pool delaying the indicated temperature relative to peak pool temperature.

Response

The spent fuel pool (SFP) cooling analysis performed for EPU demonstrated that the maximum temperature rise (thermal overshoot) resulting from a worst-case analysis with one SFP cooling train failure is 270F under the following conditions:

A full core offload is present in the SFP, initiated at 140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> after reactor shutdown at an average of 7 assemblies per hour.

The component cooling water (CCW) temperature is 950F.

A failure of one train of SFP cooling occurs at the end of the full core offload.

Thermal overshoot is the temperature difference between the maximum SFP bulk temperature following the failure of one SFP cooling train and the SFP bulk temperature at the end of fuel transfer (time when last assembly is offloaded) when the failure of one train of SFP cooling is assumed to occur. Thethermal analysis performed subsequent to the failure of one train of SFP cooling used the same methodology as described in LR Section 2.5.4.1.2 and accounts for the thermal capacity of the pool in the calculation of the SFP bulk temperature as a function time.

Since the maximum thermal overshot for the worst case is 270F, the procedural upper limit for the SFP bulk temperature will be set less than 1230F, so that the maximum bulk temperature, with the failure of one train of cooling, will not exceed 150'F. This procedural upper limit of 123°F is considered acceptable to maintain SFP bulk temperature less than or equal to 150°F based on the following:

L-2011-406 ATTACHMENT 1 Page 7 of 15

1. The rise of SFP temperature of 27 0F is based on a conservative heat load corresponding to assemblies being offloaded at 7 assemblies per hour. Note that with a lower but still conservative offload rate of 5 assemblies per hour, the thermal overshoot reduces by more than 20F.
2. The SFP heat load assumes SFP being full with all EPU fuel, discharged in the SFP with conservative batch size and schedule, providing additional margin to the thermal overshoot.
3. The thermal overshoot of 270F accounts for the thermal capacity of the pool in the calculation of the maximum bulk temperature.

The indicated temperature is expected to be close to the bulk temperature for the following reasons:

1.

The SFP heat load is distributed in the SFP.

2.

With two trains of cooling in operation prior to the thermal overshoot calculation, there will be sufficient mixing in the SFP when considering the pool configuration with inlet and outlet being on opposite sides of the pool.

3.

With the SFP bulk temperature rise being on the order of -1

~F/hr, and taking into account the heat load distribution and coolant movement corresponding to 2 trains operating, the indicated temperature is expected to remain close to the bulk temperature.

Thus, maintaining the SFP temperature below 123°F with two cooling trains in operation, the SFP bulk temperature will not exceed 150°F even when considering the failure of one train of SFP cooling.

SBPB-4:

Section 3.5.1.3, "Turbine Missiles," of Amendment 19 of the St. Lucie Unit 2 UFSAR describes the plant licensing basis for turbine missile protection. The staff found the description reflected an assumed turbine missile generation frequency, calculated the probability that any of the missiles would damage a critical component, and compared the resulting frequency against an acceptance criterion frequency of I E-07 per year.

Sections 7.7 and 10.2 address design of the turbine control system and the turbine, but do not substantively address turbine missile protection. The discussion provided in Section 2.5.1.3 of the LAR described a different approach to turbine missile protection that is based solely on a calculated turbine missile generation frequency, and which referenced a topical report. Reconcile these different approaches to turbine missile protection. If the missile generation frequency is to be adopted consistent with the referenced topical report, provide the assumptions and results supporting the revised analytical method and address items listed in the staff topical report safety evaluation.

