Text

Supplemental to Amendment Request for Extended Power Uprate
	ML041330175
Person / Time
Site:	Waterford
Issue date:	05/07/2004
From:	Houston B; Entergy Nuclear South
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	W3F1-2004-0035
	Download: ML041330175 (54)
	v • d • e

Entergy Nuclear South Entergy Operations, Inc.

17265 River Road Entergy Killona, LA 70057 Tel 504 739 6440 Fax 504 739-6698 bhousto@entergy.com W3F1 -2004-0035 Bradford Houston Director, Nuclear Safety Assurance Waterford 3 May 7, 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, 'License Amendment Request NPF-38-249 Extended Power Uprate"

2. NRC Letter dated March 24, 2004, "Waterford Steam Electric Station, Unit 3 (Waterford 3) - Request for Additional Information Related to Revision to Facility Operating License and Technical Specifications -

Extended Power Uprate Request (TAC No. MC1355)"

3. NRC Letter dated March 26, 2004, 'Waterford Steam Electric Station, Unit 3 (Waterford 3) - Request for Additional Information Related to Revision to Facility Operating License and Technical Specifications -

Extended Power Uprate Request (TAC No. MC1355)"

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.

By letter (Reference 2), the Nuclear Regulatory Commission (NRC) staff requested additional information related to three review areas. The review areas and number of questions are Piping Integrity and Non-Destructive Examination Section (4), Balance of Plant - Cooling System (7), and Dose Analysis (4). Entergy's response to these 15 questions is contained in the Attachment 1. Additionally, a typographical error, regarding dose analysis, has been identified in Power Uprate Report (PUR) (i.e., Attachment 5 of Reference 1) Section 2.13.3.3.1.5. The whole body results in PUR Section 2.13.3.3.1.5 were reported as < 25 rem when in fact they are < 2.5 rem.

By letter (Reference 3), the NRC staff requested additional information related to three review areas. The review areas and number of questions are Instrumentation and Controls (9), and Quality and Maintenance (5). Entergy's response to these 14 questions is contained in the . Additionally, a correction to table 2.9-1 in PUR section 2.9.4 is required as a result of a detailed design evaluation completed after Reference 1 was submitted. The "after EPU" QSPDS Cold Leg Temperature alarm is changed from 5620 F to 5490F.

x C0

W3FI-2004-0035 Page 2 of 3 Due to the ongoing reanalysis of the extended power uprate small break loss of coolant accident, Entergy has not made a final determination on the need for atmospheric dump valve digital controllers. Therefore, Entergy is deferring its response to questions regarding digital controllers.

In response to Instrument & Controls question 7, Entergy is withdrawing its request to add the word 'indicated" and phrase "an indicated" to the Technical Specifications. Revised Technical Specification mark-ups reflecting this withdrawal will be provided in a future supplement as discussed in the response to question 7.

There are no technical changes proposed. The editorial changes noted (i.e., typographical errors and withdrawal of the use of "indicated" terminology) do not change the responses provided to the original no significant hazards consideration questions included in Reference

1. This supplement includes new commitments as summarized in Attachment 3.

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 May 7, 2004.

Sincerely, BLH/ BM/cbh Attachments:

1. Response to March 24, 2004, Request For Additional Information

2. Response to March 26, 2004, Request For Additional Information

3. List of Regulatory Commitments

W3Fl-2004-0035 Page 3 of 3 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-07D1 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. 0. Box 4312 Baton Rouge, LA 70821-4312 American Nuclear Insurers Attn: Library Town Center Suite 300S 29th S. Main Street West Hartford, CT 06107-2445

Attachment 1 To W3FI-2004-0035 Response to March 24, 2004, Request for Additional Information

Attachment I to W3F1-2004-0035 Page 1 of 32 Response to March 24, 2004, Request for Additional Information Related to the Extended Power Uprate Piping Integrity and Non-Destructive Examination Section Question 1:

Please identify all reactor coolant pressure boundary (RCPB) materials and provide a discussion for each of these materials as to why the proposed extended power uprate (EPU) will not affect material integrity.

Response 1:

The reactor coolant pressure boundary materials are listed in two attached tables. The information in the attached tables has been verified for accuracy and completeness and is to be used in lieu of Final Safety Analysis Report (FSAR) Tables 5.2-3 and 5.2-4. During preliminary review of FSAR Tables 5.2-3 and 5.2-4, several items were identified where corrections to the material designations were needed. Therefore, a complete review and reconstitution of these tables was performed. (This issue was entered into the Waterford 3 10 CFR 50 Appendix B corrective action program.) The results of this review and reconstitution, Tables 2 and 3, are provided here in response to this request for additional information.

At Waterford 3, Alloy 600 and its associated weld metals (Alloys 82 and 182) are used in nozzle type applications in the reactor coolant system pressure boundary and as steam generator tubes. These applications include pressurizer instrument nozzles and heater sleeves, hot and cold leg reactor coolant system (RCS) piping resistance temperature detector (RTD) and pressure measurement/sampling nozzles, reactor vessel head control element drive mechanism (CEDM) and incore instrument (ICI) nozzles and vent line, steam generator instrument nozzles and heat transfer tubes. These applications, except for the steam generator tubes, are nozzle applications in which partial penetration welds were used to attach the nozzles to the inside surfaces of the various primary system components (Reference 1). The weld metals used for the partial penetration welds were Alloys 82 and 182. In addition, there are numerous bimetallic butt welds in the primary pressure boundary that have Alloy 82 or 182 weld metals (Reference 2).

Alloy 600, when highly stressed and exposed to high temperature primary coolant, has experienced intergranular stress corrosion cracking (PWSCC). Waterford 3 has not yet experienced PWSCC in CEDM or ICI nozzles but the plant has experienced PWSCC in pressurizer heater sleeves (one in 2000 and two in 2003) and in instrument nozzles (three hot leg and two pressurizer in 1999 and one hot leg in 2003). Additional nozzles and sleeves of the same heats are still in service at Waterford 3 at the same conditions at which PWSCC previously occurred (Reference 1).

Stress corrosion cracking occurs when three elements occur simultaneously - a susceptible (to SCC) material condition, a tensile stress above some threshold value, and an aggressive environment. As discussed above, Alloy 600 over a range of material conditions and properties is susceptible to PWSCC. Partial penetrations welds produce high tensile residual stresses on the inside surfaces of nozzles and operational stresses further increase these

Attachment 1 to W3F1-2004-0035 Page 2 of 32 stresses, and high temperature primary coolant is sufficient to cause PWSCC in Alloy 600.

The PWSCC of Alloy 600 in its various product forms has been extensively investigated in the laboratory. Analysis of the available data indicate that PWSCC is a thermally activated process that can be described by the expression Time-to-Crack=1/lnitiation Rate= Aacexp(Q/RT) (1)

Where, A = Material constant a = Stress, combination of operational and residual stresses n = exponent on stress, which laboratory data indicates is approximately 4 Q =activation energy (50kcalmole for PWSCC initiation)

R = gas constant (1.103 x 103 Kcal/mol 0R)

T = absolute temperature (OR).

With respect to the planned power uprate at Waterford 3, the only variable in the above expression is temperature. The material conditions of the various Alloy 600 applications were set by the initial tube or forging fabrication or by the welding processes used during fabrication and will not be affected by minor temperature changes. Likewise, the levels of the residual stresses were established by the initial material conditions and fabrication processes.

Locations where PWSCC has occurred in operating plants have been characterized by high residual stresses. Power uprate will not affect the material conditions of any nozzles, sleeves or weld metals and power uprate will not have a significant impact on residual or operational stresses at nozzle or butt-weld locations. There will be minor temperature changes as a result of the uprate. These changes could impact the susceptibility to PWSCC of the various nozzles and butt-welds. The effects of these changes are discussed below.

Power uprate at Waterford 3 will result in an increase in hot leg temperature (THOt) of approximately 0.8 0F (from 600.2 to 601'F) and a decrease of cold leg temperature (TcO0d) of approximately 20F (from 545.0 to 543.00 F). The temperature in the pressurizer will remain unchanged at approximately 653OF. Table 1 gives the estimated service temperatures before and after power uprate for all Waterford 3 locations with Alloy 600 nozzles or Alloys 182 or 82 weld metals.

The highest temperatures that any Alloy 600 nozzles or weld metal will experience will be in the pressurizer. The Alloy 600 in pressurizer applications could be as high as 6530 F, both before and after power uprate. Since temperature will not change, the power uprate will not have an effect, positive or negative, on the potential for PWSCC of Alloy 600 applications in the pressurizer.

With respect to the weld metals in the pressurizer surge nozzle and the spray, safety and relief nozzles, there have not been any events of leakage at Waterford 3 or in any other CE designed pressurizers.

The nominal hot leg temperature will increase from 600.2OF to 601 'F as a result of the power uprate. As indicated above, PWSCC is a thermally activated process, and as a result, an increase in temperature of a specific application will increase the susceptibility to PWSCC of that application. The effect will be a reduction in the remaining lifetime of that application.

