W3F1-2004-0096, Supplement to Amendment Request NPF-38-249, Extended Power Uprate
| ML042940577 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 10/18/2004 |
| From: | Peters K Entergy Nuclear South, Entergy Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| W3F1-2004-0096 | |
| Download: ML042940577 (165) | |
Text
Entergy Nuclear South Entergy Operations, Inc.
17265 River Road Entergy Kilona, LA 70057 Tel 504 739 6440 Fax 504 739 6698 kpeters~entergy.com Ken Peters W3Fl-2004-0096 Director, Nuclear Safety Assurance Waterford 3 October 18, 2004 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555
SUBJECT:
Supplement to Amendment Request NPF-38-249, Extended Power Uprate Waterford Steam Electric Station, Unit 3 Docket No. 50-382 License No. NPF-38
REFERENCES:
- 1. Entergy Letter dated November 13, 2003, uLicense Amendment Request NPF-38-249 Extended Power Uprate"
- 2. Entergy Letter dated May 7, 2004, "Supplement to Amendment Request NPF-38-249, Extended Power Uprate"
- 3. Entergy Letter dated July 14, 2004, 'Supplement to Amendment Request NPF-38-249, Extended Power Uprate"
Dear Sir or Madam:
By letter (Reference 1), Entergy Operations, Inc. (Entergy) proposed a change to the Waterford Steam Electric Station, Unit 3 (Waterford 3) Operating License and Technical Specifications to increase the unit's rated thermal power level from 3441 megawatts thermal (MWt) to 3716 MWt.
On August 25, 2004, Entergy and members of your staff held a call to discuss the results of the analysis submitted in Reference 1 and the assumptions used for these analyses. As a result of the call, Entergy agreed to reanalyze the main steam line break return to power event with a revised assumption regarding fuel failures and also to provide an additional analysis of the loss of feedwater event that maximizes pressurizer level. Also, during the August 25, 2004, call, the staff requested additional assurance that the emergency operating procedures support the operator action time assumed in the analysis for securing charging flow.
The results for the reanalyzed main steam line break return to power event are provided in and supersede the results previously submitted in Section 2.13.1.3.1, "Steam System Piping Failures Post-Trip Analysis," of Attachment 5 in Reference 1. Additionally, Sections 2.13.1.3.3.2 and 2.13.1.3.3.5 have been revised to be consistent with the reanalyzed main steam line break return to power event. The revised sections are provided in and supersede the information previously submitted in these sections in of Reference 1.
The additional analysis of the loss of feedwater event that maximizes pressurizer level is provided in Attachment 2. A discussion regarding the emergency operating procedure and the operator action time is provided in Attachment 3.
401
W3Fl-2004-0096 Page 2 of 4 Subsequent to the August 25, 2004, call, Entergy identified that the steam generator tube rupture event analysis submitted in Reference 1 assumed that cooldown was achieved using only one of the two atmospheric dump valves when operating procedures specify the use of two atmospheric dump valves. This issue was entered into Entergy's 10 CFR 50 Appendix B corrective action program at Waterford 3. As a result, the steam generator tube rupture event was reanalyzed assuming both atmospheric dump valves were used during the cooldown.
The results of this reanalysis are provided in Attachment 4 and supersede the results submitted in Section 2.13.6.3.2, 'Steam Generator Tube Rupture," of Attachment 5 in Reference 1.
As a result of the steam generator tube rupture re-analysis, information provided in the response to Question 14 in Reference 2 has changed. That supplement provided the detailed calculation results for offsite doses in support of information contained in Reference 1. The revised information for steam generator tube rupture offsite dose superseding that previously provided in Reference 2 is:
2 Hour Duration EAB 2 Hour LPZ Duration Fuel Whole EAB Whole LPZ PUR Failure Body Thyroid Body Thyroid Event Section Limit (%) (rem) (rem) (rem) (rem)
Steam Generator Tube Rupture- GIS 2.13.6.3.2 0% 0.64 1.19 0.24 1.29 case (accident generated iodine spike )
Steam Generator Tube Rupture - PIS 2.13.6.3.2 0% 0.65 21.92 0.24 4.61 case (pre-existing iodine spike)
Reference 1 and Attachment 4 of this letter report consequences for these events meet the appropriate acceptance limits of the Standard Review Plan (NUREG-0800). As stated in Reference 1 and again in Attachment 4, this will become the new licensing basis for these events and be the dose information described in the Waterford 3 Final Safety Analysis Report.
Finally, Attachment 5 contains minor miscellaneous corrections that were not included in Section 2.13 of Attachment 5 (Power Uprate Report) of Reference 1. None of these corrections affect the Power Uprate Report conclusions and are being provided for completeness.
The no significant hazards consideration included in Reference 3 is not affected by any information contained in the supplemental letter. There are no new commitments contained in this letter.
W3Fl-2004-0096 Page 3 of 4 If you have any questions or require additional information, please contact D. Bryan Miller at 504-739-6692.
I declare under penalty of perjury that the foregoing is true and correct. Executed on October 18, 2004.
Sincerely, KJ ID tachments:
- 1. Revised Section 2.13.1.3.1, Steam System Piping Failures Post-Trip Analysis
- 2. Analysis of Loss of Feedwater Event that Maximizes Pressurizer Level
- 3. Emergency Operating Procedure and Operator Action Time to Secure Charging
- 4. Revised Section 2.13.6.3.2, Steam Generator Tube Rupture
- 5. Minor Miscellaneous Corrections to Section 2.13
- 6. Revised Sections 2.13.1.3.3.2, Purpose of Analysis and Acceptance Criteria and 2.13.1.3.3.5, Radiological Consequences
W3F1 -2004-0096 Page 4 of 4 cc: Dr. Bruce S. Mallett U. S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 NRC Senior Resident Inspector Waterford 3 P.O. Box 822 Killona, LA 70066-0751 U.S. Nuclear Regulatory Commission Attn: Mr. Nageswaran Kalyanam MS O-7D1 Washington, DC 20555-0001 Wise, Carter, Child & Caraway Attn: J. Smith P.O. Box 651 Jackson, MS 39205 Winston & Strawn Attn: N.S. Reynolds 1400 L Street, NW Washington, DC 20005-3502 Louisiana Department of Environmental Quality Office of Environmental Compliance Surveillance Division P. O. Box 4312 Baton Rouge, LA 70821-4312 American Nuclear Insurers Attn: Library Town Center Suite 300S 29h S. Main Street West Hartford, CT 06107-2445
Attachment I To W3FI-2004-0096 Revised Section 2.13.1.3.1, Steam System Piping Failures Post-Trip Analysis
2.13.1.3.1 Steam System Piping Failures Post-Trip Analysis The objective of the main steam line break (MSLB) with or without a concurrent LOOP event analysis is to document the impact of:
An increase in rated power to 3716 MWt A decrease in the LSGP trip and MSIS actuation setpoints A reduction in CEA worth at trip Transition to the CENTS transient simulation code Change in most negative MTC from -4.0x104 Ap/0F to -4.2x10 4 Ap/OF The return to power MSLB analysis is presented in FSAR Section 15.1.3.1.
2.13.1.3.1.1 General Description A MSLB is defined as a pipe break in the Main Steam Safety System (MSSS). The increased steam flow resulting from a pipe break in the MSSS causes an increased energy removal from the affected steam generator, which causes a decrease in the overall Reactor Coolant System (RCS) temperatures and RCS pressure. In the presence of a negative moderator temperature coefficient (MTC), the cooldown causes positive reactivity to be added to the core. A highly negative MTC in conjunction with a large break size (guillotine breaks) can combine to degrade shutdown margin and result in a potential post-trip return to power.
With a loss-of-offsite power (LOOP) concurrent with the break, reactor coolant pumps (RCPs) begin to coast down and certain Engineered Safety Features (ESF) Systems are actuated.
In all guillotine break cases, the low steam generator pressure initiates both a reactor trip and a main steam isolation signal (MSIS), which causes closure of the main steam isolation valves (MSIVs) and main feed isolation valves (MFIVs). The steam flow from the intact SG is terminated by the complete closure of the MSIVs. Since the pipe break is assumed to occur upstream of the MSIV, the steam flow from the affected SG is not terminated until the affected SG dries out. The large cooldown of the RCS results in the reduction of the RCS pressure, which will empty the pressurizer and initiate a safety injection actuation signal (SIAS). The emptying of the affected SG and the initiation of boron injection terminates the return to power and causes the core reactivity to decrease. The operator, via the appropriate emergency procedures, may initiate plant cooldown by manual control of ADVs anytime after reactor trip occurs. The plant is then cooled to the shutdown cooling temperature, at which time shutdown cooling can be initiated.
In the analysis of record (AOR), four MSLB events were chosen to maximize the potential for a post-trip return-to-power. The events were:
A guillotine break MSLB at hot-full power (HFP) with LOOP A guillotine break MSLB at HFP with offsite power available A guillotine break MSLB at hot-zero power (HZP) with LOOP
A guillotine break MSLB at HZP with offsite power available In addition, the above combinations were analyzed for both inside containment (IC) and outside containment (OC) break locations. The outside containment break locations are in general more benign with the blowdown flow being limited by the inline venturi flow restrictors.
2.13.1.3.1.2 Purpose of Analysis and Acceptance Criteria The purpose of the analysis is to determine that the radiological doses are within their respective limits and that a coolable geometry is maintained. This is accomplished by iterating on SCRAM worth to determine that which results in 2% fuel failure due to DNB SAFDL violation for the inside containment LOOP cases and no SAFDL violation for the inside containment no-LOOP cases. Limits on SCRAM are selected so that no SAFDL violation is predicted for any of the outside containment cases.
The criteria for the MSLB with and without LOOP events are the following:
Maintain a coolable geometry Radiological Doses < small fraction (10%) of 10CFR100 limits for an event generated iodine spike and no iodine spike, and
< 10CFR1 00 limits for a pre-existing iodine spike or fuel failure Control Room Doses < 5 rem whole body
< 75 rem skin
< 30 rem thyroid The MSLB with or without a concurrent LOOP event is described in Chapter 15.1.3.1 of the SAR (Reference 2.13-1).
2.13.1.3.1.3 Impact of Changes The increase in rated power maximizes the amount of energy that is removed by the broken steam line and the cooldown effect on the RCS temperature.
The LSGP trip and MSIS actuation setpoints were decreased due to lower operating SG pressures. This delays somewhat the action of the MSIVs in stopping steam flow from the unaffected SG.
The more negative MTC results in the addition of additional positive reactivity by MTC effects during the cooldown.
The impact of the above changes, along with the iterated SCRAM worth results in a small number of fuel pins predicted to experience DNB SAFDL violation for inside containment (IC) break location LOOP cases. No violation of SAFDLs occurs for inside containment no-LOOP cases or the outside containment (OC) break locations. The radiological doses remain less than the 10CFR100 limits.
2.13.1.3.1.4 Analysis Overview The methodology used in this analysis is the same as that used in the analysis of record.
This analysis utilized the CENTS computer code (Reference 2.13-2) for the transient analysis simulation. The minimum DNBR evaluation was determined using the HRISE code (Reference 2.13-10), which employed the MacBeth correlation. ROCS/HERMITE were used to assess reactivity feedback and core power distribution.