Response

Evaluation of turbine missiles has historically followed Regulatory Guide 1.115, "Protection Against Low-Trajectory Turbine Missiles", and Standard Review Plan (SRP) Section 3.5.1.3, "Turbine Missiles". These guidance documents are identified in the UFSAR as the regulatory basis for the existing turbine missile analysis presented in UFSAR Section 3.5.1.3. As specified in SRP Section 3.5.1.3, the probability of unacceptable damage from turbine missiles is expressed as the product of three probability terms: (P1) the probability of turbine missile generation resulting in the ejection of disk fragments through the turbine casing, (P2) the

L-2011-406 ATTACHMENT 1 Page 8 of 15 probability of ejected missiles perforating intervening barriers and striking safety related structures, systems or components (SSCs) and (P3) the probability of struck SSCs failing to perform their safety functions. An acceptance criterion frequency of 1 E-07 per year was specified. The turbine missile analysis presented in Section 3.5.1.3 of the PSL2 UFSAR reflects this approach. As discussed in Section 2.5.1.2 of the EPU LAR, the emphasis in turbine missile evaluation has shifted from the strike and damage probability terms P2 & P3, to the missile generation probability term P1. This shift in emphasis is also documented in the NRC Final Safety Evaluation (ML040930616) for Siemens Technical Report CT-27332, Revision 2 "Missile Probability Analysis for the Siemens 13.9 M2 Retrofit Design of Low-Pressure Turbine by Siemens AG". As further discussed in both of these source documents, a P1 probability term acceptance criterion of 1 E-5 per year has been established for unfavorably oriented turbines (i.e. where the turbine shaft orientation results in most safety related components being within the low trajectory hazard zone).

A turbine missile analysis was performed in support of EPU which reflects replacement of the low pressure (LP) turbine rotors with the Siemens BB281-13.9 m2 design. Its conclusions are similar to the existing analysis in that the probability of a disk failure with casing penetration is significantly below the NRC's limit value.

The analytical approach employed for the turbine missile analysis is in compliance with Siemens Westinghouse Topical Report TP-04124, "Missile Probability Analysis for the Siemens 13.9M2 Retrofit Design of Low-Pressure Turbine by Siemens AG." The NRC issued a Safety Evaluation Report to Siemens Westinghouse Power Corporation (SWPC) which addressed, in part, the ability to reference SWPC Technical Report CT-27332, Revision 2 in retrofit applications such as in the case of St. Lucie Unit 2. CT-27332, Revision 2 justifies external missile probabilities out to 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> in comparison to the NRC limit.

The Topical Report expresses the probability of an external missile (P1) emanating from the turbine-generator by conservatively evaluating two distinct types of LP shrunk-on disk failures, namely:

1. failure at normal operating speed up to 120% of the rated speed Pr and
2. failure due to run-away overspeed greater than 120% of rated speed Pofor all LP disks as follows:

Pi = Pr+ P. =

"Ni=l Pi2r

  • Pi3r + Pi0 Where:

P1 is the probability of an external missile, Pr is the probability of an external missile for speeds up to 120% of rated speed, Po is the probability of an external missile for speeds greater than 120% of rated speed, N, i is the total and current number of disks, P'2r is the probability of disk # i burst up to 120% of rated speed due to stress corrosion crack growth to critical size,

L-2011-406 ATTACHMENT 1 Page 9 of 15 P'3r is the probability of casing penetration given a burst of the disk # i up to 120% of rated

speed, Plo is the probability of a run-away overspeed incident (>120% of rated speed) due to a system separation initiation event followed by a failure of overspeed protection system.

The P0 term reduces to the Plo term based on the conservative assumptions in the analysis that the probability of disk failure and probability of casing penetration are both equal to 1.0 for speeds greater than 120%.

The derivation of this equation is presented in the Topical Report.

For the calculation of Pr, a Monte-Carlo simulation technique involving successive deterministic fracture mechanics calculations using randomly selected values of variables is used. As a failure condition, the brittle fracture mode is assumed. Selected random variables that are defined by finite element analysis are employed and a critical crack size is defined. Limits are based on the applicability limitation of linear-elastic fracture mechanics and do not represent an imminent burst condition. In the final summation 14 i=1 Prwas determined to be approximately two orders of magnitude below the NRC limit value for up to 100,000 operating hours between disk inspections providing that no cracks are detected in the discs.

Due to the conservative assumptions inherent in the turbine missile analysis methodology in the Siemens analysis, the calculation of disk failure probability and casing penetration (P 2r and P3r) is treated completely independently from the calculation of system separation probability and overspeed protection system failure probability (P10) as detailed in the Westinghouse Owners Group (WOG) analysis, WCAP-16501, "Extension of Turbine Valve Test Frequency Up to 6 Months for BB-296 Siemens Power Generation Turbines With Steam Chests, Rev.O".