Although the temperature increase will be small, equation 1 was used to estimate the effect of to W3F1 -2004-0035 Page 3 of 32 the THOt increase on the Alloy 600. The increase in temperature of 0.80 F will not have a significant effect on the remaining lifetime of the Alloy 600 components exposed to hot leg temperatures. Equation 1 indicates a decrease in remaining lifetime after power uprate of about 3%.

The hot leg Alloy 82/182 welds are also susceptible to PWSCC and the slight temperature increase will result in a small and insignificant increase in the potential for PWSCC.

For the cold leg nozzles and welds, the power uprate will result in exposure to a lower temperature. The temperature decrease will be small (from 545*F to 5430 F) which would increase, using the equation 1 relationship, the remaining lifetimes for the nozzles and welds by approximately 9%.

Alloy 600 nozzles in reactor vessel heads have experienced leaks and occurrences of part-through-wall cracks in recent years. To date, Waterford 3 has not detected, in various inspections, leakage or part-through-wall cracks of any reactor vessel head nozzles or welds.

In accordance with the methods identified in revised NRC order EA-03-009, February 20, 2004, Waterford 3 is classified as a high susceptibility plant. As a result of the power uprate, the temperature in the head region may increase by a modest amount. Assuming this increase is comparable to the expected increase in THOt, the effect would be an insignificant decrease in the time to cracking in these nozzles. The effect should be equivalent to that expected for the hot leg nozzles since the estimated temperature of the nozzles in the Waterford 3 head is near that of the coolant exiting the reactor vessel.

Other locations where Alloy 600 and/or its weld metals are used are in the CEDM motor housings where the upper and lower end fittings are Alloy 600 and the butter and the motor housings and the weld metal are Alloy 82. The coolant temperature at the CEDM motor housing weld locations is not known precisely but is lower than the temperature of the CEDM nozzles, as the welds are above the head. Table 1, for conservatism, indicates temperatures at these locations to be the same as the RPV head temperature.

In summary, the uprate itself will result in an insignificant increase in hot leg temperature which will result in an insignificant increase in susceptibility to PWSCC. Alloy 600 applications at cold-leg temperatures are not likely to experience PWSCC. Thus, the power uprate will not have a significant impact on PWSCC of Alloy 600 at Waterford 3.

References:

1. WCAP-15700 Rev 01, "Alloy 600 Primary Pressure Boundary Penetrations in CEOG Plants CEOG Task 1142", June 15, 2001.

2. CE NPSD-1211-P Rev 1, Identification of Bi-metallic Weld Locations in C-E NSSS Primary Components", March 1, 2001.

to W3F1 -2004-0035 Page 4 of 32 Table I Estimated Service Temperatures for Waterford 3 Alloy 600 and Welds Applications TEMP 0F, before Temp IF, after COMPONENT LOCATION Power Uprate Power Uprate Reactor Vessel CEDM Head Nozzles/Welds 599.7 600.5 ICI Nozzles/Welds 599.7 600.5 Vent LineNVelds 599.7 600.5 Leak-off 599.7 600.5 (Monitoring)Tubes/

Welds Steam Generators Tubes, hot leg 600.2 601 Inst. Nozzles/welds 545 543 Pressurizer Heater Sleeves 653 653 TH Inst. 653 653 Nozzles/Welds LS Temp 653 653 Nozzles/Welds BH Inst 653 653 Nozzles/welds Surge nozzle weld 653 653 Spray nozzles 653 653 welds Safety and relief 653 653 nozzle welds Piping HL RTD 600.2 601 nozzles/welds CL RTD 545 543 nozzles/welds Pres./sampling 600.2 601 nozzles/welds RCP welds 545 543 Surge nozzle welds 600.2 601 Letdown nozzle 545 543 welds Drain nozzle welds 600.2 601 Charging inlet noz. 545 543 welds SD cooling noz. 600.2 601 welds Spray noz. welds 545 543 CEDM Motor End fittings/welds 599.7 600.5 Housings

Attachment 1 to W3F1 -2004-0035 Page 5 of 32 Table 2 REACTOR COOLANT SYSTEM MATERIALS (Sheet 1 of 5)

Component Material Specification Reactor vessel Shell SA-533 Grade B Class 1 Forgings (flanges, nozzles, and safe ends) SA-508 Class 1 or Class 2 Cladding (a) Weld deposited austenitic stainless steel with greater than 5% delta ferrite or NiCrFe alloy Reactor vessel head SB-166 CEDM Nozzles (a)

Instrument nozzles (a) SB-167 and SA-182, F-304 Control element drive mechanism housings Lower (a) SA-1 82 Type 403 stainless steel Special Code Case 1334 with end fittings of SB-166 Upper (a) SA-213 Type 316 stainless steel with lower end fitting of SB-166 and upper end fitting of SA-479 Type 316, vent valve seal of ASTM A276 Type 440C stainless steel seat Closure head bolts SA-540 Grade B24 Pressurizer Shell (a) SA-533 Grade B Class 1 (A gap exists between the original Inconel 600 and replacement Inconel 690 materials on the repaired instrument nozzles and heater sleeves.)

Shell Cladding (a) Weld deposited austenitic stainless steel with greater than 5 percent delta ferrite or NiCrFe alloy Forged nozzles SA-508 Class 2 Instrument nozzles (a) SB-166 Surge and safety valve nozzle safe ends SA-351 Grade CF8M

- to W3F11-2004-0035 Page 6 of 32 Table 2 REACTOR COOLANT SYSTEM MATERIALS (Sheet 2 of 5)

Comnonent Material Specification Heater sleeves SB-167 Heater sleeve plug SB-166 Studs and nuts SA-540 Grade B24 Steam Generator Primary head SA-533 Grade B Class 1 Primary nozzles and safe ends SA-508 Class 1 and Class 2 Primary head cladding (a) Weld deposited austenitic stainless steel with greater than 5 percent delta ferrite Tubesheet SA-508 Class 2 Tubesheet stay SA-508 Class 2 Tubesheet cladding (a) Weld deposited NiCrFe alloy Tubes (a) NiCrFe alloy (SB-163)

Secondary shell and head SA-533 Grade A Class 1 SA-516 Grade 70 Secondary nozzles SA-508 Class 1 and Class 2 Secondary nozzle safe ends SA-508 Class 1 Secondary instrument nozzles SA-106 Grade B Studs and nuts SA-540 Grade B24 and SA-193 Grade B7 Reactor Coolant Pumps Casing (a) SA-351 Grade CF8M Pump cover (lower flange of SA-1 05 driver mount)

Cladding (a) Austenitic steel wire electrodes conforming to requirements of ASME/AWS SFANA-5.4 and SFAIA-5.9 Type 308 or 309 to W3F11-2004-0035 Page 7 of 32 Table 2 REACTOR COOLANT SYSTEM MATERIALS (Sheet 3 of 5)

Component Material Specification Bolts SA-540 Gr B23 Class 4 SA-564, Type 630, H-I 100 (For seal cartridge and seal heat exchanger)

Nuts SA-194 Grade 7 SA-564, Type 630, H-I 100 (For seal cartridge and seal heat exchanger)

Heat exchanger flange SA-240 TP 304 Annealed or SA-182 Grade F304 Reactor Coolant Piping Piping (30" and 42") SA-516 Grade 70 (SA-264 Clad Plate) (b)

Cladding (a) SA-240, 304L Surge line (12") (a) SA-351 Grade CF8M Piping (a)

Pressurizer spray SA-376, TP-304 Shutdown cooling return SA-376, TP-304 Reactor coolant drain SA-376, TP-316 or TP-304 Charging line SA-376, TP-304 Safety injection SA-376, TP-304 Letdown line SA-376, TP-316 or TP-304 Shutdown cooling bypass SA-376, TP-304 Piping Nozzles and Safe Ends (a)

Piping safe ends (30") SA-351 Grade CF8M Surge nozzle forging SA-105 Grade II Surge nozzle safe end SA-351 Grade CF8M Shutdown cooling outlet nozzle forgings SA-105 Grade II to W3Fl-2004-0035 Page 8 of 32 Table 2 REACTOR COOLANT SYSTEM MATERIALS (Sheet 4 of 5)

Component Material Specification Shutdown cooling outlet nozzle safe ends SA-351 Grade CF8M Safety injection nozzle forgings SA-182 F1 Safety injection nozzle safe ends SA-351 Grade CF8M Charging inlet nozzle forging SA-182 F1 Charging inlet nozzle safe end SA-182 F316 Spray nozzle forgings SA-105 Grade II Spray nozzle safe ends SA-182 F316 Letdown and drain or drain nozzle forgings SA-105 Grade II Letdown and drain or drain nozzle safe ends SA-182 F316 Sampling or pressure measurement nozzles SB- 66 Sampling or pressure measurement nozzle safe ends SA-182 F316 RTD nozzles SB-1 66 and SA-182 F316 Sampling nozzle (surge line) SA-182 F316 Valves(a)

Body SA-182 F316, SA-479 Type 316 and SA-351 Grade CF8M Bonnet SA-105 Grade II, SA-351 Grade CF8M, SA-479 Type 316, SA-276 F316, SA-240 Type 316 and SA-182 F316 Disc or Poppet SA-637 Grade 688, SA-240 Type 316, SA-276 F316, SA-479 Type 316, SA-182 F316, SA-351 Grade CF8M, SA-351 Grade CF3 and SA-564 Grade 630 to W3F1 -2004-0035 Page 9 of 32 Table 2 REACTOR COOLANT SYSTEM MATERIALS (Sheet 5 of 5)

Component Material Specification Mechanical Nozzle Seal Assembly (MNSA)

Assembly SA-479 Type 304 Seal(a) Grafoil Grade GTJ Nuclear Grade A Bolting Material SA-453 Grade 660 la) _Materials exposed to reactor coolant (b) _ Material within 4 inches of weld centerline on Field Welds PIOW1 and PIOW2 have been rated with a strength level of 65 ksi per CE Analytical Evaluation Report CENC-1460.