Input parameters for HFP and HZP from Tables 2.13.1.3.1-1 through 2.13.1.3.1-4 and the bounding physics data from Section 2.13.0.2 have been incorporated in this analysis with the following clarifications:
- A double-ended IC guillotine break (7.88 ft2) causes the greatest cooldown of the RCS and the most severe degradation of shutdown margin. Flow from the other SG was limited to the 3.14 ft2 area of the inline flow restrictors.
- A break inside or outside the containment building, upstream of the MSIVs causes a non-isolatable condition in the affected SG.
- A SIAS is actuated when the pressurizer pressure drops below 1560 psia. Time delays associated with the safety injection pump acceleration and valve opening are taken into account. An 18.5-second HPSI response time was assumed for the offsite power available case while a 30-second delay (conservatively greater than the 27 seconds to be specified in the Technical Requirements Manual
[TRM]) was assumed for the LOOP case. Additionally, the event was initiated from the highest pressure allowed by the Technical Specifications to delay the effect of the safety injection boron.
- The cooldown of the RCS is terminated when the affected steam generator blows dry. As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback decreases. The decrease in moderator reactivity combined with the negative reactivity inserted via boron injection cause the total reactivity to become more negative.
- CENTS is used to model the reactor coolant pump (RCP) coast down on a LOOP.
- Low SG pressure trip setpoint of 576 psia was assumed with a 0.9-second response time.
- MSIS is actuated on a LSGP setpoint of 576 psia. The MSIVs and Main Feedwater Isolation Valves (MFIVs) all receive an MSIS signal to close. A response time of 8.0 seconds was assumed for the MSIVs.
- The HERMITE code (Reference 2.13-4) was used to calculate the reactivity for the post-trip return to power portion of the analysis. This was done since the HERMITE code, which is a three-dimensional, coupled neutronics, open channel thermal hydraulics code, can more accurately model the effects of moderator temperature feedback on the power distribution and reactivity for the critical configuration existing during the return to power. The HERMITE results used in the Waterford 3 analysis were actually obtained from a parametric study performed for Calvert Cliffs Unit 1 Cycle 7. Waterford 3-specific ROCS
calculations were used to confirm the applicability of these parametric results to Waterford 3.
- Three-dimensional power distribution peaks (Fq) were determined with the ROCS and HERMITE evaluations mentioned above. Axial profiles consistent with these conservative power distribution peaks were utilized in the analysis.
- Reactor core thermal margin (DNBR) was simulated using the HRISE computer program, which employed the MacBeth critical heat flux (CHF) correlation and a 1.3 DNBR limit described in Reference 2.13-10. RCS conditions from CENTS (RCS temperature, pressure, flow, and power) are used in the HRISE thermal margin calculations.
- An EOC Doppler coefficients was assumed. This was based on the most negative fuel temperature coefficient (FTC). This FTC, in conjunction with the decreasing fuel temperatures, causes the greatest positive reactivity insertion during the steam line break event.
- The delayed neutron fraction assumed is the maximum value including uncertainties for EOC conditions (total delayed neutron fraction, A, 0.005662).
- A minimum initial RCS flow of 148,000,000 Ibm/hr was assumed.
- A maximum initial RCS temperature results in the greatest increase in density of the coolant during the event. This maximizes the positive reactivity added by the moderator. The analytical value of 5520 F was used in this analysis.
The conservative assumptions included in the HZP and HFP simulations are discussed below.
The post trip steam line break analysis done for power uprate is performed with a combination of reactivity parameters that are expected to bound cycle specific core design parameters. A review of these parameters is done for every fuel cycle Reload Analysis to ensure the analysis of record remains bounding. Acceptable results can still be obtained if one cycle specific parameter (for example MTC) is non-conservative relative to the analysis of record, provided that other cycle specific parameters (for example SCRAM worth) are adequately conservative to compensate for any non-conservative parameter. The Reload Analysis process automatically performs this assessment to ensure the acceptability of the cycle specific reactivity behavior.
A negative MTC results in the greatest positive reactivity addition during the RCS cooldown caused by the steam line break. Since the coefficient of reactivity associated with moderator feedback varies significantly over the range of moderator density covered in the analysis, a curve of reactivity insertion versus moderator density rather than a single value of MTC is assumed in the analysis. A typical moderator cooldown curve is seen in Figure 2.13-1 and includes the direct change in moderation as well as variation in the worth of the tripped CEAs as moderator density changes. It was conservatively calculated assuming'that on reactor trip, the highest worth control element assembly is stuck in the fully withdrawn position. The effect of uneven temperature distribution on the moderator reactivity is accounted .for by assuming that the moderator reactivity is a function of the lowest cold leg temperature. Each cycle, the reload assessment process generates the appropriate cooldown curve.
For conservatism, the full steam generator heat transfer surface area is assumed to always be covered by the 2-phase level until a steam generator becomes essentially empty.
Due to differences in the magnitudes of reactivity feedback mechanisms, the rates of heat removal associated with different break areas and LOOP assumptions, the minimum acceptable SCRAM worth would be different for each of the eight RTP steamline break (SLB) scenarios examined. Restrictions will be incorporated in future reload core designs to ensure that the most limiting of the requirements are verified for actual power uprate core designs.
The HFP cases assume that feedwater delivery to the affected SG reached the capacity of the Main Feedwater (MFW) System until the MFIVs act to terminate MFW delivery.
2.13.1.3.1.5 Radiological Consequences Based upon the required scram worths, the maximum fuel failure for the inside containment LOOP RTP MSLB is 2% via the mechanism of DNB SAFDL violation. No fuel failure is allowed for the inside containment no-LOOP cases or for the outside containment RTP main steamline break (MSLB). Similar limited fuel failure during the RTP SLB has been licensed for Calvert Cliffs and St Lucie 2. The radiological consequences and fuel failure limits of the RTP SLB scenario are combined with those of the pre-trip SLB scenario. Refer to Section 2.13.1.3.3.5 for the discussion.
2.13.1.3.1.6 Analysis Results The results of all four of the inside containment RTP SLB scenarios are presented. The input assumptions for the HFP, LOOP case, the HFP no-LOOP case, the HPP LOOP case and the HZP no-LOOP case are seen in Tables 2.13.1.3.1-1 through 2.13.1.3.1-4, respectively.
The sequences of events for the scenarios are seen in Tables 2.13.1.3.1-5 through 2.13.1.3.1-8. Figures 2.13.1.3.1-1 though 2.13.1.3.1-13 present the transient response of key parameters for the HFP LOOP case. The same parameters are plotted in Figures 2.13.1.3.1-14 through 2.13.1.3.1-25 for the HFP no-LOOP case, in Figures 2.13.1.3.1-26 through 2.13.1.3.1-38 for the HZP LOOP case and in Figures 2.13.1.3.1-39 through 2.13.1.3.1-50 for the HZP no-LOOP case.
It is seen that the response for the power uprate is slightly more adverse than the current power level. A limited extent of SAFDL violation is seen to occur for these inside containment steam line breaks.
Table 2.13.1.3.1-1 HFP, LOOP Assumption Table Power Uprate Current Power Parameter Assumption Level Assumption Initial Core Power, MWt 3716 3478 Core Inlet Coolant Temperature, OF 552 560 RCS Flowrate, X10 6 Ibm\hr 148.0 148.0 Pressurizer Pressure, psia 2310 2300 Pressurizer Level, % 21 SG Pressure, psia 867 969 SG Level, % NR 90 -
Doppler Coefficient Multiplier 1.15 1.15 SBCS Inoperative Inoperative PPCS Automatic Automatic High Pressure Safety Injection Pumps 1 pump inoperative 1 pump inoperative Blowdown Fluid 100% steam 100% steam Break Area, ft2 7.88 7.88 Core Burnup End of Cycle End of Cycle
Table 2.13.1.3.1-2 HFP, no-LOOP Assumption Table Parameter Power Uprate Current Power Level Assumption Assumption Initial Core Power, MWt 3716 3478 Core Inlet Coolant Temperature, OF 552 560 RCS Flowrate, x106 Ibm/hr 148.0 148.0 Pressurizer Pressure, psia 2310 2300 Pressurizer Level, % 21 SG Pressure, psia 867 969 SG Level, % NR 90 Doppler Coefficient Multiplier 1.15 1.15 SBCS Inoperative Inoperative PPCS Automatic Automatic High Pressure Safety Injection Pumps 1 pump inoperative 1 pump inoperative Blowdown Fluid 100% Steam 100% Steam Break Area, ft2 7.88 7.88 Core Burnup End of Cycle End of Cycle
Table 2.13.1.3.1-3 HZP, LOOP Assumption Table Power Uprate Current Power Parameter Assumption Level Assumption Initial Core Power, MWt 37.16 34.78 Core Inlet Coolant Temperature, OF 552 551 RCS Flowrate, x10 6 Ibm/hr 148.0 148.0 Pressurizer Pressure, psia 2310 2300 Pressurizer Level, % 21 --
SG Pressure, psia 1054 1044 SG Level, % NR 90 Doppler Coefficient Multiplier 1.15 1.15 SBCS Inoperative Inoperative PPCS Automatic Automatic High Pressure Safety Injection Pumps 1 pump inoperative 1 pump inoperative Blowdown Fluid 100% steam 100% steam Break Area, ft2 7.88 7.88 Core Burnup End of Cycle End of Cycle
Table 2.13.1.3.1-4 HZP, no-LOOP Assumption Table Parameter Power Uprate Current Power Level Assumption Assumption Initial Core Power, MWt 37.16 34.78 Core Inlet Coolant Temperature, OF 552 551 RCS Flowrate, x106 Ibm/hr 148.0 148.0 Pressurizer Pressure, psia 2310 2300 Pressurizer Level, % 21 SG Pressure, psia 1054 1044 SG Level, % NR 90 Doppler Coefficient Multiplier 1.15 1.15 SBCS Inoperative Inoperative PPCS Automatic Automatic High Pressure Safety Injection Pumps I pump inoperative 1 pump inoperative Blowdown Fluid 100% Steam 100% Steam Break Area, ft2 7.88 7.88 Core Burnup End of Cycle End of Cycle