Turbine speeds greater than 120% of rated speed can only be reached due to a total functional failure of the turbine overspeed protection system. As discussed in Section 2.5.1.2.2.2.2 of the EPU LAR, the larger inertia of the replacement LP rotors outweighed other EPU effects such that the net effect is a 1% decrease in expected maximum turbine speed during a loss of load event. Specifically, the expected change in the inertia of the rotor system will be approximately 47%. Also, the efficiency improvements due to the HP and LP upgrades and increase in thermal power will result in an increase in the power output of the turbine of approximately 14.9%. The increase in the amount of energy during the trip delays and valve closing as well as expansion of the entrapped steam will be higher at the EPU condition. However, this increase is more than offset by the increased inertia of the rotor train. Thus, the calculated overspeed will be approximately 1% lower than the original equipment. The calculated overspeed upon a breaker opening at full power EPU conditions is 114.7% based upon a trip setpoint of 111%.

P10 or the probability of a run-away overspeed incident (>120% of rated speed) is the product of the system separation probability and the overspeed protection system failure probability and it is based on Westinghouse Owners Group (WOG) analysis WCAP-16501. The existing overspeed protection system failure probability, Plo documented in WCAP-16501 remains bounding for the upgraded turbine control system to be installed as part of EPU at St. Lucie Unit

2. The modifications being made to enhance the reliability of the controls system, and thereby reduce the probability of reaching a run-away overspeed condition, are not being credited in the failure probability analysis. Since the P10 probability from WCAP-1 6501 is bounding for both the

L-2011-406 ATTACHMENT 1 Page 10 of 15 current and EPU turbine overspeed protection system St. Lucie designs, the existing 18 month fuel cycle conditional probability of destructive overspeed remains unchanged due to the power uprate. WCAP-16501 was prepared for a number of participating plants including St Lucie, North Anna, McGuire, Waterford, Shearon Harris, Farley, Byron and Braidwood. Some of the participating plants., including Byron Units 1 & 2, had previously upgraded their turbine control and turbine protection systems based on a Westinghouse Ovation design similar to the proposed new St Lucie Unit 2 Ovation design for EPU.

The design of the Ovation turbine control and protection system at St. Lucie Unit 2 includes two independent subsystems each with redundant processors. Each subsystem provides turbine overspeed protection in 2 out of 3 logic. Enhanced design features include: redundant and diverse speed probes, speed sensing modules that function independent of control processors, and a redundant and diverse Overspeed Protection Control (OPC) trip system at 103%

overspeed. The Ovation turbine control and protection system enhances control system reliability and thereby reduces the probability of reaching a run-away overspeed condition. Thus, continued usage of the existing overspeed protection system failure probability in the overspeed analysis is conservative.

Total probability of an external turbine missile (P1) for St. Lucie Unit 2 at 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> inspection interval is approximately 60 times less than the NRC limit value of 11.42 E-5 per 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> inspection interval. Therefore, it has been shown that the replacement Siemens rotors provided with a Westinghouse-provided Ovation control system continue to meet the current design analysis for missile protection under EPU conditions.

The NRC Final Safety Evaluation Report for Siemens Technical Report CT-27332, Revision 2 requires that the following items be addressed in any associated submittal:

a) State the approximate date for the turbine disk inspection at the end of 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of rotor operation.

Response

The St. Lucie Unit 2 replacement LP turbine rotors were placed in service at the conclusion of the SL2-19 outage (April, 2011). In accordance with the preventative maintenance (PM) program, the turbine disk inspection is scheduled to be performed once every 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of rotor operation. The first inspection will therefore occur around April, 2021.

b) Provide a commitment to inform the NRC about turbine disk inspection results and plans to reduce the probability of turbine missile generation, P1, for continued operation should cracks be detected in the inspection.

Response

FPL commits to inform the NRC about turbine disk inspection results and plans to reduce the probability of turbine missile generation, P1, for continued operation should cracks be detected in the inspection.

c) Provide justification for any additional turbine missile analyses, or minor deviations that may be plant specific.