Attachment 1 to W3F11-2004-0035 Page 10 of 32 Table 3 WELD MATERIALS FOR REACTOR COOLANT PRESSURE BOUNDARY COMPONENTS (Sheet 1 of 2)

Material Specification Base Material Weld Material

1. SA-533 SA-533 a. SFA 5.5, (a) E-8018, C3 Grade B Class 1 Grade B Class 1 b. MIL-E-18193, B-4

2. SA-508 SA-533 a. SFA 5.5, E-8018, C3 Class 2 Grade B Class 1 b. MIL-E-18193, B4

3. SA-508 SA-508 SFA 5.5, E-8018, C3 Class 1 Class 2 I

4. SA-516 SA-516 SFA 5.1, E-7018 (b)

Grade 70 Grade 70

5. SA-508 SA-508 SFA 5.1, E-7018 (b)

Class 1 Class 1 S.

I SA-182 SA-516 SFA 5.1, E-7018 F1 Grade 70

7. SA-105 SA-351 SFA 5.14, ERNiCr-3 Grade II CF8M B. SA-182 SA-351 SFA 5.11, ENiCrFe-3 F1 CF8M i9. SA-105 SA-182 SFA 5.14, ERNiCr-3 Grade II F316

10. SB-166 SA-182 Root SFA 5.14, ERNiCr-3 F316 Remaining SFA 5.11, ENiCrFe-3 I

11. SB-167 SA-182 Root SFA 5.14, ERNiCr-3 F304 Remaining SFA 5.11, ENiCrFe-3 I12.

SA-516 SA-351 a. SFA 5.1, E-7018 Grade 70 CF8M b. MIL-E-18193, B-4 I

13. SA-182 SA-182 SFA 5.11, ENiCrFe-3 F1 F316 I

14. SB-166 SA-533 SFA 5.11, ENiCrFe-3 Grade B Class 1 I15. SA-182 SB-167 SFA 5.14, ERNiCr-3 Code Case 1334 to W3F11-2004-0035 Page 11 of 32 Table 3 WELD MATERIALS FOR REACTOR COOLANT PRESSURE BOUNDARY COMPONENTS (Sheet 2 of 2)

Material Specification Base Material Weld Material

16. SA-516 SA-508 SFA 5.5, (a) E-8018, C3 Grade 70 Class 2

17. Austenitic stainless SFA 5.9, ER-308 steel cladding SFA 5.9, ER-309 SFA 5.9, ER-312

18. Inconel Inconel SFA 5.11, ENiCrFe-3 SFA 5.14, ERNiCr-3

19. SA-1 82 SA-508 SFA 5.11, ENiCrFe-3 F-316 Class 2

20. SA-351 SA-508 SFA 5.11, ENiCrFe-3 CF8M Class 2 When welding SB-166 N06690 or SB-167, SB-06690 base materials, ERNiCrFe-7 and ENiCrFe-7 weld materials may be substituted for ERNiCr-3 and ENiCrFe-3.

(a) Special weld wire with low residual elements of copper and phosphorus is specified for the beltline region.

(b) Filler metal used for Field Welds PIOW1 and PIOW2 have been rated with a strength level of 65 ksi per CE Analytical Report CENC-1460.

Attachment 1 to W3F1-2004-0035 Page 12 of 32 Question 2:

Identify dissimilar metal welds within the primary coolant piping system (including vessel safe end welds).

Response 2:

Bimetallic weld joints were identified on primary piping and pressurizer components. No bimetallic weld joints were identified for reactor pressure vessel, steam generator or reactor coolant pump components of the reactor coolant pressure boundary (RCPB). The reactor vessel and steam generators have carbon steel safe ends welded to the low alloy steel inlet and outlet nozzle forgings. The carbon steel safe ends are welded directly to the carbon steel primary piping hot leg and cold leg segments. Therefore, there are no dissimilar metal welds associated with the reactor pressure vessel or steam generator. Similarly, the reactor coolant pump casing is cast stainless steel. Field welds to the pump casing are made directly to stainless steel safe-ends that are shop-welded to the suction and discharge segments of the cold leg piping. Thus there are no dissimilar metal welds associated with the reactor coolant pump.

Bimetallic welded joints are made on the primary piping and branch line connections. These locations are described, along with the quantity for each weld, the base materials and weld filler metal for each weld in the following table:

Part Safe End Nozzle Weld Part Description Qty. Material Material Buttering Filler RCP Suction to RC Pipe 4 SA-516 SA-351 Gr. 182 182 Gr. 70 CF8M RCP Discharge to RC Pipe 4 SA-516 SA-351 Gr. 182 182 Gr. 70 CF8M RC Pipe Surge Nozzle I SA-508 SA-351 Gr. 182 182 Cl. 2 CF8M Letdown & Drain or Drain 4 SA-105 SA-182 182 182 Nozzles Gr. I1 F316 Drain Nozzle I SA-1 05 SA-182 182 182 Gr. II F316 _____

Charging Inlet Nozzle 2 SA-1 82 SA-182 182 182 F1 F316 Safety Injection Nozzle 4 SA-182 SA-182 182 182 F1 F316 Shutdown Cooling Nozzle 2 SA-105 SA-351 Gr. 182 182 Gr. II CF8M Spray Nozzle 2 SA-G SA-182 182 182

_ __ __ _ _ _ _ __ _ _ _ _ _ _ G r. ll F316_ _ _ _ _ _ _ _ _

All of the weld joints listed in the table above are shop welded and inspected. A specification for field assembly of pressure piping components for CE supplied nuclear power plants

Attachment 1 to W3F1-2004-0035 Page 13 of 32 provided requirements for assembly and welding of all primary piping components. All of the piping components that are welded to stainless steel piping or stainless steel RCP casing have stainless steel safe-ends welded on in the shop. Therefore, there are no bimetallic welds made as field welds during installation of the RCPB components or primary piping systems.

Bimetallic welded joints are made on the pressurizer at the following locations:

Nozzle Safe End Nozzle Weld Part Description Qty. Material Material Buttering Filler Surge Nozzle I . SA-508 SA-351 182 182 l_ Cl. 2 CF8M Spray Nozzle I SA-508 SA-182 182 182 C1. 2 F316 Safety Valve Nozzles 3 SA-508 SA-351 182 182

_. Cl. 2 CF8M II The pressurizer instruction manual for Waterford 3 requires field welds for all of the nozzle connections to be performed in accordance with approved erection procedures. None of the field installation welds to the pressurizer will be bimetallic welds, since all of the nozzles either have shop welded stainless steel safe ends or are small diameter nickel base alloy nozzles with stainless steel socket weld safe ends.

Question 3:

Identify any mitigating steps that have been taken to control primary water stress-corrosion cracking or any other degradation mechanism in the RCPB system.

Response 3:

Entergy has taken "proactive repair" as a mitigation step to reduce PWSCC impact on Alloy 600 components at Waterford 3 in addition to the ongoing inspection and repairs required by the Order. Component repair or replacement at Waterford 3 has utilized Alloy 690 materials and its compatible weld materials (Alloy 152 and Alloy 52).

Entergy has proactively repaired five small bore instrument nozzles using Alloy 690/1-52/1-152 materials which are believed to have a higher resistance to PWSCC. The nozzles that were proactively repaired include two pressurizer instrument nozzles and three hot leg instrument nozzles.

There have been a total of nine RCS nozzle pressure boundary leaks associated with Alloy 600. Two pressurizer steam space nozzles (weld repair), one pressurizer heater (plugged),

two pressurizer heater sleeves (mechanical nozzle seal assemblies (MNSA's) installed during RF12), and four hot leg nozzles (weld repairs). Entergy has used the Alloy 690/1-52/1-152 materials for the welded repairs.

to W3Fl-2004-0035 Page 14 of 32 Question 4:

If mitigating steps have been taken, discuss why the EPU will not adversely affect the mitigating steps that have been taken.

Response 4:

No activities planned in support of the EPU will hamper the ability to perform inspections of the reactor vessel head penetrations, hot and cold leg penetrations, or pressurizer penetrations as were performed prior to EPU.

The EPU will not affect the new A-690/1-52/1-152 materials that were used in the hot leg nozzle repairs. The impact due to a slight increase in nominal hot leg temperature (0.8 0F) on the new A690 materials is negligible as explained below:

'The annealed Alloy 690 retains more than 90% of its room temperature tensile properties (yield and tensile strengths and elongation) up to 800 01" (Ref. 1.0)

Considering that RCS temperature is below 8000F, the impact due to EPU is negligible.