Table 2.13.1.3.1-5 HFP, LOOP, Inside Containment Sequence of Events Current Current Power EPU Time Power Level EPU Level (sec) Time (sec) Event SetpointValue SetpointlValue 0.0 0.0 Steam line break upstream 7.88 ft2 7.88 ft2 of MSIV, loss of power to RCPs 1.9 1.7 LSGP trip and MSIS 576 psia 675 psia setpoint reached 2.8 2.6 Trip breakers open _
2.8 2.6 MSIVs begin to close _
3.4 3.2 Shutdown CEAs begin dropping into the core 11.4 - MSIVs closed _
19.4 12.6 MFIVs closed ---
44.2 15.8 Pressurizer empties 50.4 19.8 Low RCS pressure initiates 1560 psia 1560 psia SIAS 69.5 --- Minimum pressurizer 873.3 pressure, psia 80.4 49.8 HPSI pump reaches full speed 153.2 142.3 Maximum post-trip fission 6.1% of 3716 5.2% of 3410 power MWt MWt 169.3 152.3 Minimum post-trip 1.03 >1.30 MacBeth DNBR 183.8 143.5 Maximum post-trip +.006%Ap -.056%Ap reactivity 269.0 112.7 Affected SG empties ---
1800 1800 Plant cooldown initiated by manual control of the ADV associated with the intact SG 28,800 SDC initiated
Table 2.13.1.3.1-6 HFP, no LOOP, Inside Containment Sequence of Events Power Current Event Power Uprate Current Power Uprate Time Power Level Setpoint I Value Level Setpoint I (sec) Time (sec) Value 0.0 0.0 Steam Line Break 7.88 ft2 7.88 ft2 Upstream of main Steam Isolation Valve, Loss of Power to Reactor Coolant Pumps 1.9 1.7 Low Steam 576 psia 675 psia Generator Pressure Trip and MSIS Setpoint Reached 2.8 2.6 Trip Breakers Open --- -
2.8 2.6 MSIVs Begin to Close 3.4 3.2 Shutdown CEAs --- -
Begin Dropping into the Core 11.0 12.6 MSIVs Closed --- ---
13.6 15.8 Pressurizer Empties -- -
14.7 18.2 Low RCS Pressure Initiates 1560 psia 1560 psia SIAS 33.2 36.7 High Pressure Safety Injection Pump Reaches Full Speed 69.8 72.8 Maximum Post Trip Fission 6.4% of 3716 MWt 5.6% of 3410 Power MWt 69.8 72.8 Maximum Post Trip LHGR 22.8 20.7 101.6 74.4 Affected Steam Generator --- ---
Empties 103.4 74.4 Maximum Post Trip -.147%Ap -.318%Ap Reactivity 1800.0 1800.0 Plant Cooldown Initiated by --- ---
Manual Control of the Atmospheric Dump Valve Associated with the Intact Steam Generator
Table 2.13.1.3.1-7 HZP, LOOP, Inside Containment Sequence of Events Current Current Power EPU Time Power Level EPU Level (sec) Time (sec) Event SetpointlValue SetpointlValue 0.0 0.0 Steam line break upstream 7.88 ft2 7.88 ft2 of MSIV, loss of power to RCPs 3.2 2.2 LSGP trip and MSIS 576 psia 675 psia setpoint reached 4.1 3.1 Trip breakers open ---
4.7 3.7 Shutdown CEAs begin dropping into the core 11.6 - Pressurizer empties --- --
12.2 11.6 Low RCS pressure initiates 1560 psia 1560 psia SIAS 12.2 13.1 MSIVs closed --- --
19.8 --- MFIVs closed _
40.0 94.5 Maximum post-trip +0.19%Ap +0.19%Ap reactivity 42.2 41.6 HPSI pump reaches full speed 123.6 --- Minimum RCS pressure, 580.1 psia 226.1 229.6 Maximum post-trip fission 4.4% of 3716 4.2% of 3478 power MWt MWt 228.0 249.4 Minimum post-trip DNBR 1.18 >1.30
>600 311.4 Affected SG empties _ _---
1800 1800 Plant cooldown initiated by _
manual control of the ADV associated with the intact SG 28,800 --- SDC initiated ---
Table 2.13.1.3.1-8 HZP, no LOOP, Inside Containment Sequence of Events Power Current Event Power Uprate Current Power Uprate Time Power Level Setpoint / Value Level Setpoint/
(sec) Time (sec) Value 0.0 0.0 Steam Line Break Upstream ---
of main Steam Isolation Valve, Loss of Power to Reactor Coolant Pumps 3.2 2.2 Low Steam Generator 576 psia 675 psia Pressure Trip and MSIS Setpoint Reached 4.1 3.1 Trip Breakers Open --- ---
4.7 3.7 Shutdown CEAs Begin --- ---
Dropping into the Core 11.3 10.6 Low RCS Pressure Initiates 1560 psia 1560 psia SIAS 12.2 13.1 MSIVs Closed 46.3 88.5 Maximum Post Trip +0.2004%Ap +0.187%Ap Reactivity 29.8 29.1 High Pressure Safety --- ---
Injection Pump Reaches Full Speed 228.2 145.7 Maximum Post Trip Fission 5.7% of 3716 MWt 5.9% of 3478 Power MWt 228.2 145.7 Maximum Post-Trip LHGR 20.6 20.6 396.7 143.7 Affected Steam Generator --- ---
Empties 1800.0 1800.0 Plant Cooldown Initiated by --- ---
Manual Control of the Atmospheric Dump Valve Associated with the Intact Steam Generator
120 100 -
CU80 -
0 I- 6 60 200 00 0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-1 Inside Containment, HFP SLB with LOOP Core Power vs. Time
120 100 -
- 080-860 -
040 -
00 2 -
0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-2 Inside Containment, HFP SLB with LOOP Core Heat Flux vs. Time
2500 2000 CL d 1500 us to a-N
.r-M 1000 0A V1) 02 500 0
0 100 200 300 400 lime, Seconds Figure 2.13.1.3.1-3 Inside Containment, HFP SLB with LOOP Pressurizer Pressure vs. Time
650 550--
CL) 250 E
U, CL) 250 I 0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-4 Inside Containment, HFP SLB with LOOP RCS Temperatures vs. Time
1200 1000 800 CLa-6 (n
to 0) 0~ 600 I-a)
(i 0)
E cu 400 CD, 200 0
0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-5 Inside Containment, HFP SLB with LOOP SG Pressure vs. Time
0.06 0.04 -
0.02 - Dopple 0
o-0 0
z 1 3-D Feedback
-0.02 - Total
-0.04 -
-0.06 0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-6 Inside Containment, HFP SLB with LOOP Reactivity vs. Time
10 9
8 7
11 6
0) a)
5 N
en CL co a-0, 4D-3-
2-1-
0 -
0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-7 Inside Containment, HFP SLB with LOOP Pressurizer Level vs. Time
14000 12000 10000 a)
U, E 8000 -
-o
-i 0
a-6000 E
a) n/)
4000 2000 0
0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-8 Inside Containment, HFP SLB with LOOP Steam Flow vs. Time
4000 3500 -
Affected SG 3000 -
0 a)
U) 2500 -
E Unaffected
-0 0
U- 2000 -
500 -
0 0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-9 Inside Containment, HFP SLB with LOOP Feedwater Flow vs. Time
200000-180000 -
160000- Unaffected
,, 140000 -
E c5 U,
120000 -
CU
° 100000 -
Affected (D 80000 -
E so 60000 -
40000 -
20000 -
0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-10 Inside Containment, HFP SLB with LOOP SG Mass vs. Time
18000 16000 -
14000 -
g 12000 -
-J j- 10000 -
0
._ 8000-C/
m1)
C/o 6000-4000 -
2000 0
0 100 200 300 400 lime, Seconds Figure 2.13.1.3.1-11 Inside Containment, HFP SLB with LOOP Integrated Safety Injection Flow vs. Time
9 8-7-
- 6 0) a-0 0 100 200 300 400 Time, Seconds Figure 2.13.1.3.1-12 Inside Containment, HFP SLB with LOOP Reactor Vessel Level vs. Time
3 2.5 -
2-z 0
-.S a) 1.5 -
ime, Seconds Figure 2.13.1.3.1-13 Inside Containment, HFP SLB with LOOP DNBR vs. Time
1.4 1.2 1
CD qO 0.8-C 0
O LL W 06 0D 0) 0.4 0.2 0
0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-14 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Core Power vs. Time
1.2 CE 0.8 CO 0
,o
, 0.6 LI.
U-CD aD 0.4 0
0.2 -
0 50 100 150 200 Tirne, Seconds Figure 2.13.1.3.1-15 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Core Heat Flux vs. Time
2500 2000 CO, 0a ai 1500 a) aL.
a)
U) 1000 ER)
I .
a.
500 0
0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-16 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Pressurizer Pressure vs. Time
650 600 -
550 -
LL 50)
Enaffeted Hot Leg Adffeted Cold Legg E 450 -UnfetdClLg I-(1) 400 -
350 -
AffectedClLe 300~
0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-17 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Reactor Coolant System Temperatures vs. Time
1000 900 800 lUnaffected SG V5 700 2600\
500 C:
0) o 400~
E 200 Affected SG 100 0
0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-18 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Steam Generator Pressure vs. Time
0.08 0.06 0.04 -
0.02 Doppler
-i0.02-
-0.06 - Scram
-0.08 -
0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-19 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Reactivity vs. Time
14 12 10 LR-ai)6 a.
4-2 0
0 50 100 150 200 Tirne, Seconds Figure 2.13.1.3.1-20 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Pressurizer Level vs. Time
14000 12000 -
10000 -
0 U,
a)
CL 8000 C,,
E
. 6000.
LL E
co 4000\
2000 Affected SG 0-_ Unaffected Sg 0-0 50 100 150 200 Time, Seconds Figure 2.13.1.3.1-21 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Steam Flow vs. Time
4000 3500 -
Affected Sg 3000 -
t, 2500 U- Unaffected Sg
-J 0 2000 -
I-a)
- 0 a) 1500 1 LL 1000 I 500 '
0+
0 50 100 150 200 Tirne, Seconds Figure 2.13.1.3.1-22 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Feedwater Flow vs. Time
200000 180000-160000 -
140000
-D cii 120000 (n
°C 100000 U,
e)
O 80000-E CU co \
60000 -
Affected SG 40000 20000 0
0 50 100 150 20C 1ine, Seconds Figure 2.13.1.3.1-23 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Steam Generator Mass vs. Time
70000 60000 50000 3 40000-0 LL X 30000-a,/
20000 -
10000 -
0-0 50 100 150 200 Timre, Seconds Figure 2.13.1.3.1-24 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Integrated Safety Injection Flow vs. Time
9 7.
6-
>, 5-T S F 2 .
I 3.
2 0
0 50 100 150 200 Tirme,Seconds Figure 2.13.1.3.1-25 Return-to-power Steam Line Break Hot Full Power, No Loss of Offsite Power Reactor Vessel Upper Head Level vs. Time
25 20 a1) 4W15-0 C
a) a)
a-01) 0 a_ 10 -
a)
I.-
0 5 -
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-26 Inside Containment, HZP SLB with LOOP Core Power vs. Time
25 20 -
r 15 0
4-.
lo L 10 -
5 0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-27 Inside Containment, HZP SLB with LOOP Core Heat Flux vs. Time
2500 2000 1500 I-(n (n
L a)
N 1000 U,
0n C.
500 0
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-28 Inside Containment, HZP SLB with LOOP Pressurizer Pressure vs. Time
600 500 Tete U Affected S 2) 2 400 300 -
ET 300 -
200 -1 0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-29 Inside Containment, HZP SLB with LOOP RCS Temperature vs. Time
1200 1000 800-E-
600-C:
1)
E
- 400-200 -
\ Affected SG 0 100 200 300 40C) 500 600 lime, Seconds Figure 2.13.1.3.1-30 Inside Containment, HZP SLB with LOOP SG Pressure vs. Time
0.05 0.04 -
0.03 -
0.02 -
0 0.01 - Doppler 0
-0.01 - 3-D Feedback
-0.02 - Boron
-0.03 -
-0.04 -
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-31 Inside Containment, HZP SLB with LOOP Reactivity vs. Time
10 9-8-
7-5.
N (O 4-3 2-1-
0~
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-32 Inside Containment, HZP SLB with LOOP Pressurizer Level vs. Time
20000 18000 16000 14000 L)
(n 12000 E
-J 10000 0
LL E
CU a) 8000
.-6.