L-2011-406 ATTACHMENT 1 Pagel 1 of 15

Response

Beyond the discussions provided above, there are no additional turbine missile analyses or plant specific deviations that require further justification.

SBPB-05:

The licensee indicated in Section 2.12 of the LAR that equipment modifications are being made to the feedwater system to support EPU conditions and that the feedwater system response would be monitored during power ascension. The licensee also stated that the transient response for the feedwater system during EPU conditions was modeled using the CENTS computer code. However, the staff is concerned that CENTS-modeled transient for the feedwater system may not reflect the actual transient response of the replacement feedwater pumps, along with its compatibility with the modified feedwater control system, during EPU conditions.

Discuss how the feedwater system will be assessed with actual transient testing prior to EPU implementation to confirm that the replacement feedwater pumps and feedwater control system will respond in a manner similar as the CENTS-modeled transient, or if actual transient testing will not be done, justify why it is not needed.

Response

EPU License Amendment Request (LAR), Attachment 5, Licensing Report Section 2.12.1.2.6, discusses the CENTS code model and its general application. LAR Section 2.12.1.2.7 includes the application of CENTS to load transients. The following discussion provides supplemental information regarding the CENTS modeling and the justification for why actual transient testing is not required, with emphasis on the feedwater (FW) system.

CENTS was benchmarked with operating data in order to refine the EPU model. The following St. Lucie transients were used in the benchmarking process:

Unit 2 manual reactor trip from 100% power on June 4, 2008 following a loss of a main FW pump, and Unit 2 manual reactor trip from 100% power on June 7, 2008 following a condensate pump trip.

In addition, Unit 1 and Unit 2 are very similar with respect to overall plant design and behavior of NSSS control systems. The above Unit 2 events were used in the benchmarking process for the Unit 1 CENTS model with excellent results. The Unit 1 CENTS model was also benchmarked against specific Unit 1 events, including non-trip operational transients.

Since the Unit 2 CENTS model is similar to the Unit 1 CENTS model, the Unit 1 CENTS benchmarking supports validation of the Unit 2 CENTS model. For benchmarking against each of the Unit 2 trip events and the Unit 1 non-trip operational events, short duration time interval data for a large number of key plant parameters was available for electronic comparison.

A CENTS model base deck was developed taking into account EPU conditions. The model was built to incorporate the applicable EPU equipment modifications and setpoint changes as well as the EPU operating conditions. The EPU FW modifications modeled in the CENTS transient analyses include the valve C, for the modified FW flow control valves, the pump curve for the new FW pumps, and the new FW control system settings. These modifications do not change the fundamental design and operation of the FW system. For the flow control valves, the valve

L-2011-406 ATTACHMENT 1 Page 12 of 15 trim is new, but the valve body is not replaced. For the new pumps, the motor is not replaced.

For the FW control system, Distributed Control System (DCS) software testing will include validation that the FW control system is correctly modeled in the CENTS code.

The agreement between the CENTS model results and the actual plant response during the benchmarking process, and the fact that the FW equipment systems have been appropriately incorporated in the CENTS model, provides confidence that CENTS cases adequately model plant response at EPU conditions.

The CENTS cases modeled the response to many parameters. LAR Table 2.12-4 lists the CENTS cases. Each case provided results for the following parameters: reactor power, reactor coolant system (RCS) temperatures, pressurizer pressure, pressurizer level, steam generator (SG) pressure, SG level, SG steam flow, SG FW flow, steam header pressure, main FW valve position, bypass FW valve position, FW pump pressures (suction and discharge), and FW temperature. Many of these parameters are related to the FW system, and the parameter responses demonstrated acceptable FW system response.

Although step change load transients are not planned, as discussed in LAR Section 2.12.1.2.7, FW system response is monitored during power ascension. The monitoring includes evolutions such as swap from FW bypass to the FW flow control valves, second condensate pump start, second FW pump start, closure of second FW pump recirculation valve, and heater drain (HD) pumps start. These evolutions are FW system transients even though reactor power and load are not expected to change.