A-690/1-5211-152 is generally accepted as a better material then A-600/1-82/1-182. As discussed above, in response to question 1, the adverse impact of EPU on A-60011-8211-182 is insignificant thus the impact of EPU on A-690/1-5211-152 is also expected to be insignificant.

The pressurizer will continue to operate at the same temperature and pressure as before uprate therefore the A-690/1-52/1-152 materials and MNSA's that were used in pressurizer nozzle repairs will not be impacted by EPU.

Reference:

1. MRP-111, Materials Reliability Program Resistance to Primary Water Stress Corrosion Cracking of Alloy 690, 52 and 152 in Pressurized Water Reactors",

Balance of Plant - Cooling System Question 5:

Please explain how the equipment and floor drainage system is impacted by the EPU.

Response 5:

Power uprate has no impact on the design and operation of the equipment and floor drain systems. Equipment drain lines, floor drain lines, sumps, sump pumps are sufficiently sized to handle normal and anticipated transient conditions (i.e., postulated system leakage or line breaks) expected for power uprate. There are no significant changes in the operating parameters in systems with postulated line breaks, and there are no systems in which the new expected operating parameters exceed the design ratings of the piping and/or equipment.

to W3F1 -2004-0035 Page 15 of 32 The non-safety related equipment and floor drain systems consists of all piping from equipment and floor drains to the drain sumps, the sump pumps, and all piping necessary to carry the potentially radioactive or non-radioactive effluents through separate subsystems.

Potentially radioactive drainage is collected in the drain sumps in each building and discharged to the appropriate radwaste processing system. Drainage from non-radioactive sources, such as the turbine building or roof drains, is processed by the industrial waste systems or discharged directly offsite. The implementation of power uprate does not add any new sources of potentially contaminated leakage, nor does it create any new flow paths or routes that would allow the contamination of drainage systems designed for uncontaminated fluids.

Liquids leaking from process systems, liquids used during cleaning activities, liquid spills from maintenance activities, and liquids generated in the radio-chemistry laboratory enter the equipment and floor drain system during all plant operating modes. EPU does not directly impact the source and quantities of liquids that enter the equipment and floor drains (from the above sources).

Internal plant flooding due to postulated piping failures has been considered in the design of the equipment and floor drain systems. In addition, provisions have been made to essential equipment (i.e., equipment, instrumentation, and controls in the pump safe guard rooms RAB elevation, -35 feet) to ensure their elevation is above calculated flood levels. The initiation and consequences of postulated flooding events (as previously investigated) will not be impacted by power uprate. The design conditions and physical arrangement of those piping lines postulated for failure remain unchanged for power uprate and no new initiating events are postulated Question 6:

Section 2.5.5.3 of the application, addresses the impact of EPU on the Reactor Auxiliary Cooling Water Systems. In the evaluation section, it is stated that "Under EPU conditions, the maximum heat load from containment during a loss-of-coolant accident (LOCA) is lower than the maximum heat load considered on the component cooling water system (CCWS) and auxiliary CCWS (ACCWS) systems under pre-Uprate conditions. The containment heat load under EPU conditions was determined using a more detailed evaluation of the containment heat loads than was performed previously under Pre-EPU conditions.'

a. Provide the pre-EPU and post-EPU heat loads for the CCWS and ACCWS systems.

b. Explain, in detail, the differences in the methods and assumptions used to calculate the pre-EPU and post-EPU heat loads. Identify what conservatism, if any, has been removed, and provide appropriate justification for the changes made in the way the heat load was calculated for post-EPU plant operation.

c. Section 2.5.5.4 of the application addresses the impact of EPU on the Ultimate Heat Sink (UHS). The EPU evaluation arrived at lower peak heat loads than those used in the current UHS analysis, due to lower maximum CCWS heat loads that resulted from a more detailed evaluation of post-accident heat loads. Please discuss how the UHS analyses were performed, and identify any differences in the analysis methods, assumptions or inputs between the pre-EPU evaluation and the post-EPU evaluation.

- - - to W3F1I-2004-0035 Page 16 of 32 Response 6a:

The pre-EPU and post-EPU accident heat loads for the CCW and ACCWS systems are provided below:

of Units Pre-EPU Heat Transferred Post-EPU Heat Transferred Equipment Operating (Btu/hr

106) (Btulhr

106)

Shutdown Heat 1 43.87 Note 1 Exchanger Containment 2 136.57 150.0 (Notes 1, 2)

Fan Coolers Diesel 1 9.7 9.7 Generators HPSI Pumps 1 0.1 0.1 LPSI Pumps 1 0.1 0.1 Containment 1 0.1 0.1 Spray Pumps Chillers 1 5.1 5.1 Fuel Pool Heat 1 11.4 20.34 Exchanger Note 1: Maximum containment heat load combines the heat loads from both the shutdown cooling heat exchanger and containment fan coolers.

Note 2: The maximum calculated heat load was 146.8 x 10r6 Btu/hr. Itwas rounded up to 150 x 106 Btu/Hr for conservatism.

Response 6b & 6c:

The pre-EPU accident heat loads are provided in FSAR Table 9.2.3 and FSAR Figure 9.2-4.

The accident auxiliary heat loads will remain unchanged for EPU. These plant auxiliary loads are the high pressure safety injection (HPSI) pump, low pressure safety injection (LPSI) pump, containment spray pump, diesel generator and essential chiller. The accident heat loads in containment and assumed for spent fuel pool cooling have changed for EPU. The peak accident heat load for EPU in containment (i.e., heat load removed for the shutdown cooling heat exchanger and two containment fan coolers) has decreased from 180.44 x 106 Btu/Hr to 150 x 106 Btu/hr. The inputs and assumptions that changed from the pre-EPU analysis and the post-EPU analysis include the following:

The thermal power was increased to 3716 MWt.

Revised mass and energy release data (same as used in support of Amendment 165, dated July 6, 2000) was used for the EPU analysis of the containment heat load on the ultimate heat sink system. The mass and energy release data is a key input for the GOTHIC analysis.

The EPU containment analysis was performed using GOTHIC and the pre-EPU analysis was performed using CONTEMPT.

The post-EPU containment heat load was calculated using GOTHIC computer code and EPU mass and energy release data generated by Westinghouse for six different loss of coolant accident (LOCA) scenarios: Hot leg break, reactor coolant pump (RCP) suction leg break, and reactor coolant pump (RCP) discharge leg break assuming both maximum and minimum

Attachment 1 to W3Fl-2004-0035 Page 17 of 32 safety injection flow for all three break locations. The post-LOCA mass and energy release data used in the EPU analysis of the containment heat load on the ultimate heat sink system is the same as that used in support of the current analysis of record for the post-LOCA containment pressure and temperature response analyses approved via Amendment 165, dated July 6, 2000. At the time Amendment 165 was approved, an update of the containment heat load on the ultimate heat sink system analysis was not required to support plant operations. This analysis is now being updated to support the EPU.

The total containment heat load on one train of the ultimate heat sink system was calculated by adding the heat addition to CCW from the containment fan coolers (CFCs) (both CFCs in one train assumed operable) and the shutdown cooling system heat exchanger which is used to cool the containment spray flow in the recirculation mode (suction from the safety injection sump). The results showed that the maximum heat of 146.8 x 106 Btu/Hr removed from the containment occurs following a hot leg break during the blowdown phase of the event. This containment heat load was conservatively rounded to 150.0 x 106 Btu/hr. This heat load represents the heat load on two CFCs in the operable train. The CFC performance and the timing of the CFC operation were chosen such to maximize the heat removal rate by the CFCs. The decrease in required heat removal from containment was primarily due to the revised post-LOCA mass and energy release data (same as used in support of Amendment 165, dated July 6, 2000) which is an important factor in determining containment heat load on the UHS.

The peak heat load assumed for spent fuel pool cooling during an accident was increased from 11.4 x 106 Btu/Hr to 20.34 x 106 Btu/Hr. The resultant increase in spent fuel pool heat load is based on the following new inputs and assumptions:

Thermal power starting at Cycle 14 was increased to 3716 MWt.

The heat load assumed was increased to account for future refueling outage durations of greater than or equal to 15 days. The pre-EPU analysis currently assumes a minimum of 30 day refueling outage duration.

Maximum background heat in the storage pool was increased assuming stored fuel assemblies from 21 refueling batches. The pre-EPU analysis currently assumes stored fuel assemblies from 11 refueling batches.

The maximum fuel assembly offload was increased from 96 to 108 assemblies to bound the fuel management expected for EPU.

The increase in spent fuel pool cooling heat load resulted in decreasing the time required for restoration of spent fuel pool cooling during the accident from approximately 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months will still allow sufficient time for operators to manually align the spent fuel pool cooling system onto the ultimate heat sink for cooling post-accident.

Question 7:

Section 2.5.5.5 of the application addresses the impact of EPU on the emergency feedwater system (EFS). In the Evaluation Section the licensee states: "Although EPU will cause an increase in the decay heat, engineering evaluations for the EPU determined that no change to the EFS performance (flow rate and delivery pressure) is required." Please provide additional to W3F1-2004-0035 Page 18 of 32 details on the analysis used to support the above statement. Explain how the increased heat load is accommodated by the EFS without any change in the system performance requirements.