C,)
6000 4000 2000 0
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-33 Inside Containment, HZP SLB with LOOP Steam Flow vs. Time
4000 3500 -
Affected SG 3000 -
n a) 2500 -
-a
-J (IL 0
2000 - Unaffected SG S.-
a)
CU a) 1500 -
a)~
1000 -
500-0 0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-34 Inside Containment, HZP SLB with LOOP Feedwater Flow vs. Time
350000 300000 -
Unaffected SG 250000 -
E
_ 200000-CU (D150000 -
15000Affected SG (9
E CU u" 100000 -
50000 -
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-35 Inside Containment, HZP SLB with LOOP SG Mass vs. Time
60000 -
50000 -
E 40000-
-J 0
0o 30000 C.,
4 20000 -
10000 -
0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-36 Inside Containment, HZP SLB with LOOP Integrated Safety Injection Flow vs. Time
9 8
7-46-0 U ~5-CL 0.
2-0, 0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-37 Inside Containment, HZP SLB with LOOP Reactor Vessel Level vs. Time
4 3-0o z
0
,=#,2 -
a) 1-0 100 200 300 400 500 600 Time, Seconds Figure 2.13.1.3.1-38 Inside Containment, HZP SLB with LOOP DNBR vs. Time
1 0.9 -
0.8 -
0.7 (0
I 0.6-0 C
0 304--
LL 3: 0.4 0
a.
0 O) 0.3 0.2 0.1 0-0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-39 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Core Power vs. Time
0.9 0.8 007 co N-CO) 0.64 0
0 0.5 LL Ia)
LL04
- 0.4-0.2 0.1 0
0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-40 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Core Heat Flux vs. Time
2500 2000l 1500
,,1000 -
0.
500 0 50 100 150 200 250 300 350 400 m me,Seconds Figure 2.13.1.3.1-41 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Pressurizer Pressure vs. Time
600 550 -.
500 X LL cm co ColdUnAffectedLoopoT E
400 -
350 Afete Cldo Unfece Loop=
30-T Hot Afcted loop T Cold AffectedLo 0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-42 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Reactor Coolant System Temperatures vs. Time
1200 1000 a- 800-ci) in co E 400 0) 200 -
6UAffected SG 0 50 100 150 200 2'50 300 350 400 Time, Seconds Figure 2.13.1.3.1-43 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Steam Generator Pressure vs. Time
0.06 Moderator 0.04 -
0.02-0
-0)0
-0.04 -
-0.06 0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-44 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Reactivity vs. Time
10 9
8 7
LL 6
-jI a) 5 N
U, (n
() 4 (L
3-2-
1-0 . I 0 50 100 150 200 2'50 300 350 400 lime, Seconds Figure 2.13.1.3.1-45 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Pressurizer Level vs. Time
18000 -
16000 -
14000 -
> 12000 -
Cl)
D 10000 -
0 LL 8000 E
a, U) 6000 -
4000 -
2000 -
Affected SG 0 - Unaffected S 0 100 200 300 400 500 Time, Secor ids Figure 2.13.1.3.1-46 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Steam Flow vs. Time
4000 3500 -
Affected SG 3000 -
0 a)
()
2500 -
E 7
-I 0
U-2000 -
U.-
a)
Unaffected SG 1500 -
a)
U-1000 -
500 -
0 -
0 100 200 300 400 500 Time, Seconds Figure 2.13.1.3.1-47 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Feedwater Flow vs. Time
350000 300000 250000 E
.0
-J U,
U, 200000 Cn 0) a) 150000 C) 100000 50000 0
0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-48 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Steam Generator Mass vs. Time
100000 90000 80000 70000 E
.0
- 60000 3o 0
LL fi C,
50000 a)
D- 40000 CU to 30000 20000 10000 0
0 50 100 150 200 250 300 350 400 Time, Seconds Figure 2.13.1.3.1-49 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Integrated Safety Injection Flow vs. Time
9 8
7 U-a) 0)
o,4- /
0) a, 3-2-
0*
0 50 100 150 200 25 0 300 350 400 lime, Seconds Figure 2.13.1.3.1-50 Return-to-power Steam Line Break Hot Zero Power, No Loss of Offsite Power Reactor Vessel Upper Head Level vs. Time
Attachment 2 To W3FI-2004-0096 Analysis of Loss of Feedwater Event that Maximizes Pressurizer Level
Purpose of Analysis During the review of the Waterford-3 3716 MWt extended power uprate report, the Reactor Systems Branch asked for a confirmatory demonstration that the pressurizer will not become totally filled with liquid following a loss of feedwater plus a single failure. This report presents the results of the requested analysis and demonstrates that adequate time exists for the operators to identify conditions which are leading to a solid system and take compensatory actions. Two potential active failures are considered: Failure of the Pressurizer Level Control System (PLCS), and Reduction of the Emergency Feedwater Flow (EFW).
Cases Analyzed Case 1: Loss of Feedwater with PLCS failure, long-term, 1800 sec run The loss of feedwater plus the single failure of the pressurizer level control system (PLCS) was the first scenario to be examined. The failure in the PLCS is assumed to result in termination of letdown flow and starting all charging pumps. This first set of results determines the time at which the system would become solid with no operator intervention and determines the timing when discharge of liquid through the pressurizer safety valves begins.
Results of Case 1 show that operator action is required no earlier than 15 minutes after reactor trip, in order to prevent discharge of liquid through the pressurizer safety valves.
Major assumptions for this case are presented in Table 1-1. Sequence of events is presented in Table 1-2, and figures are presented in Figure 1-1 through Figure 1-13.
Case 2: Loss of Feedwater with PLCS failure, long-term, operator action 15 min after reactor trip, 1800 sec run Case 2 is the same as Case 1 but with operator action being modeled to occur at 15 minutes. The operator action consists of tripping 2 out of 3 charging pumps and reestablishing letdown flow. Results of Case 2 show that that with operator action at this time, significant margin exists to a solid pressurizer condition.
Major assumptions for this case are presented in Table 2-1. Sequence of events is presented in Table 2-2, and figures are presented in Figure 2-1 through Figure 2-13.
Case 3: Loss of Feedwater with Reduced EFW flow, long-term, 1800 sec run The other scenario examined is a single active failure in the emergency feedwater system.
This failure results in a minimum EFW flow of 575 gpm being delivered to the steam generators. Examining the results, it is seen that this scenario does not result in the discharge of liquid through the pressurizer safety valves or pressurizer fill.
Major assumptions for this case are presented in Table 3-1. Sequence of events is presented in Table 3-2, and figures are presented in Figure 3-1 through Figure 3-13.
Analysis Overview This evaluation examined the analysis of the loss of feedwater analysis documented in the Power
Uprate Report (PUR) with the following input differences (to exacerbate the potential for pressurizer fill):
- 1. Most positive (least negative) MTC of 0.5x104 Ap.
- 2. A PSV tolerance of -3% was applied.
- 3. An MSSV tolerance of +3% was applied.
- 4. Main Steam Isolation Signal (MSIS) setpoint of 725 psia was used. However, it was not initiated, since secondary safety valves were cycling, and SG pressure did not drop below this setpoint.
Analysis Results The LOFW with an active failure in the PLCS event does not result in pressurizer overfill, since operators take action in 15 minutes after reactor trip, tripping 2 out of 3 charging pumps and initiating letdown flow.
The NSSS, PPS, and EFW system responses for the LOFW with PLCS failure event are shown in Table 1-2 and Figures 1-1 through 1.-13.
The NSSS, PPS, and EFW system responses for the LOFW with PLCS failure and operator action in 15 minutes after trip event are shown in Table 2-2 and Figures 2-1 through 2-13.
The LOFW with reduced EFW flow event does not result in pressurizer overfill. The NSSS, PPS, and EFW system responses for this event are shown in Table 3-2 and Figures 3-1 through 3-13.
Table 1-1 Assumptions for 1800 seconds Long-Term LOFW with PLCS Failure Event (Case 1)
Parameter Power Uprate Assumption Initial Core Power level, MWt 3735 Core Inlet Temperature, OF 533 RCS Flowrate, 10' Ibm/hr 148 Pressurizer Pressure, psia 2090 Pressurizer Level, % 67.5 SG Pressure, psia 742 SG Level, %NR 90 MTC,I 0'Ap/oF 0.5 Doppler Coefficient Multiplier 0.85 CEA Worth for Trip, 10 2Ap -6 SBCS Inoperative PLCS Manual PPCS Automatic Single Failure PLCS: maximum charging flow and zero letdown flow Operator Action None
Table 1-2. Sequence of Events for 1800 seconds Long-Term LOFW with PLCS Failure Event (Case 1)
Time Event Setpoint or value (sec) 0.0 Termination of all feedwater flow 0.0 PLCS failure:
Maximum charging flow 144 gpm Minimum letdown flow 0 gpm 32.1 Low steam generator water level trip signal 5% NR 33.0 Trip breakers open 33.6 CEAs begin to drop into core 33.6 Maximum core power (% of 3716 MWt) 101.3%
48.3 Steam generator safety valves open 1117 psia 49.8 Maximum steam generator pressure 1118.6 psia 82.5 Emergency feedwater reaches steam generators 360.4 Minimum steam generator water inventory 52,110 Ibm 932 Time when operator would be required to trip 15 minutes after charging pumps reactor trip 961.1 Minimum RCS pressure 1972.4 psia 1111.9 Time when liquid starts to discharge through the PSV quality < 1.0 PSVs (if operator did not trip charging pumps 15 minutes after trip) 1297.1 Pressurizer safety valves begin to open 2424 psia 1705.2 Maximum RCS pressure 2484 psia 1705.4 Maximum pressurizer liquid volume 1468.7 ft 1800 End of analysis
Table 2-1 Assumptions for 1800 seconds Long-Term LOFW Event with Operator Action 15 min After Reactor Trip (Case 2)
Parameter Power Uprate Assumption Initial Core Power level, MWt 3735 Core Inlet Temperature, OF 533 RCS Flowrate, 10' Ibm/hr 148 Pressurizer Pressure, psia 2090 Pressurizer Level, % 67.5 SG Pressure, psia 742 SG Level, %NR 90 MTC, 104 Ap/IF 0.5 Doppler Coefficient Multiplier 0.85 CEA Worth for Trip, 10 2Ap -6 SBCS Inoperative PLCS Manual PPCS Automatic Single Failure PLCS: maximum charging flow and zero letdown flow Operator Action 15 min after reactor trip operator trips 2 out of 3 charging pumps
& initiates letdown flow
Table 2-2. Sequence of Events for the Loss of Normal Feedwater Long-Term Case with Operator Action 15 min After Reactor Trip (Case 2)
Time Event Setpoint or value (sec) 0.0 Termination of all feedwater flow 0.0 PLCS failure:
Maximum charging flow 144 gpm Minimum letdown flow 0 gpm 32.1 Low steam generator water level trip signal 5% NR 33.0 Trip breakers open 33.6 CEAs begin to drop into core 33.6 Maximum core power (% of 3716 MWt) 101.3%
40.6 Maximum RCS pressure 2379 psia 48.3 Steam generator safety valves open 1117 psia 49.8 Maximum steam generator pressure 1118.6 psia 82.5 Emergency feedwater reaches steam generators 432.1 Minimum steam generator water inventory 50,990 Ibm 932 Operator trips 2 out of 3 charging pumps; 15 minutes after initiates letdown flow reactor trip Charging flow 48 gpm Letdown flow 78 gpm 963.8 Minimum RCS pressure 1932.7 psia 1033.1 Maximum pressurizer liquid volume 1369 ft 1800 End of analysis 4 4
Table 3-1 Assumptions for 1800 seconds Long-Term LOFW Event with Reduced AFW Flow (Case 3)
Parameter Power Uprate Assumption Initial Core power level, MWt 3735 Core Inlet Temperature, OF 533 RCS Flowrate, 10o Ibm/hr 148 Pressurizer Pressure, psia 2090 Pressurizer Level, % 67.5 SG Pressure, psia 742 SG Level, %NR 90 MTC, 104Ap/aF 0.5 Doppler Coefficient Multiplier 0.85 CEA Worth for Trip, 1oP2Ap -6 SBCS Inoperative PLCS Automatic PPCS Automatic Single Failure EFW flow: one-half emergency feedwater capacity, 575 gpm Operator Action None
Table 3-2. Sequence of Events for 1800 seconds Long-Term LOFW Event with Reduced AFW Flow (Case 3)
Time Event Setpoint or value (sec) 0.0 Termination of all feedwater flow --
32.1 Low steam generator water level trip signal 5% NR 33.0 Trip breakers open ---
33.6 CEAs begin to drop into core 33.6 Maximum core power (% of 3716 MWt) 101.4%
40.6 Maximum RCS pressure 2366 psia 47.4 Maximum pressurizer liquid volume 1081 ft 47.7 Steam generator safety valves begin to open 1117 psia 52.3 Maximum steam generator pressure 1120 psia 96.5 Emergency feedwater reaches steam generators -
504 Minimum steam generator water inventory 46,120 Ibm 1026.4 Minimum RCS pressure 1939 psia 1800 End of analysis _
4 1
Figure 1-1 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Core Power vs. Time 120, I 100 t 2 80 Co N.