L-2011-406 Page 13 of 15 I E"c"'. * ;:m

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Ž o-FIGURE SBPB2-1: Manfacturer's Pump Curve For AFW Pumps

L-2011-406 Page 14 of 15 REVISION NO.:

PROCEDURE TITr*-.

PAGE:

3..

2_..A AUXILIARY FEEDWATER PUMP REFUELING SHUTDOWN PUMP AND VALVE TEST 14of 14 PROCEDURE NO.:

2-OSP-09.02A ST. LUCIE UNIT 2 ATTACHMENT I 2A Auxiliary Feedwater Pump Comprehensive Flow Test (Page 1 of 1)

Date: -3/4 /

I Inlet Press Disch. Press Calculated Vibration Instr. NO.

-- ? _.

PI-12-18A PI-09-7A Pump Head Peak Velocity (in./sec.)

IPV IPH OPV OPH OPA (psig)

(psig) 2807

.6 13(o

.o0366

.03'22_

.,034*9'[

o3 {n4l Allowable Range 2645 to 2928

<0.086

<0.090

<0,081

<0,064

<0.107 Acetance I',.

~

~

~

c nteria Alert Range 2560 to <2645 0.086 to 0.208 0.090 to 0.217 0.081 to 0.195 0.064 to 0.'155 0.107 to 0.259 Required Action

<2560 or >2928

>0.208

>0.217

>0.195

>0.155

>0.259 II I

C. %.~UIL1 Fun I!j1aU InI k

nj~4, caIg reZ It~

UI "Ie IL sl W)~

    • Do not use the Vibration Probe Triaxial Mounting Block when measuring pump vibration.

(Section 8.1.3 Management Directive 1)

NOTE Any fime a pump is placed in an ALERT or ACTION status, Sys Performance Group is required to be notified immediately (call c for resolution of discrepancies and to coordinate the initiation of action.

The above data has been compared to the acceptance criteria and determined to be:

oceptable D Alert Range 0 Required Action Range tem

)ut if necessary) corrective Purpose of Test 0 Quarterly Code Run )< Post Maintenance (explain) 6'0t, other

.' e' 0

FIGURE SBPB2-2: AFW Pump 2A Test Results

L-2011-406 Page 15 of 15 RE"*VISI(N No:.*

'PROCE-DURE T'*I.,1 PAGE..:

3 28 AUXILIARY FEEDWATER PUMP REFUELING SHUTDOWN PUMP AND VALVE TEST 14-(if 1 4 PROC-EDU*RE NW, 2-OSP-09.02B ST. LUCIE UNIT 2 ATTACHMENT I 2B AUXILIARY FEEDWATER PUMP COMPREHENSIVE FLOWTEST (Page I of 1)

Inlet Press Disch. Press Calculated Vibra(ion Instr. No. k, L-P1.12-18B P1-09-7B Pump Head*

Peak VelocIt (inise.) "3 temp gauge temp gauge (f)IPH OPV OPH PA AIlowable Range.

2581 to 2857

<0.149

<0,141

<0.166

<0.119

  • t40 ACrerian Alert Range 2552 to <2581 0.149 to0.357' 0141 to 0.33B 0.166 to 0.399 0,119 to 0.285]

0/4i to 0.337l Required Action

<2552 or !2857

>0.357

>0.338

>0.399

>0.285

>0.337

,alcularen Prmp neac in Teei = tLiscnarge rressure - inIet rresSurwj A C.311.

Do not use the Vibration Probe Triaxial Mounting Block when measuring pump vibration..

(Section 8.1.3 Management Directive 1)

NOTE Any time a pump is placed in an ALERT or ACTION status, Syst Performance Group is required to be notified immediately (call (H for resolution of discrepancies and to coordinate the initiation of action.

I e above data has been compared-to the acceptance criteria and determined to be:

Acceptable 0 Alert Range 0 Required Action Range em t If necessary) orrectve Purpose of Test: 0.Quarterly Code Run'fPost Maintenance (~expl1iin).

E)t..~i!

other FIGURE SBPB2-3: AFW Pump 2B Test Results

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