Response 7:

The emergency feedwater system (EFS) is described in Final Safety Analysis Report (FSAR)

Section 10.4.9. The FSAR section states that the EFS system must deliver at least 575 gpm to the steam generators, at the first main steam safety setpoint (MSSV) pressure, during loss of feedwater (LOFW) events. To accommodate a single failure of any EFS pump, the EFS performance capability analysis demonstrates that either the EFS turbine drive pump or both EFS motor driven pumps can deliver the 575 gpm to the steam generators. This performance capability of the EFS is provided as an input into the pre-EPU events described in FSAR Sections 15.2 and demonstrated acceptable results.

EPU does not recommend any changes to the relieving pressure setpoints for the first or any other MSSV, therefore the capability of the EFS remains the same for EPU. With the current system performance capability, all acceptance criteria for the post-EPU events described in the PUR Section 2.13.2 were met.

The FSAR Chapter 15 events for which EFS performance is of interest are the Loss of Condenser Vacuum (PUR Section 2.13.2.1.3), Loss of Main Feedwater Flow (PUR Section 2.13.2.2.5), Feedwater Line Break (PUR Section 2.13.2.3.1), and Loss of Main Feedwater Flow with a single active failure in the Steam Bypass Control System (PUR Section 2.13.2.3.2). Note the EPU analyses are conducted with the CENTS transient simulation code, as discussed in PUR Section 2.13.0.1. CENTS provides a realistic best estimate calculation. Conservatism required in non-LOCA analyses is provided by the selection of transient specific initial conditions and plant data. Pre-EPU analyses used the CESEC code.

Loss of Condenser Vacuum:

This is of interest since it is the peak pressure Infrequent Event. For EPU conditions, calculated peak reactor coolant system (RCS) pressure is 2732 psia, compared to 2708 psia pre-EPU; this meets the 2750 psia acceptance criterion. EFS performance has negligible impact on the acceptance of this event, as EFS flow reaches the steam generators (SGs) at 60.2 seconds, whereas peak primary and secondary pressures occur in the first 20 seconds of the event. Analyzed SG inventory is approximately 90,000 Ibm at this time, well over half the initial inventory, thus SG dryout is not challenged.

Loss of Main Feedwater:

This event involves a rapid reduction in secondary inventory due to the loss of main feedwater. PUR Figure 2.13.2.2.5-10 provides the SG secondary liquid mass as a function of time. For EPU conditions, minimum inventory of 34,240 Ibm occurs at 204.9 seconds, per Table 2.13.2.2.5-2. Due to differences in initial conditions (Table 2.13.2.2.5-1), this event as analyzed for EPU is slightly less challenging to SG dryout than for pre-EPU conditions. For pre-EPU conditions, the minimum SG inventory is 18,100 Ibm at 100 seconds.

to W3Fl-2004-0035 Page 19 of 32 Feedwater Line Break (FWLB):

This event is analyzed to demonstrate that peak RCS pressure for this Limiting Fault Event is maintained below a 3000 psia acceptance criterion. Maximum RCS pressure for EPU conditions was calculated to be 2753 psia, compared to 2750 psia previously.

Figure 2.13.2.3.1-9 shows the SG liquid mass as a function of time for the large FWLB.

The SG connected to the ruptured feedwater line empties at 26.95 seconds for EPU conditions, as documented in Table 2.13.2.3.1-2. The pre-EPU analysis shows that SG emptying at 16.6 seconds into the event. For the analysis of the large FWLB, a very conservatively low setpoint for the low SG level trip signal is assumed, thus the EFS actuation signal only occurs at 24.1 seconds and EFS flow is initiated only at 84.1 seconds. Figure 2.13.2.3.1-9 demonstrates SG dryout does not occur in the unaffected SG even with the extremely conservative assumptions for SG Low Level for the EFS actuation signal. Thus, the EFS flow does not impact the peak pressure response for this event.

PUR Figure 2.13.2.3.1-28 presents the SG inventory response for the small FWLB. Per Table 2.13.2.3.1-4, EFS flow is initiated to the SG at 86.6 seconds. It is seen that at the time of EFS initiation that more than 40,000 Ibm of inventory are remaining in the SG. As that case was run concentrating on peak steam generator pressure results, EFS flow was not actually initiated in the simulation. However, as the large FWLB result demonstrates that the depletion of the SGs terminate upon EFS delivery, and the presence of a significant amount of inventory at the time that EFS delivery would commence, it is concluded that SG dryout does not occur for the small FWLB.

Loss of Main Feedwater with an Active Failure in the Steam Bvpass Control System (SBCS):

PUR Figure 2.13.2.3.2-10 demonstrates that SG dryout will not occur for this Limiting Fault event. Failure of the SBCS produces the minimum steam generator inventory in the shortest period of time after a loss of main feedwater flow. A minimum SG inventory of 4,476 Ibm is predicted at 115 seconds into the event for EPU conditions, as documented in Table 2.13.2.3.2-2. Pre-EPU predicted inventory was slightly larger (7,530 Ibm at 90 seconds). EFS flow reaches the SG's at 100.9 seconds, prior to the time of minimum inventory.

Thus, review of the EPU analytical results presented in PUR Section 2.13.2 demonstrates the continued ability of the EFS to fulfill its mitigation responsibilities for analyzed FSAR Chapter 15 events. Thus, as discussed in PUR Section 2.5.5.5, no change to EFS performance (e.g., flow rate and delivery pressure) is required and these analyses demonstrate that the EFS pumps continue to provide the minimum flow rate necessary to support safety analyses.

Question 8:

In Section 2.5.5.5 it is also stated that "The increased demand for condensate requirements for cooldown as a result of EPU can be met with the current system configuration and to W3Fl-2004-0035 Page 20 of 32 operation." Please provide both the total inventory required by EFS for cooldown, and the total inventory available for use by the EFS for the post-EPU plant.

Response 8:

Technical Specification 3/4.7.1.3 for the condensate storage pool (CSP) requires a minimum contained volume of 91% indicated level. A minimum 91% indicated level ensures that 170,000 gallons is available for EFS usage to cool the reactor coolant system (RCS) to shutdown cooling entry conditions following any design basis accident. Assuming a loss of offsite power and remaining for two hours at hot standby, the EFS requires approximately 142,100 gallons from the CSP to perform a cooldown to shutdown cooling entry conditions at the current power level and requires approximately 165,750 gallons from the CSP to perform a cooldown to shutdown cooling entry conditions at post-EPU power level. Makeup to the CSP is provided by the wet cooling tower (WCT) basin if an additional two hours is required to remain at hot standby prior to initiating shutdown cooling for both pre-EPU and post-EPU power levels.

Question 9:

As a result of plant operation at the proposed EPU level, the decay heat load for any specific discharge fuel scenario will increase. In Section 2.5.5.1 of the application,- it is stated that for power uprate conditions the maximum bulk pool temperature limit of 140'F for normal refueling outage will not be exceeded and that the maximum bulk pool temperature limit of 155-F for full core offload will not be exceeded. However, a detailed discussion of the Spent Fuel Pool (SFP) evaluations performed to support the above statements was not provided.

Based on the plants current SFP analysis, the peak fuel pool temperature for the normal discharge case is 139.4'F, and for the full core discharge is 151 .6-F. Please provide the following information for both pre-EPU, and post-EPU operation.

a. Please provide, the methodology and assumptions (i.e. number of fuel assemblies off loaded, hold time, number of previously discharged fuel assemblies in the SFP, UHS temperature, etc.) used in the SFP thermal-hydraulic analysis for each scenario analyzed.

Also, provide the SFP bulk temperature results for both the pre-EPU and post-EPU conditions, and identify any changes made to the SFP analysis for the EPU evaluation, the SFP heat loads and corresponding peak calculated temperatures during planned (normal) refueling outages under partial and full core off-load conditions, and unplanned (abnormal) full-core offload outages for both pre-EPU and post-EPU conditions.

b. In the event of loss of the SFP cooling system, what impact does the EPU have on the time for the SFP temperature to rise from the maximum bulk pool temperature limit of 140F to boiling at 212EF. Confirm that the time to boil-off the post-EPU plant is sufficient to allow mitigative actions and that make-up water requirements are within system capacity.