CO LU.
0 z
( 60 0.
0~
Of: 40 0
Mu 20 -
O i l
. I 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1.2 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Core Heat Flux vs. Time 120 100 9too cot CD I-U-80 -
w (9
< 60-U-
0 z
w CU 0.
>~ 40 -
W
-j LU
°w o0 20 -
0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-3 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Reactor Coolant System (Cold Leg Discharge) Pressure vs. Time 2600 2400 U) a.
Li CD a:
U, WU 2200 I--
co, 8200 z
o 0
2000 co 0
0 w
1800 1600 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-4 Loss of Normal Feedwater Flow with PICS Failure, Long-Term Reactor Coolant System Temperatures vs. Time 610 600 L. 590 d
w 0
CD W 580 AL 2w 570 w
e-
> 560 5I-0 0
C8) 550 0
L%540 530 520 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-5 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Pressurizer Water Volume vs. Time 1500 1400 1300 CV)
La
-J o 1200 w
a-Lu 1100 C,,
w en 1000 900 800 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-6 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Steam Generator Pressure vs. Time 1200 1150 1100 1050 UF W-1000 cn EL L
0~
950 z
w (9 900 I-C,,
850 800 750 700 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-7 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Total Secondary Steam Flowrate vs. Time 5000
/
4500 4000 -
W 3500 -
C,,
-i 0L 3000 3 -
0-J 2500 1- -
w C:
>-2000 -
0 z
0 0
w 1500 U,
1000 500 0 I f.d vn 1f 1 f 11 I 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-8 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Emergency Feedwater Flowrate per Steam Generator vs. Time 100 90 QU m
-j 80 0
W-w 70 z
w (9
LU 60 w
LU LI 50 0U
-j U- 40 W
W i-a.
30 U..
z 20 wi LI)
W wj 10 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-9 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Emergency Feedwater Enthalpy vs. Time 500 400 m
-j a-
-j
< 300 I
z w
W UL 200 0
z r::
w9 100 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-10 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Secondary Liquid Mass vs. Time 200000 180000 160000 2 140000 m
-J C',
5 120000 0
a W 100000 0
LU 80000 0
60000 40000 20000 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-11 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Safety Valve Flowrate per Steam Generator vs. Time 500 0
w cn m
-j 400 0
of z
w 0
us w
I 300 un 0:
AL 0-0:
-J LL 200 IL U-
< 100 0
z 0
0 uw U) 0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-12 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Primary Safety Valve Flow Rate vs. Time 600 500 0
w co
-' 400 w
0
-J
-J W300 L-
>- 200 00.
100 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 1-13 Loss of Normal Feedwater Flow with PLCS Failure, Long-Term Primary Safety Valve Quality vs. Time 1.2 1.0
,0.8 a
w r 0.6 LiL nr 0.4 0.2 0.0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-1 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Core Power vs. Time 120-100
~80 -
0 0
a60 0~
0~
20 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-2 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Core Heat Flux vs. Time 120-100 CD I-U- 80-I-
60 z
w 400 0 2 U-0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-3 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Reactor Coolant System (Cold Leg Discharge) Pressure vs. Time 2600 2400 (I,
CD a-Li W 2200 WL I-U)
C,,
z o
0 2000 0
0 0
w 1800 1600 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-4 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Reactor Coolant System Temperatures vs. Time 610 600 IL 590 C
w 0
c]
W580 W
w a-2w 570 H
U)
> 560 z
0 0
° 550 0
0 W 540 530 520 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-5 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Pressurizer Water Volume vs. Time 1500 1400 1300 LUi
-i1200 w
I--
W N 1100 CO, en U) w W-1000 900 800 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-6 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Steam Generator Pressure vs. Time 1200 1150 1100
< 1050 05 a-n 1000 u) a:
0~
W 950 z
WU 900 U) 850 800 750 700 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-7 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip Long-Term Total Secondary Steam Flowrate vs. Time 5000 -
4500 -
4000 -
W 3500 -
-J m
I 3000 -
0:
-r L- 2500 -
w
'I:-
LU
> 2000 -
0 z
0 w 1500-1000 -
500 0
0 CT-200 In 400 600 It ..
800
. n nfl
.. ..IL 1000 IL
.L .,11 1200 1
1400
. ...L 1600
.... ...L 1800 TIME, SECONDS
Figure 2-8 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Emergency Feedwater Flowrate per Steam Generator vs. Time 100 90 -
80 0
w 70-z w
VJ 60-0~
450-30-I-I U-Wz 20 -
(9 10 -
0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-9 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Emergency Feedwater Enthalpy vs. Time 500 400 m
m
-J a-
-J
< 300 I
zI z
w w
I-0 w
a:
u-200 -
z w
(9 LU 100.
0-0 200 400 600 800 1000 1200 1400 . 1600 1800 TIME, SECONDS
Figure 2-10 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Secondary Liquid Mass vs. Time 200000 180000 160000 2 140000 m
-J C6 2 120000 a
C}
W 100000 0
W 80000 60 60000 40000 20000 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-11 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Safety Valve Flowrate per Steam Generator vs. Time 500
- U)
M
-400 -
0 z
w I--
co) 300 w
0
-J
'200 -
U-U)
< 100 -
0 z
0 0
w U) 0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-12 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip, Long-Term Primary Safety Valve Flow Rate vs. Time 600 500 0
w U,
-' 400 Li 0
U-UJ300 -
LL 2U, W 20200 a.
100 00 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 2-13 Loss of Normal Feedwater Flow with Operator Action 15 min After Reactor Trip Long-Term Primary Safety Valve Quality vs. Time 1.2 1.0 U-WEO.4 EL 0.2 0.0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-1 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Core Power vs. Time 120 100 -
80]
co cV) 0 z
ALi w
60 -
o-0 40 -
0 20 -
0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-2 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Core Heat Flux vs. Time
Figure 3-3 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Reactor Coolant System (Cold Leg Discharge) Pressure vs. Time 2600 2400 CD a.
Co CL co w 2200 cc a.-
On co z
o 0
2000 0
0 w
1800 1600 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-4 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Reactor Coolant System Temperatures vs. Time 610 600 L. 590 w
0W M: 580 a:
2 570 w
CD W 560 z
0 0
( 550 0
CC 540 530 520 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-5 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Pressurizer Water Volume vs. Time 1500 1400 1300 Li w
3-Wi N 1100 cn co w
ccm 1000 900 800 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-6 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Steam Generator Pressure vs. Time 1200 1150 -
1100 =
< 1050 Li D 1000 -
Cn a:
950-I-
z W 900-co 850 800 750 -
700 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-7 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Total Secondary Steam Flowrate vs. Time 5000 4500 4000 W 3500 -
m
-J H 3000 -
3:
0-j U. 2500 -
w I-2000 -
U) 0 zux 0
0 wU 1500 -
U, 1000 -
HHi I NIh 500 -
0 0
_ LjlfI[R 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-8 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Emergency Feedwater Flowrate per Steam Generator vs. Time 100 -
90 -
0 w
M 1 80-0 W 70-z w
(9UJ60 -
a-Wi 0 I 0
-J LL 40 -
w o30 -
w U-Wz 20 -
10 -
0 . . . £. - - - - - - - - . . . . . . . .
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-9 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Emergency Feedwater Enthalpy vs. Time 500 -
400 -
m
-j
< 300 -
M z
I-w W
I-0 w
UL 200 -
0 z
100-0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
3-10 Long-Term Feedwater Flow with Reduced EFW Flow, Figure Loss of Normal vs. Time Secondary Liquid Mass
Figure 3-11 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Safety Valve Flowrate per Steam Generator vs. Time 500 0
w
-J
-a 400 0
I-w z
w uD w
300 a-wW 0
-j
'200 co w
U-u-
n LL
< 100 0
z 0
0 w
CD 0
0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-12 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Primary Safety Valve Flow Rate vs. Time 600 500 -
0 Cn m
-J 400 F
a:
0-J IL 300-
>. 200 -
W 2
E a:
100 -
0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Figure 3-13 Loss of Normal Feedwater Flow with Reduced EFW Flow, Long-Term Primary Safety Valve Quality vs. Time 1.2 1.0
¢, 0.8 -
a 0.6 U,
- 0.4-a.
0.2 0.0 0 200 400 600 800 1000 1200 1400 1600 1800 TIME, SECONDS
Attachment 3 To W3Fl-2004-0096 Emergency Operating Procedure and Operator Action Time to Secure Charging to W3Fl-2004-0096 Page 1 of 1 Emergency Operating Procedure and Operator Action Time to Secure Charging Question:
During a Feedwater Line Break (FWLB) event, a Safety Injection Actuation Signal (SIAS)
(generated on a high containment pressure signal) would further challenge the long-term cases. Among other things, a SIAS starts safety injection pumps, starts all three charging pumps, and isolates letdown. While the High Pressure Safety Injection (HPSI) pumps and letdown isolation have little effect, the mass addition associated with three charging pumps will quickly fill the pressurizer solid. For the FWLB event, the depletion of secondary side inventory and the subsequent Reactor Coolant System (RCS) heatup had previously challenged criteria to prevent the pressurizer going solid and Pressurizer Safety Valve (PSV) liquid discharge criteria. Now with the mass addition of 3 charging pumps, it would be impossible to demonstrate compliance during the first 30 minutes. The Waterford 3 Extended Power Uprate (EPU) FWLB calculation requires operator action to secure charging flow within 12 minutes. The staff should verify that Emergency Operating Procedures (EOPs) instruct operators to perform this function and that this action will be completed within 12 minutes. Note that the LOAC will direct operators to the Functional Recovery procedures, which may delay this required action.
Response
Per NUREG-0800 Standard Review Plan (SRP) 15.2.8 Section II, an operator action time greater than 10 minutes may be assumed. This time is reasonable to assume for all non-LOCA events for non-ECCS non-ESF actions such as securing charging to prevent pressurizer overfill.
An SIAS only auto starts two charging pumps not three as assumed in the question above.
Standard post reactor trip actions instruct the Operator to maintain pressurizer level within 33% and 60% by, among other things, operating charging pumps as necessary. This is a continuous action performed throughout the EOPs whenever pressurizer level is challenged and regardless of which individual EOP is being used. Since Operators continuously monitor pressurizer level during the accident and a high pressurizer level alarm exists, there is high confidence that charging pumps can be secured within the required time to prevent filling the pressurizer. The standard post trip actions also include instructions to stabilize RCS temperature in the event of an Excess Steam Demand, as would exist for a Feedwater line break, by either the steam dump valves to the condenser or the Atmospheric Dump Valve on the intact steam generator and feeding with emergency feedwater. This action, which is not credited in the analysis, typically occurs in simulator scenarios as pressurizer pressure starts to rise after the initial cooldown. This action limits the pressurizer refill effects due to RCS heat up and provides more time to fill the pressurizer than is predicted in the analysis. The implementation of this step is not time based, but is indication based (pressurizer pressure or core exit thermocouple temperature starts to rise). Since EPU has little effect on the time for the faulted steam generator to blow down, the timing of the EOP action to stabilize temperature will not change appreciably. Operators will stabilize temperature and pressure when the faulted steam generator has lost its RCS cooling capability. RCS temperature will be controlled at a lower temperature than at the start of the accident, thus giving a relatively long time with two charging pumps running before pressurizer level would be high in the level band.
Attachment 4 To W3FI-2004-0096 Revised Section 2.13.6.3.2, Steam Generator Tube Rupture
2.13.6.3.2 Steam Generator Tube Rupture The objective of the steam generator tube rupture (SGTR) with loss-of-offsite power (LOOP) analysis is to document the impact of the following changes:
- Change from CESEC to CENTS as the primary simulation tool
- A decrease in secondary system pressures due to the uprate
- Associated lowering of the MSIS setpoint The impact of the EPU resulted in no violation of maximum RCS and SG pressure limits for the SAR events.
2.13.6.3.2.1 General Description of the Event The SGTR accident is a penetration of the barrier between the Reactor Coolant System (RCS) and the Main Steam Supply System (MSSS), which results from the failure of a steam generator (SG) U-tube. Integrity of the barrier between the RCS and MSSS is significant from a radiological release standpoint. The primary coolant activity from the leaking SG tube mixes with the shell side water in the affected SG. After the reactor trip and turbine trip, the radioactive fluid will be released through the ADVs as a result of the LOOP.
A SGTR event results in a depressurization of the RCS. Prior to reactor trip, the radioactivity is transported through the turbine to the condenser where noncondensable radioactive materials would be released via the condenser air ejectors. Because of the reactor trip, the turbine/generator trips and normal offsite power is assumed to be lost. It is assumed that electrical power would then be unavailable for the station auxiliaries such as reactor coolant pumps (RCPs) main feedwater pumps (MFPs), and main circulating water pumps. Under such circumstances, the plant would experience a loss of load, normal feedwater flow, forced RCS flow, condenser vacuum, and SG blowdown. A LOOP after the reactor and turbine/generator trip results in the greatest releases of radioactivity to the atmosphere, therefore, it is assumed for a limiting analysis. The plant is brought to SDC entry conditions through the use of SG ADVs, pressurizer heaters, auxiliary spray, the Safety Injection System (SIS), charging and the Emergency Feedwater System (EFS).
Diagnosis of the SGTR accident is facilitated by radiation monitors that initiate alarms and inform the operator of abnormal activity levels and that corrective operator action is required. These radiation monitors are located in the condenser air ejector discharge, SG blowdown lines, and main steam lines. Additional diagnostic information is provided by the RCS pressure and pressurizer level response and by the level response in the affected SG.
2.13.6.3.2.2 Purpose of Analysis and Acceptance Criteria The purpose of the analysis was to determine whether the peak primary and secondary system pressures remain below their respective acceptance criteria, DNBR remained above the DNB SAFDL, and to provide input for the offsite dose analysis.
The following criteria apply to the SGTR event:
- Peak RCS pressure < 2750 psia
- Peak secondary pressure
- 1210 psia
- Radiological doses are within 10CFR100 limits The SGTR w/LOOP event is described in Chapter 15.6.3.2 of the FSAR (Reference 2.13-1).
2.13.6.3.2.3 Impact of Changes In the reanalysis of the SGTR, the CENTS code is used in the same fashion as the CESEC code.
The decreased secondary system pressures associated with the EPU conditions tend to increase the primary-to-secondary system leakage predicted in the early phases of the event.
The increase in rated thermal power (RTP), and resulting decay heat load tend to increase the amount of steaming necessary to perform plant cooldown.
2.13.6.3.2.4 Analysis Overview This analysis utilized the CENTS computer code (Reference 2.13-2) for the transient analysis simulation. The minimum DNBR evaluation was determined using the CETOP code (Reference 2.13-3). As stated in the FSAR, the LOOP case is bounding for offsite doses. This is due to the fact that the release path for the LOOP is direct to the atmosphere rather than through the condenser when offsite power is available. This analysis assumes that the LOOP occurs 3.0 seconds after reactor trip which is a conservative assumption as discussed in Reference 2.13-13. This assumption is consistent with the SGTR with LOOP assumptions made on other plants and included in CESSAR FSAR Chapter 15.
The input parameters from Table 2.13.6.3.2-1 and the bounding physics data from Section 2.13.0.2 of this report were incorporated with the following clarifications:
- The BOC Doppler curve was assumed.
- A BOC delayed neutron fraction and neutron lifetime consistent with those defined in Section 2.13.0.2 were assumed.
- An initial core power of 3735 MWt, based on a rated power of 3716 MWt and a 0.5%
uncertainty, was assumed.
- A most positive (least negative) MTC of -0.2
- 104 Ap/OF at HFP was used.
- The maximum HFP core inlet temperature of 552 OF was assumed.
- A minimum RCS flow of 1.48x10 8 Ibm/hr was assumed.
2.13.6.3.2.5 Radiological Consequences During the SGTR, a total of 325,702 Ibm of primary coolant passes through the rupture into the affected SG. Prior to reactor trip, both SGs are steaming normally to the condenser. The high partition factor associated with the condenser makes releases from this source insignificant. Following reactor trip, both SGs are steamed through the ADVs. The affected SG is then isolated until it is necessary to bring the affected SGs ADV back into service for reaching equilibrium for shutdown cooling entry and SG inventory control. A total of 245,600 Ibm of steam is released to the atmosphere through the affected SGs ADV. Of this 138,969 Ibm are released during the initial steaming prior to isolation.
The majority of the cooldown of the plant is performed by steaming the unaffected SG. A total of 910,107 Ibm of steam are released through the unaffected generator's ADV during the cooldown of the plant. Radioactivity release through this intact SG is assumed due to primary to secondary tube leakage.
The radiological consequences for the SGTR with LOOP were calculated for both a pre-existing iodine spike and an event generated iodine spike.
The radiological consequences resulting from the SGTR with LOOP are:
I 2-Hour EAB (PIS) I 8-Hour LPZ (PIS) l I
Thyroid < 300 rem < 300 rem Whole Body < 25 rem < 25 rem 2-Hour EAB (GIS) 8-Hour LPZ (GIS)
[ Whole Body < 2.5 rem < 2.5 rem Note:
GIS - generated iodine spike PIS - pre-existing iodine spike 2.13.6.3.2.6 Analysis Results The peak RCS and SG pressures remained below their respective criterion of 2750 psia and 1210 psia. The NSSS and RPS responses for the SGTR event are shown in Table 2.13.6.3.2-2 and in Figures 2.13.6.3.2-1 through 2.13.6.3.2-13.
Table 2.13.6.3.2-1 Assumptions for 3716 MWt SGTR with LOOP 3716-MWt Current Power Uprate Power Level Parameter Assumption Assumption Initial Core Power, MWt 3735 3478 Core Inlet Temperature, 'F 552 560 RCS Flowrate, 106 Ibm/hr 148 141 Pressurizer Pressure, psia 2090 2000 Pressurizer Level, % 33 SG Pressure, psia 872 949 SG Level, % NR 26.5 88.5 MTC 104 Ap/OF -0.2 N/A Doppler Coefficient Multiplier .85 N/A CEA Worth for Trip, % Ap -6.0 N/A SBCS Inoperative Inoperative Feedwater Regulation System Inoperative Inoperative EFS Automatic Automatic SG ADVs Automatic Automatic ADV Setpoint, psia 980 1050 SIAS Setpoint, psia 1560 1560
Table 2.13.6.3.2-2 Sequence of Events for 3716 MWt SGTR with LOOP Current Power Current Power EPU Time Level Time 3716-MWt EPU Level (Sec.) (Sec.) Event SetpointNalue SetpointlValue 0.0 0.0 Tube rupture occurs -- --
45 40 Second charging pump turned -0.75 -0.75 on, on pressurizer level error, ft 70 70 Third charging pump turned on, -1.17 -1.17 on pressurizer level error, ft 445 109.3 CPC hot leg saturation trip 13 13 condition reached, OF 446 CEAs begin to drop 448 109.7 LOOP _
445 112.1 SG ADVs open, psia 980 1050 450 113.5 SG MSSVs open, psia 1085 1085 455 142 SG MSSVs close, psia 1041.6 1041.6 485 170.1 SIAS actuated on pressurizer 1560 1560 pressure, psia 515 645 Safety injection flow begins to --
enter RCS 595 138.1 Pressurizer empties
Table 2.13.6.3.2-2 (cont)
Sequence of Events for 3716 MWt Steam Generator Tube Rupture with Loss of Offsite Power Current Power Current Power EPU Time Level Time 3716 MWt EPU Level (Sec.) (Sec.) Event Setpointlalue SetpointValue 875 530 Operator initiates EFW flow to 225 225 unaffected SG Operator 650 Operator takes manual control of --
control with the SG ADVs. Initiates plant 2-minute cooldown by steaming through interval both of the ADVs between 4190 Operator initiates auxiliary spray _
actions in order to depressurize the RCS begins. below 1000 psia and regain level control in the pressurizer.
3350 Operator manually controls EFW 71 77 flow to the intact SG to maintain 68% to 71 % WR.
4310 Operator manually controls safety --
injection, auxiliary spray flow and the pressurizer backup heater output to try to maintain subcooling (280F) and pressurizer level (33%-60%)
1980 4070 Operator isolates the affected SG 23630 8270 Operator opens ADV to the -- --
affected SG as needed to maintain level below 94% WR.
28800. 28800 Shutdown cooling entry 392/350 392/350 conditions reached, RCS pressure, psia/Temperature, OF
1.2 0.8 0
2 I,
0.6 .
90 El 0
V I-Core Aver-ag-e Power 0.4-0.2-0I 0 100 200 300 400 500 Time (Sec)
Figure 2.13.6.3.2-1 SGTR with LOOP Core Power vs. Time
1.2 0.8-0.4 b l _~core Ave rage Heat Fluxli
- 0.2 0
0 100 200 300 400 500 Time (Sec)
Figure 2.13.6.3.2-2 SGTR with LOOP Core Heat Flux vs. Time
2600 2200 -
1800 -
a.