Response 9a:

The design bases for the spent fuel pool (SFP) cooling system are discussed in FSAR Section 9.1.3 and FSAR Table 9.1-3. FSAR Section 9.1.3 states in part that the SFP cooling system, assuming a single failure, will maintain the spent fuel storage pool below 1400 F to W3F11-2004-0035 Page 21 of 32 assuming a partial core discharge is placed into spent fuel storage pool after reactor shutdown. It also states the SFP cooling system, without assuming a single failure, will maintain the spent fuel storage pool below 1550F assuming a full core is discharged into spent fuel storage pool after reactor shutdown. To ensure the design bases spent fuel storage pool temperatures requirements are not exceeded, procedural controls are in place to limit the amount of fuel assemblies that can be placed in the spent fuel storage pool following a reactor shutdown. The current limits are:

Partial Core Offload Operating Conditions: Primary Spent Fuel Pool Heat Exchanger in Service Spent Fuel Pool Pump Flow 2 2000 gpm Component Cooling Water Flow 2 1600 gpm Component Cooling Water Temperature 5900F Time After Shutdown Limit 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 5 79 Assemblies 80 hours9.259259e-4 days 0.0222 hours 1.322751e-4 weeks 3.044e-5 months 5 82 Assemblies 88 hours0.00102 days 0.0244 hours 1.455026e-4 weeks 3.3484e-5 months 5 85 Assemblies 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months 5 88 Assemblies 104 hours0.0012 days 0.0289 hours 1.719577e-4 weeks 3.9572e-5 months 5 90 Assemblies 112 hours0.0013 days 0.0311 hours 1.851852e-4 weeks 4.2616e-5 months 5 93 Assemblies 120 hours0.00139 days 0.0333 hours 1.984127e-4 weeks 4.566e-5 months 5 96 Assemblies Full Core Offload Operating Conditions: Primary Spent Fuel Pool Heat Exchanger in Service Spent Fuel Pool Pump Flow 2 4000 gpm Component Cooling Water (CCW) Flow 2 5000 gpm Total Amount of Assemblies Transferred - 217 Time After Shutdown CCW Temperature 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 5 890 F 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months s 950 F 120 hours0.00139 days 0.0333 hours 1.984127e-4 weeks 4.566e-5 months 5 1000 F Post-EPU does not recommend a design basis change on the spent fuel pool cooling system.

The spent fuel storage pool temperature limits being maintained currently will not be changed for EPU. EPU will impose stricter restrictions for the full core discharge due to the higher spent fuel decay heat. However, the amount of spent fuel assemblies that can be offloaded for a partial core discharge to ensure the temperature limits will not be exceeded will be increased for EPU based on the following.

The assumed decay heat values used for the current limits are based on standard ANSI IANS- 5.1 - 1979, 'Decay Heat Power in Light Water Reactors". The post-EPU decay heat fractions are based on Branch Technical Position ASB 9-2 'Residual Decay Energy for Light-Water Reactors for Long Term Cooling.

to W3Fl-2004-0035 Page 22 of 32

The delivery capabilities of the SFP cooling pump and CCW pump were increased based on improved system modeling which increased the heat removal capacity of the SFP cooling system for a partial core discharge from 22.1 x 106 Btu/Hr to 29.0 x 106 Btu/Hr.

The SFP cooling design basis currently assumes a power level of 3661 MWt or 8.0%

above the original license power of 3390 MWt. This was done to prepare for a future EPU.

The proposed EPU therefore only increases the design basis thermal power limit from 3661 MWt to 3716 MWt.

These design basis changes for the SFP cooling system were performed in support of Licensing Amendment 144 dated 7/10/98 (TAC No. M98325). However, the procedural limits were not changed because the limits provided in the procedure were considered bounding.

Since EPU will increase the assumed power level from 3661 MWt that is given in the current SFP cooling design bases to 3716 MWt, new spent fuel offload limits will be established. The proposed spent fuel offload limits for EPU that will be placed in the plant procedure will be the following:

Partial Core Offload Operating Conditions: Primary Fuel Pool Heat Exchanger in Service Spent Fuel Pool Pump Flow 2 2440 gpm Component Cooling Water Flow 2 2768 gpm Component Cooling Water Temperature s900F Time After Shutdown Limit 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 5 91 Assemblies 80 hours9.259259e-4 days 0.0222 hours 1.322751e-4 weeks 3.044e-5 months s 95 Assemblies 88 hours0.00102 days 0.0244 hours 1.455026e-4 weeks 3.3484e-5 months s 99 Assemblies 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months 5 102 Assemblies 104 hours0.0012 days 0.0289 hours 1.719577e-4 weeks 3.9572e-5 months 5 106 Assemblies 112 hours0.0013 days 0.0311 hours 1.851852e-4 weeks 4.2616e-5 months s 110 Assemblies 120 hours0.00139 days 0.0333 hours 1.984127e-4 weeks 4.566e-5 months s 113 Assemblies Full Core Offload Operating Conditions: Primary Fuel Pool Heat Exchanger in Service Spent Fuel Pool Pump Flow 2 3650 gpm Component Cooling Water (CCW) Flow 2 5000 gpm Component Cooling Water Temperature s90'F Total Amount of Assemblies Transferred - 217 Time After Shutdown Limit 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 5 185 Assemblies 80 hours9.259259e-4 days 0.0222 hours 1.322751e-4 weeks 3.044e-5 months 5 193 Assemblies 88 hours0.00102 days 0.0244 hours 1.455026e-4 weeks 3.3484e-5 months 5 200 Assemblies 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months ' 208 Assemblies 104 hours0.0012 days 0.0289 hours 1.719577e-4 weeks 3.9572e-5 months 5 215 Assemblies 106 hours0.00123 days 0.0294 hours 1.752645e-4 weeks 4.0333e-5 months 217 Assemblies

- - - to W3Fl-2004-0035 Page 23 of 32 Response 9b:

Per FSAR Section 9.1.3.3, it states that although it is unlikely that cooling would be lost to the spent fuel storage pool, it would take approximately 6.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for the bulk pool temperature to rise from 133 0F to 212'F. This assumes a partial core discharge with a maximum heat load of 29.44 x 106 Btu/Hr. The maximum heat load allowed in the spent fuel pool for a partial core discharge will be slightly less than the 29.44 x 106 Btu/Hr for EPU (see response to Question 9a above), therefore the time for the spent fuel pool to reach boiling will remain essentially unchanged. This time period allows for sufficient time for the operators to intervene and line up an alternate source of replenishing the pool inventory and removing the decay heat.

Question 10:

In Section 2.5.8.1 of the application, it is stated that "The fuel oil consumption rates were based on actual measured rates as opposed to vendor supplied rates determined when the emergency diesel generators (EDGs) were new. The consumption rates used in the evaluation were less than the vendor-supplied rates used in the analysis of record, but greater than the measured rates." Please provide the following information:

a. The consumption rate assumed in the current analysis of record.

b. The measured consumption rates, and conditions under which they were measured.

c. The consumption rate assumed in the EPU evaluation, and the corresponding fuel oil requirements for post design basis accident operation.

d. A detailed discussion on how the consumption rates used for the EPU analysis was selected. Include discussions uncertainties associated with the measured data, and margins applied to the assumed consumption rate.

Response l0a:

The pre-EPU fuel oil consumption rate of the emergency diesel (EDG) at full load (4400 KW) is 5.1293 gpm. This is based on EDG vendor supplied information and corrected to the minimum specific gravity specified by Technical Specifications (4.8.1.1.2c).

Response lOb:

Measured consumption rates as trended by engineering indicate EDG fuel oil consumption rates are less than the 5.1293 consumption rate used in the pre-EPU analysis. EDG surveillance trends for average (raw) consumption rate, average EDG load, nominal full load (i.e., 4400 KW) consumption rate, and maximum consumption rate (including potential instrument uncertainty) are provided below:

to W3Fl-2004-0035 Page 24 of 32 EDG 'A' Nominal Average (Raw) Average Full Load Maximum Date Consumption EDG (4.4 MW) Consumption (gpm) Load Consumption (gpm)

(MW) (gpm) 8/5/2002 4.794 4.28 4.928 4.990 1/20/2003 4.638 4.24 4.813 4.875 3/17/2003 4.656 4.27 4.794 4.856 8/4/2003 4.524 4.15 4.793 4.855 12/22/2003 4.546 4.25 4.709 4.771 2/16/2004 4.643 4.24 4.818 4.880 3/15/2004 4.598 4.18 4.845 4.907 4/12/2004 4.656 4.27 4.799 4.861 Average 4.632 4.23 4.812 4.874 EDG 'B' Nominal Average (Raw) Average Full Load Maximum Date Consumption EDG (4.4 MW) Consumption (gpm) Load Consumption (gpm)

(MW) (gpm) 7/22/2002 4.645 4.21 4.852 4.914 1/6/2003 4.628 4.26 4.780 4.842 4/28/2003 4.762 4.25 4.926 4.988 7/21/2003 4.759 4.36 4.801 4.863 8/18/2003 4.859 4.26 5.020 5.082 10/14/2003 4.569 4.20 4.789 4.851 3/1/2004 4.512 4.12 4.820 4.882 3/29/2004 4.689 4.24 4.867 4.929 Average 4.678 4.24 4.857 4.919 EDG day tank level vs. elapsed time data was collected for the EDG surveillance runs on the above dates. Data was recorded between re-fills of the EDG day tank during steady state EDG operation between 4000 KW and 4400 KW. The EDG surveillance tests took place during a relatively short time span so that changes in ambient and instrument operating temperatures were small enough to have a negligible impact on the results. All of the data sets taken for the date shown were then averaged to determine the actual EDG fuel oil consumption rate. The maximum consumption rate shown above includes measurement uncertainty added to the measured consumption rates adjusted for 4400 KW.

- to W3FI-2004-0035 Page 25 of 32 Response 10c:

The pre-EPU EDG load summary is provided in FSAR Table 8.3-1. EPU will require longer operating times for ultimate heat sink equipment during a design basis accident. The post-EPU EDG load summary is provided in the Tables below. As a result, EPU would have required additional fuel oil to be stored onsite to meet the seven day requirement if the assumed EDG fuel oil consumption rate remained unchanged for EPU. However, the EDG fuel oil storage tank is already being maintained at its capacity to meet the pre-EPU fuel oil requirements. Therefore, the assumed post-EPU fuel oil consumption rate of the EDG at full load was reduced to 5.0 gpm based on recent EDG fuel oil consumption rate trend data. The EDG 'B' surveillance performed on August 18, 2003, was considered an invalid trend as the previous and subsequent surveillances indicate fuel oil consumption rates below 5.0 gpm.

However, as committed in the November 13, 2003, submittal, a test will be performed to confirm that the fuel oil consumption rate for the EDGs is less than or equal to 5.0 gpm at full load. (See commitment for PUR Section 2.5.8.1.) The test will prescribe the plant conditions and include all appropriate process uncertainties and correct for the minimum requirements for fuel oil as stated in the Technical Specifications.

Attachment I to W3Fl-2004-0035 Page 26 of 32 Emergency Diesel Generator "A" LOCA MSLB Shutdown Time Sequence Load (KW) Load (KV) Load (KW) 0 - 1Os Generator Starts 0 0 0

.10- 10.5s Load block la 338.73 338.73 324.30 10.5- 1Is: Load block lb 338.73 338.73 329.25 11 - 11.5s: Load block 1c 365.20 365.20 355.72 11.5- 15s: Load block Id 1019.07 1019.07 355.72 15 - 17s: Load block 2a 1064.58 1064.58 401.23 17 - 27s: Load block 2b 1886.36 1886.36 1207.96 27 - 39s: Load block 3 2540.74 2540.74 1551.32 39 - 51s:Load block 4 2758.04 2758.04 1719.95 51 - 60s: Load block 5a 3419.80 3419.80 2381.71 60- 120s: MOVs DE 3404.05 3404.05 2380.38 120 - 178s: Load block 5b 3477.53 3477.53 2453.86 178-201s: Load block 6a 3498.91 3498.91 2475.24 201-210s: Load block 6b 3499.60 3499.60 2475.93 210-229s:Load block 6c 3539.48 3539.48 2515.81 229-30m: Load block 6d 3955.85 3955.85 2895.12 30m-30m25s: Auto Load block 4139.39 4139.39 3457.44 30m25s-75m:Manual loading 4138.69 4138.69 3457.44 75m-90m: LPSI DE 3791.62 3791.62 3457.44 90m-2h: Turb. Aux DE 3721.46 3721.46 3387.28 2h-2h50s: Manual MOVs 3722.12 3722.12 3387.28 2h50s-4hr MOV DE 3721.46 3721.46 3387.28 4h-6h: EFW DE 3416.62 3416.62 3280.69 6h-8h: Manual loading (SF pump) 3457.32 3457.32 3321.39 8h-14h Manual load: DE Charging Pump, Charging Room AH, DE BA pump 3365.41 3365.41 3229.48 14h-17h Manual load: DE CCW M/U 3338.77 3338.77 3202.84 17h-4d Manual load: DE EDG Xfer P 3317.33 3317.33 17h-7d: DE EDG Xfer pump 3181.40 4d-7d: WCT fans 5-8 DE 3221.65 4d-7d:Manual loading DE HPSI,CS EN LPSI 2920.60 DE = Deenergize EN = Energize to W3F1-2004-0035 Page 27 of 32 Emeraenev Diesel Generator "B" LOCA MSLB Shutdown Time Sequence Load (KW) Load (KW) Load (KW) 0 - 1Os Generator Starts 0 0 0 10 - 10.5s Load block Ia 322.95 322.95 306.83 10.5 - I11s: Load block lb 322.95 322.95 311.68 11 - 11.5s: Load block 1c 349.07 349.07 337.80 11.5- 15s: Load block Id 1002.78 1002.78 337.80 15 - 17s: Load block 2a 1048.29 1048.29 383.31 17-27s: Load block2b 1866.69 1866.69 1186.81 27 - 39s: Load block 3 2538.59 2538.59 1548.41 39 - 51s:Load block 4 2755.81 2755.81 1717.04 51 - 60s: Load block 5a 3417.66 3417.66 2378.89 60 - 120s: MOVs DE 3400.20 3400.20 2377.56 120 - 178s: Load block 5b 3466.32 3466.32 2443.68 178-201s: Load block 6a 3487.69 3487.69 2465.05 201-210s: Load block 6b 3488.38 3488.38 2465.74 210-229s:Load block 6c 3515.10 3515.10 2492.46 229-30m: Load block 6d 3931.41 3931.41 2871.71 30m-30m25s: Auto Load block 4115.26 4115.26 3437.56 30m25s-75m:Manual loading 4114.56 4114.56 3437.56 75m-90m: LPSI DE 3768.23 3768.23 3437.56 90m-2h: Turb Aux DE 3698.08 3698.08 3367.41 2h-2h50s: Manual MOVs 3698.74 3698.74 3367.41 2h50s-4hr MOV DE 3698.08 3698.08 3367.41 4h-6h: EFW DE 3393.24 3393.24 3260.08 6h-8h: Manual loading (SF pump) 3433.94 3433.94 3300.78 8h-14h Manual load: DE Charging Pump, Charging Room AH, DE BA pump 3368.55 3368.55 3235.39 14h-17h Manual load: DE CCW M/U 3341.83 3341.83 3208.67 17h-4d Manual load: DE EDG Xfer P 3320.50 3320.50 17h-7d: DE EDG Xfer pump _ 3187.34 4d-7d: WCT fans 5-8 de 3223.79 4d-7d:Manual loading DE HPSI,CS EN LPSI 2922.02 DE = Deenergize EN = Energize

Attachment I to W3F1 -2004-0035 Page 28 of 32 Response 10d:

The EDG fuel oil consumption rate of 5.0 gpm assumed in support of the EPU analysis discussed in the November 13, 2004, submittal was determined by using empirical data taken October 14,2003, on EDG 'B'. Differences in EDG 'B' day tank level were measured during the October 14, 2003, EDG 'B' test run to determine the volume of oil consumed over a period of time. Based on the empirical test results, a nominal MW value associated with that rate of consumption was determined. Uncertainties of the level measurement instrumentation, the megawatt meter, and EDG 'B' day tank dimensions were then calculated. The measured volume of oil consumed during the surveillance run was corrected based on the minimum specific gravity required by Technical Specifications. As shown in the response 1Ob table, It was determined that the EDG 'B' fuel oil consumption rate during the October 14, 2003 run, including potential instrument uncertainties and corrected to 4400 KW, was 4.851 gpm. This value was then increased to 5.0 gpm to establish the consumption rate assumed in the EPU analysis. As indicated in response 1Ob table, the average maximum consumption rate, including potential instrument uncertainties and corrected to 4400 KW, for eight tests on each EDG further support the use of the 5.0 gpm consumption rate.

Note that the values shown in the response 1Ob table are the maximum possible fuel consumption rates based on adding measurement uncertainties to the test results adjusted for 4400 KW. Given the generally random nature of the measurement uncertainties, a more realistic fuel consumption rate would be the mean of the minimum and maximum possible fuel consumption rates, which would be around 4.812 gpm for EDG A and 4.857 gpm for EDG B (accounting for the 8/18/2003 run).

Question 11:

In Section 2.5.8.1 of the application, it is stated that 'A time-dependent load profile was developed based on expected power requirement and run time of each component powered by the EDG under accident conditions. This evaluation considered the ECCS [emergency core cooling system] performance and containment design analyses, along with engineering judgment for long-term portion of the event and for components not modeled in those analyses." Please identify the parts of the analysis where engineering judgment was used and provide the appropriate rationale.

Response 11:

FSAR Section 9.5.4.1 states that EDG fuel oil system must provide seven days operation of one EDG to meet the emergency safety feature (ESF) load requirements following a loss of offsite power (LOOP) and a design basis accident. Analyses for the design basis accidents described in the FSAR are only modeled over the time period that demonstrates the regulatory acceptance criteria are met. Usually this time period is a short duration and is much less than the seven days that needs to be modeled for EDG fuel oil consumption.

Therefore, the long term EDG fuel oil consumption model was based on the plant's emergency operating procedures (EOPs) that prescribe actions, both short and long term, based on plant conditions to mitigate design basis accidents. The engineering judgment that

Attachment 1 to W3FI-2004-0035 Page 29 of 32 was used in the EDG fuel oil analysis was that the large break LOCA (LBLOCA) event is the bounding event for EDG fuel oil usage.

The EOPs prescribe two mitigating methods to provide long term cooling following a LOCA.