, 1400 -
ILI a:
1000 -
600 200 0 5000 10000 15000 20000 25000 Time (sec)
Figure 2.13.6.3.2-3 SGTR with LOOP RCS Pressure vs. Time
650 600 -
660 I C. boo C.
450 Thot Unaffected SG 400 -
Ti 350 3n0 0 5000 1Oo00 15300 2000C, 25000 rimn (SOc)
Figure 2.13.6.3.2-4 SGTR with LOOP RCS Temperatures vs. Time
leco 14C0 -
1200 10 0 0 g 8 co 0 00 600 -
200 0 boo5 10000 15000 20000 25000 Time (Sec)
Figure 2.13.6.3.2-5 SGTR with LOOP Pressurizer Water Volume vs. Time
800000 700000 30000O 00C000 4000DO 300C00 , _
D 5C00 10000 150Co 20C00 25000 Time (Sec)
Figure 2.13.6.3.2-6 SGTR with LOOP RCS Inventory vs. Time
1200 1000 n I' C O 0 l 400 -
0 200
120 100 80 E
-Aux Fee 60 20 40 0 5000 10000 15000 20000 25000 Time (Sec)
Figure 2.13.6.3.2-8 SGTR with LOOP Feedwater Flowrate per SG vs. Time
40 35 30 -
25 -
20-15 10 S
0I 1 1001 ZO0 3001 4001 5001 Thk (Sec)
Figure 2.13.6.3.2-9 SGTR with LOOP Primary-to-Secondary Leak Rate vs. Time
400000 350000-
-Total a
- Total Ll 300000-E E
.0
> 250000-0*J, 0
_ 200000/
0 E
150000 100000 50000 0 5000 10000 15000 20000 25000 Time (Sec)
Figure 2.13.6.3.2-10 SGTR with LOOP SG Liquid Mass vs. Time
1000000-900000-E
- 800000 Unaffected SG m- 700000-0 C 0 600000-
.4-.
U, CI, co 500000 a)
E 400000-Cu
-) 300000 -
Cu a) 200000 - Affected SG
.-b-100000 -
0 5000 10000 15000 20000 25000 Time, Seconds Figure 2.13.6.3.2-11 SGTR with LOOP Integrated Steam Mass Through ADVs vs. Time
720000 600000 480000 0
tTotal Intogta 1ld SGTI 1 Flow
- 360000 240000-120000-0 5000 I0000 15000 20000 25C00 Tltme {See)
Figure 2.13.6.3.2-12 SGTR with LOOP Integrated Primary-to-Seconclary Leak Flow vs. Time
7 S
aIs A
4 2
0 25 50 75 100 125 IS0 175 20C 225 250 275 3 00 325 350 375 400 42 4*50 Time (not)
Figure 2.13.6.3.2-13 SGTR with LOOP Minimum DNBR vs. Time
Attachment 5 To W3FI-2004-0096 Minor Miscellaneous Corrections to Section 2.13
Minor Miscellaneous Corrections to Section 2.13 The revisions to Power Uprate Report (PUR) Section 2.13 consist of minor corrections that were not included in the initial submittal of the report. None of these changes affect the report's conclusions. The changes are:
- 1. Editorial revision to the entry for Section 2.13.2.2.3 in Table 2.13.0-1 to use terminology consistent with other sections in the PUR. Reference to an additional bounding event has been added to the table for the LOOP event. The additional event (Inadvertent Opening of a Steam Generator ADV in PUR Section 2.13.2.1.4) bounds the radiological consequences of the LOOP. Consistent with this change, the text of PUR Section 2.13.2.1.4 has been revised to cite the bounding event for LOOP radiological consequences.
- 2. Revisions to figures that reflect slight changes in the transient behavior of various parameters or changes to labeling. The figures affected are: 2.13.1.1.4-4; 2.13.1.3.3-7; 2.13.2.2.5-8; 2.13.4.1.3-3; 2.13.4.1.3-5; 2.13.4.1.3-7; 2.13.4.3.2-12.
- 3. Replacement of Figure 2.13.1.2.3-5 to show the Tavg trace that did not reproduce in the printed version of the existing figure.
- 4. Editorial change to Table 2.13.1.3.3-1 to change the units for RCS flowrate from m/hr to Ibm/hr.
- 5. Minor changes to Sequence of Events Table 2.13.1.3.3-3 to correct some timing and parameter values. The initially reported minimum DNBR is more conservative (closer to the DNBR limit) than the corrected value.
- 6. Two revisions to Section 2.13.1.3.3.6. One revision incorporates the revised minimum DNBR in Table 2.13.1.3.3-3 noted above, and the other revises a minimum DNBR value to the correct value presently reported in Table 2.13.1.3.3-4 (i.e., a correction to achieve internal consistency in the PUR).
- 7. In Table 2.13.2.3.1-2, the maximum SG pressure has been changed from 1122 psia to 1123 psia. The change is due to roundoff.
- 8. In Table 2.13.2.3.1-3, the initial intact SG inventory has been corrected from 98.280 to 98,280.
- 9. In Table 2.13.2.3.1-4, the time of emergency feedwater activation has been changed from 60 sec. to 50 sec. to achieve internal consistency with event timings provided in the table.
- 10. In Table 2.13.3.2.1-2, the time of the low RCP shaft speed trip has been changed from 0.48 sec. to 0.49 sec. The change results from roundoff.
- 11. In Table 2.13.3.3.1-1, the assumed pressurizer level has been corrected from 44 to 54 percent, and the narrow range SG level has been corrected from 68 to 71 percent.
- 12. In Table 2.13.4.1.4-1, the RCS flowrate for power uprate has been changed from lb/hr to gpm for consistency with the value presented for the current power level assumption. Correspondingly, the units for RCS flowrate have been changed to gpm.
- 13. Correction of the time of RCS peak pressure in Table 2.13.4.3.2-4 from 2.9 sec. to 3.41 sec. In addition, Figure 2.13.4.3.2-2 has been replaced to show peak core power as a fraction of full power.
Waterford 3 Extended Power Uprate Table 2.13.0-1 (cont.)
Non*-LOCA Transient Events Section Event Category Result 2.13.12.3 Increased Main Steam Flow wit Infrequent EPU analysls provided Loss-of-ofsite Power (LOOP) Event 2.13.12.4 IOSGADV with LOOP Infrequent EPU analysis provided Evont 2.13.1.3.1 Stear System Piping Falures U-miting EPU analysis provided I Post-Trip Analysis Fault 2.13.1.32 Mode 3 and 4 All Rods In (ARI) lUmiting Event Isbounded by current Steam Line Break (SLB) Fault FSAR 2.13.1.3.3 Steam System Piping Failures Limiting EPU analysis provided Pie-Trip Power Excursion Fault Decrease In Heat Removal by the Secondary System (Turbine Plant) 2.132.1.1 Loss of External Load Moderate Event Is bounded by Frequency 2.132.1.3 2.13.2.12 Turbine Trip Moderate Event Is bounded by Frequency 2.13.2.1.3 2.13.2.1.3 Loss of Condenser Vacuum Moderate EPU analysis provided (LOCV) Frequency 2.132.1.4 LOOP Moderate Evontisboundedby 2.13,1.1 Frequency 2.132.1.3 and 2.13.3.2.1 2.132.1.5 Steam Pressure Regulator Moderate Event Is bounded by Falure Frequency 2.13.2.1.3 2.132.2.1 Loss of External Load with SAF Infrequent Event is bounded by Event 2.1322.3 2.132.2.2 Turbine Trip with SAF Intrequent Event Is bounded by Event 2.13.22.3 2.1322.3 LOCVwithjp 5QAF Infrequent EventwithSAFls bounded Event by event with no SAF.
2.132.1.3 2.1322.4 Loss-ol-Normal AC Power with Infrequent Event Is bounded by SAF Event 2.13.32.1 2.1322.5 Lossol-Normal Feodwator Flow Infrequent EPU analysis provided Event 2.13.2.3.1 Feedwater System Pipe Breaks Urriting EPU analysis provided Fault 2.13-2 6X&I.wOX-1 1A15/03 6O61ioc.l tDY05 2.13-2
Table 2.13.1.3.3-1 Key Parameters Assumed for the Steam Piping Failures Event IC Pre-Trip Power Excursions Current Power Power Uprate Level Parameter Assumption Assumption Initial Core Power, MWt 3735 3482 Core Inlet Temperature, 0F 552 560 Pressurizer Pressure, psia 2310 2000 RCS Flowrate, 106 Ibm/hr 148.0 137.0 Pressurizer Level, % 35.8 --
SG Pressure, psia 878 976 SG Level, % NR 65 (36.1 ft) -
MTC, 104 Ap/IF -4.2 -4.0.
Doppler Coefficient Multiplier 0.85 (BOC) 0.85 (BOC)
Kinetics Minimum IB Minimum IB CEA Worth at Trip, %Ap -6.0 -6.0 Break Size ft2 5.5 5.25
2.13.1.3.3.6 Analysis Results The primary reactor trip for the pre-trip SLB event is the CPCS VOPT. The initial thermal margin was selected to ensure no fuel failure occurs for the OC breaks. This margin, in conjunction with the input parameters from Tables 2.13.1.3.3-1 and 2.13.1.3.3-2 and the physics data from Section 2.13.0.2 resulted in the lowest calculated DNBR. 1.1689 at 6.5 Table 2.13.1.3.3-3 delineates the sequence of events for the pre-trip SLB IC event. A CPCS VOPT occurs at 3.63 seconds, which results in a minimum DNBR of416O2 at 6.
seconds. Figures 2.13.1.3.3-1 through 2.13.1.3.3-7 illustrate the behavior of key parameters associated with the pre-trip SLB event.
As shown in Table 2.13.1.3.3-4 for the pre-trip SLB outside-containment event, a CPCS VOPT occurs at 3.73 seconds, which results in a minimum DNBR of 4.287-9 at 6.7-seconds. The minimum DNBR remains greater than the SAFDL value of 1.26.
l1.2754 at 6.3
Table 2.13.1.3.3-3 Sequence of Events for the Steam System Piping Failure Event IC Pre-Trip Power Excursion with LOOP Current 3716 MWt Power Current Power EPU Time Level Time 3716 MWt EPU Level (sec) (sec) Event SetpointlValue SetpointValue 0.0 0.0 Failure in the MSSS Piping 5.5 ft2 5.25 ft2 3.63 4.57 CPCS VOPT trip occurs 113.63% of 117.14% of 3716 MWt 3482 MWt 4.06 5.2 Trip breakers open 4.35 6.0 LOOP occurs, RCPs begin coastdown 4.66 5.8 CEAs begin to drop 5-425.2 6.0 Maximum core power 436.06134% o 137.5*Ia of 3716 MWt 3482 OWt 57965.8 6.35 Maximum core heat flux 419.73118% of 119.4 o of 3716 MWt 3482 IWt 646.5 6.9 Minimum DNBR 446021.1689 1.161t I
2.13.2.1.4 Loss-of-Normal AC Power The thermal margin consequences of this event are bounded by the loss of flow, I Section 2.13.3.2.1 of this report. The peak pressure consequences of this event are bounded by the LOCV, Section 2.13.2.1.3 of this report. Radiological consequences of this event are bounded by the Inadvertent opening of a Steam GeneratorADV, Section 2.13.1.1.4 of this report.
Table 2.13.2.3.1-2 Comparison of the Sequence of Events for the Limiting Large FWLB Event Current Current Power Power Level Level EPU Time (sec) SetpointlValue Time Reference 3, EPU Setpoint/ Reference 3, (sec) Table 15.2-8 Event Value Table 15.2-8 0.0 0.0 Break of main feedwater line. 0.12 ft2 0.2 ft2 Complete loss of feed flow.
24.1 -- Low SG trip condition (SG 9000 Ibm (2 ft) 5% NR liquid mass) 24.1 -- EFW actuation signal 9000 Ibm (2 ft) 5% NR generated by low water level trip condition (SG liquid mass) 24.6 17.3 High pressurizer trip condition 2422 psia 2474 psia 25.0 18.2 Trip breakers open __--
25.0 18.2 Turbine trip 25.0 18.2 LOOP _
25.01 18.2 Turbine admission valves _
closed 25.6 18.8 CEAs begin to drop _
26.95 16.6 SG connected to the ruptured 2000 Ibm feed line empties 27.0 18.7 PSVs open 2575 psia 2575 psia 27.85 20.7 Maximum, pressurizer surge 1914 Ibm/sec 1637 Ibm/sec line flow 28.2 21.3 Maximum RCS pressure 2753 psia 2750 psia 34.5 22.8 SG safety valves open 1117 psia 1117.6 psia 35.0 26.7 Maximum SG pressure 11232 psia 1165 p ia 84.1 70.1 Emergency feedwater flow --- --
initiated*
100 26.0 Minimum pressurizer steam 225.2 ft3 391 ft3 volume 1800 1800 Opertor takes control of plant --- _ _
28,800 -- SDC initiated
- EFW flow is initially diverted to the break.
Table 2.13.2.3.1-3 Comparison of Assumptions for the Small FWLB Event Power Uprate Current Power Parameter Assumption Level Assumption Initial core power level, MWt 3735 3478*
Core inlet temperature, OF 552 560 Core mass flow rate, 106 Ibm/hr 148 128.55 RCS pressure, psia 2310 2200 SG pressure, psia 867 964 MTC, 104Ap/CF -0.2 0 Doppler coefficient multiplier 0.85 0.85 CEA worth for trip, 102 Ap -6 -6.0 SBCS Inoperative Inoperative PPCS Inoperative Inoperative PLCS Automatic Inoperative FWLB area, ft2 0.17 0.2 Initial intact SG liquid inventory, Ibm 98,7280 14 SG safety valve setpoint tolerance, percent +3% +3%
PSV setpoint tolerance, percent +3% +3%
EFW flow, gpm 575 700
- Includes pump heat
Table 2.13.2.3.1-4 (cont.)
Comparison of the Sequence of Events for the Limiting Small FWLB Event Current Current Power Power Level Level EPU Time (sec) SetpointlValue Time Reference 3, EPU Reference 3, (sec) Table 15.2-8 Event SetpointValue Table 15C.1-3 44 28.1 SG safety valves open 1117.2 psia 1117.6 psia 46.05 30.5 Maximum SG pressure 1129.1 psia 1152.5 psia 51.8 35.8 Minimum pressurizer steam 345.4 ft3 443.2 ft3 volume 86.6 - EFW flow initiated emergency --
feedwater flow activation (EFWA)
+ 5060 sec 100. End of analysis 100.0
Table 2.13.3.2.1-2 Sequence of Events for the Loss of Flow Current EPU Power Current Power Time Level Time EPU Level (sec) (sec) Event SetpointValue SetpointValue 0.0 0.0 Loss of power to all RCPs -- -
Low RCP shaft speed trip 96.5% of initial 96.5% of initial 0.498 0.622 condition shaft speed shaft sdeed 0.78 0.85 Reactor trip breakers open _
1.38 1.45 CEAs begin to drop ---_ _
2.60 2.20 Minimum DNBR > 1.26 > 1.26 7.9 4.5 Maximum RCS pressure, psia 2395 2523 183.5* 15* SG safety valves open, psia 1117 1100 183.5* 19* Maximum SG pressure, psia 1117 1116 212.8* 24* SG safety valves close, psia 1062 1056
- These are typical values for the loss-of-forced RCS flow event.
Table 2.13.3.3.1-1 RCP Seized/Sheared Shaft Assumption Table Power Uprate Current Power Parameter Assumption Level Assumption Initial Core Power, MWt 3735 3478 Core Inlet Temperature, 0F 533 560 Pressurizer Pressure, psia 2098 2300 RCS Flowrate, 106 Ibm/hr 170.2 141.7 Pressurizer Level, % 5444 m SG Pressure, psia 733 SG Level, % NR 7168 _
MTC, x104 Ap/OF -0.20 +0.5 Doppler Coefficient Multiplier 0.85 0.85 Kinetics Maximum Maximump CEA Worth at Trip, %Ap -5.0 -8.55
Table 2.13.4.1.4-1 Comparison of Assumptions for the CEA Drop Event Current Power Level Assumption 3716 MWt Power Reference 3, Parameter Uprate Assumption Table 15.4-9 Initial core power, MWt 3735 3441 Core inlet temperature, OF 543 553 Pressurizer pressure, psia 2250 2250 Pressurizer level, % 67.5 RCS flowrate, qpm}-x464bbhf 4176404-584 396000 Dropped CEA reactivity worth, %Ap -0.15 -0.05 Time for CEA to be fully inserted, sec. 1 1 MTC, 104Ap/ 0 F -4.2 -3.3 Doppler coefficient multiplier 1.15 1.15 Prompt CEA radial distortion upon drop 1.147 1.09 15 minute Xenon radial distortion 1.097 1.043 PPCS Auto --
PLCS Auto -
I
Table 2.13.4.3.2-4 CEA Ejection Peak RCS Pressure Sequence of Events 3716 MWt EPU Time 3716-MWt EPU (sec) Event SetpointlValue 0.00 Mechanical failure of CEDM causes CEA to eject 0.00 CEA fully ejected 0.07 CPC VOPT, % of full power 159 0.08 Maximum core power occurs, % of full power 187.0 0.699 Trip breakers open 1.299 CEAs begin to drop into core 3.412-9 Maximum RCS pressure, psia2519l 4.8 CEA fully inserted, core power reduced to below 10%
power
560 550 540 U: 530 C).
a>
c in e 520 C)
Q a! 510 I.-
is 0 500 0
it: 490 480 470 460 0 600 1200 1800 Time, Seconds Figure 2.13.1.1.4-4 Inadvertent Opening of a Steam Generator Atmospheric Dump Valve Reactor Coolant Temperature vs. Time
625
_fXHot Le 575 V /
A'-_
i Cold Leg
, 550 2
I-I 525.
500 475 0 80 160 240 320 400 TIME, SECONDS Figure 2.13.1.2.3-5 Increased Main Steam Flow with Concurrent Single Failure Reactor Coolant Temperatures vs. Time
1.5 1.45 -
1.4 -
1.35 -
1.3 -
z 0 1.25 -
0 1.2-1.15 -
I 1.1 -
1.05-5 5.5 6 6.5 7 7.5 8 lime, Seconds Figure 2.13.1.3.3-7 IC, SLB, Pre-Trip Power Excursions DNBR vs. Time
2400 2000
-j ct 1600 0
I-z CD I-CO1200 -
LU 0
-j IL.
LU w 800.
O-IL 400 -
0 0 100 200 300 400 500 TIME, SECONDS Figure 2.13.2.2.5-8 Loss of Normal Feedwater Flow Feedwater Flowrate per Steam Generator vs. Time
2400 C) 2200 w
0-5do z
0 0
o 2000 1800 0 10 20 30 40 50 60 TIME, SECONDS Figure 2.13.4.1.3-3 Control Element Assembly Withdrawal at Power RCS Pressure vs. Time
1200 1150 L 1100
-J 0 1050 W
I-i 1000 N
1 950 cn UJ IL 9oo 850 800 0 10 20 30 40 50 60 TIME, SECONDS Figure 2.13.4.1.3-5 Control Element Assembly Withdrawal at Power Pressurizer Water Volume vs. Time
2500
' 2000 W
zw a:
M 1500 0
It W
CL E
0 a00 co O1 0 10 20 30 40 50 60 TIME, SECONDS Figure 2.13.4.1.3-7 Control Element Assembly Withdrawal at Power Steam Flow vs. Time
900%
800% \
3 700% -
LU 0600% \
o -J 1500%
LULL ice )300,m\
0 400% -
300%/
IL 0%
EL200%-
100%
0%
0 1 2 3 4 5 TIME, SECONDS Figure 2.13.4.3.2-2 CEA Ejection Peak Core Power vs. Time
1 DOPPLER EJECTED CEA 0 I .. --..
MODERATOR -
0.
=
I--
z w a-I I--
C.,
-5
-6 0 10 20 TIME, SECONDS Figure 2.13.4.3.2-12 CEA Ejection Reactivity Components vs. Time for Peak RCS Pressure
Attachment 6
- To W3FI-20040096 Revised Sections 2.13.1.3.3.2, Purpose of Analysis and Acceptance Criteria and 2.13.1.3.3.5, Radiological Consequences to W3F1-2004-0096 Page 1 of 2 2.13.1.3.3.2 Purpose of Analysis and Acceptance Criteria The purpose of this analysis is to examine the thermal margin degradation and fuel failure immediately before and after trip during a steam line break event. Longer term effects are discussed in the return to power SLB event. (Section 2.13.1.3.1) Two break locations were analyzed: an inside containment (IC) break and an outside containment (OC) break. The OC break, due to the smaller flow area, does not result in SAFDL violation. The IC break cases do allow some fuel failure.
The criteria for the pre-trip SLB are the following:
. Minimum DNBR 21.26 for no fuel failure (OC). If the IC minimum DNBR < 1.26 then a fuel failure analysis must be performed a Radiological doses s 10CFRIOO limits
- Fuel temperature s fuel centerline melt temperature, as demonstrated by peak LHR < 21.0 kW/ft.
This event is described in Section 15.1.3.3 of the Safety Analysis Report (SAR) (Reference 2.13-1).
to W3F1 -2004-0096 Page 2 of 2 2.13.1.3.3.5 Radiological Consequences With the release path resulting from inside containment SLB's, the fuel failure that would result in the 10CFR100 limits being reached is well in excess of 10% of the pins in DNB (MSLB with LOOP).
The pre-trip SLB event with no LOOP does not result in violation of the DNBR SAFDL. The pre-trip SLB with LOOP, discussed in this section, results in a limited violation of the DNBR SAFDL. The thermal hydraulic conditions present in the core at the time of minimum DNBR in this analysis will be evaluated in combination with the cycle-specific pin census each reload cycle. It will be verified that fewer than 8.0% of the fuel pins will be predicted to experience DNB via the method of statistical convolution.
Similarly, a limited amount of SAFDL violation will occur during the RTP SLB with LOOP (Section 2.13.1.3.1). The extent of this SAFDL violation will be confirmed each reload cycle.
The LOOP RTP SLB will be limited to less than 2% of the pins in violation of the MacBeth DNBR SAFDL.
The fuel pin census applicable to the Pre-Trip phase of the SLB is typical of the HFP power distribution. The fuel pin census applicable to the RTP phase of the SLB is governed by the power distribution that would be present in the core in the N-1 configuration. As these two power distributions are independent of each other, the total fuel failure associated with the SLB event is taken as the summation of the fuel failure for these two scenarios.
The SLB event with no LOOP does not result in SAFDL violations. For the SLB event with LOOP, the total fuel failure is <10.0% of the pins experiencing DNB. Of these, 8.0% are attributable to the pre-trip phase and 2% are attributable to the RTP phase. The radiological consequences resulting from these fuel failure results are:
2-Hour EAB 8-Hour LPZ I Thyroid < 300 rem I <300 rem Whole Body < 25 rem < 25 rem