For small reactor coolant system (RCS) breaks (i.e., small break LOCA (SBLOCA)) where RCS pressure and pressurizer level can be controlled, the plant will cool down using emergency feedwater to shutdown cooling (SDC) entry conditions and then enter shutdown cooling for long term cooling. For large RCS breaks (LBLOCA) where RCS pressure and pressurizer level can not be controlled, the plant would remain on recirculation for long term cooling for the entire event. The loading on the EDG is essentially the same for both the SBLOCA and LBLOCA with the exception of the high pressure safety injection (HPSI), low pressure safety injection (LPSI), containment spray (CS), emergency feedwater system (EFS), and auxiliary component cooling water (ACCW) system pumps and fans. For the LBLOCA, the HPSI, CS, and ACCW pumps and fans are assumed to be required for the entire seven days. For the SBLOCA, the ACCW system pumps and fans and the CS pumps would be secured sometime within the seven days (due to the lower containment heat load) and the LPSI pump would be used for long term cooling via the SDC system. The HPSI pump would remain throttled or operated intermittently, requiring less electrical load for this event (i.e., SBLOCA), to provide makeup to the RCS. The electrical load for the ACCW system pump and fans and CS pumps exceed the electrical load for the LPSI pump. The EFS pump may be used longer for the SBLOCA event; however its additional load would still be offset by the securing of the ACCW pump and fans and CS pump within the seven days.

Therefore, it can be judged that the LBLOCA event is the most limiting LOCA event for EDG fuel oil consumption.

The remaining design basis accidents are bounded by the SBLOCA event since these events do not breach the RCS boundary, therefore RCS pressure and pressurizer level will be controlled and mitigation strategy would be to cooldown using EFS and then enter SDC.

Additionally, containment heat loads are significantly less for non LOCA events reducing the operating time of ACCW pumps and fans and the CS pumps and makeup to the RCS would be provided by normal means using charging pumps which would require less electrical load than the HPSI pumps. For normal shutdown, numerous ESF loads would not be sequenced on the EDG following a LOOP since an accident signal is not present. Therefore, the electrical loading on the EDG is significantly less for the normal shutdown. Based on the above reasoning, the LBLOCA event was the bounding event analyzed for EDG fuel oil usage.

Dose Analvsis Question 12:

The staff and the licensee held a conference call on February 13, 2004, to clarify the licensee's position on updating the control room analyses for design-basis accidents (DBAs) other than the LOCA and the fuel handling accident (FHA), since they were not submitted as revised for the EPU. The licensee plans to provide updated information on the measured control room unfiltered inleakage and its impact on all the DBA control room analyses as the information is available, expected by June 2004. The staff will consider this information in the context of the EPU review as it is received. The timing of this additional information may impact the EPU review schedule.

to W3Fl-2004-0035 Page 30 of 32 Response 12:

As stated in PUR Section 2.5.3.1 and in PUR Attachment 8, Entergy has committed to complete the evaluations of control room habitability in response to Generic Letter 2003-01 by September 30, 2004. This evaluation will include a validation of the inleakage assumptions made in dose consequence analyses. It is Entergy's intent to provide updated information on control room unfiltered inleakage and its impact on control room analyses in support of EPU.

It is projected that additional information will be submitted to the NRC by June 30, 2004.

Question 13:

A burnup of 70,000 mega-watt day per metric ton of uranium (MWD/MTU) was assumed in the calculation of the fuel gap inventory for the FHA. What gap fractions were used? If the gap fractions in regulatory guide (RG) 1.195 were used (0.08 for 1-131, 0.10 for Kr-85, and 0.05 for others), Footnote 7 states that the gap fractions in RG 1.195 are applicable to fuel with burnup up to 62,000 MWD/MTU. Please justify use of the gap fractions for fuel with burnup >62,000 MWD/MTU.

Response 13:

The fuel gap inventory was calculated for 20,000, 45,000, 60,000 and 70,000 MWD/MTU and 2% and 5.5 % enrichment. (Per PUR Table 2.6-1, the peak rod average burnup is 60,000 MWD/MTU). For each isotope the maximum activity from the above calculation was used in the FHA. The following gap fractions were used in the FHA dose calculation:

Isotopes Gap Fractions Noble gases except Kr-85 0.10 l Kr-85 l 0.30 Iodine isotopes, except 1-131 0.10 1-131 1 0.12 The above gap fractions are consistent with RG 1.25 and NUREG/CR-5009, "Assessment of The Use of Extended Burnup Fuel in Light Water Power Reactors." The gap fractions in regulatory guide (RG) 1.195 were not used and Waterford 3 peak rod average burnup is below 62,000 MWDIMTU.

Question 14:

Please provide the calculated revised radiological consequences analysis dose values that were used to evaluate the impact of the EPU for the main steamline break, reactor coolant pump shaft seizure/sheared shaft, control element assembly (CEA) ejection, letdown line break, and steam generator tube rupture.

Response 14:

The PUR reports radiological results for the events of interest of:

to W3Fl-2004-0035 Page 31 of 32 2 Hour Duration Fuel EAB 2 Hour LPZ Duration Failure Whole EAB Whole LPZ PUR limit Body Thyroid Body Thyroid Event Section (%) (rem) (rem) (rem) (rem)

Main Steam Line Break 2.13.1.3.3 10% <25 <300 <25 <300 Note 1 RCP Shaft Seizure 2.13.3.3.1 8% < 2.5 < 30 < 2.5 < 30 CEA Ejection 2.13.4.3.2 15% <25 <300 <25 <300 Note 2 Letdown Line Break - 2.13.6.3.1 0% < 2.5 < 30 < 2.5 < 30 GIS case (accident generated iodine spike)

Steam Generator Tube 2.13.6.3.2 0% < 2.5 < 30 < 2.5 < 30 Rupture - GIS case (accident generated iodine spike)

Steam Generator Tube 2.13.6.3.2 0% <25 <300 <25 <300 Rupture-PIS case (pre-existing iodine spike)

Notel: MSLB fuel failure limit of <10% experiencing DNBR or <2% experiencing fuel melt.

Reported fuel failure for other events is percent of fuel experiencing DNBR.

Note 2: No fuel melt for CEA Ejection.

As discussed in Section 2.13.0.5 of the PUR, the amount of allowed fuel failure which results in doses equal to (or less than) the regulatory acceptance limits were calculated based upon the release path applicable to the event scenario. Reload cycle-specific analyses ensure these fuel failure limits are not exceeded.

The PUR reports that the consequences for these events meet the appropriate acceptance limits of the SRP, NUREG-0800. This will become the new licensing basis for these events and be the dose information described in the Waterford 3 FSAR. The detailed calculation results which support this basis show that actual results are less than the reported results:

to W3F1-2004-0035 Page 32 of 32 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)

Main Steam Line 2.13.1.3.3 10% 3.019 58.61 1.844 24.09 Break RCP Shaft Seizure 2.13.3.3.1 8% 2.415 17.22* 1.475 12.13*

CEA Ejection 2.13.4.3.2 15% 2.27 75.27 1.43 47.76 Letdown Line Break 2.13.6.3.1 0% 0.11 29.6 0.02 4.7

-- GIS case (accident generated iodine spike)

Steam Generator 2.13.6.3.2 0% 0.14 1.08 0.25 4.48 Tube Rupture-GIS case (accident generated iodine spike)

Steam Generator 2.13.6.3.2 0% 0.16 13.20 0.25 3.16 Tube Rupture-PIS case (pre-existing iodine spike)

RCP shaft seizure thyroid dose results are based on 10% fuel failure.

Question 15:

Was spray removal assumed in the containment for the LOCA and for the CEA ejection? If so, what spray removal assumptions were used?

Response 15:

Containment spray is credited for the removal of fission products in containment in the LOCA radiological dose calculations. Spray removal coefficients per NUREG-0800 SRP Section 6.5.2 are used. Specifically, the formula from Section 6.5.2 is used for particulate and elemental Iodine. The maximum allowed elemental spray removal value of 20/hr is assumed and supported for Waterford 3; a maximum decontamination factor of 200 is imposed per the SRP. The SRP formula for spray removal of particulate iodine is applied; this value is reduced by a factor of 10 per the SRP guidance once a decontamination factor of 50 has been achieved. No spray removal is assumed for organic Iodine, consistent with the SRP guidance.

No credit is taken for containment spray removal of iodine for the CEA Ejection analysis.

Attachment 2 To W3Fl-2004-0035 Response to March 26, 2004, Request for Additional Information to W3F1 -2004-0035 Page 1 of 15 Response to March 26, 2004, Request for Additional Information Related to the Extended Power Uprate Instrumentation and Controls Question 1:

Discuss the instrument setpoint methodology used to calculate trip setpoints and allowable values of the plant parameters affected by the extended power uprate (EPU). If your methodology has not been previously reviewed by the U. S. Nuclear Regulatory Commission (NRC) staff, then submit a copy of the plant instrument setpoint methodology for the staffs review and approval. If you use 'method 3" specified in Independent Safety Analysis S67.04.02, then confirm that a check calculation is performed to account for all loop uncertainties not measured during the channel operational test/channel functional test. Please assure that adequate margin exists between the analytical limit and the allowable value that equals or exceeds the value of uncertainties not measured during the channel operational test.

Please provide the documentation of the calculation which demonstrates the existence of an adequate margin. Discuss how the channel operability is determined for each of the plant parameters affected by the power uprate.

Response 1:

The setpoint methodology used to calculate trip setpoints and allowable values of the plant parameters affected by the EPU is described in the Waterford 3 Technical Specification (TS)

Bases for sections 2.0 and 3.3. This methodology, and the specific plant parameter affected by EPU (steam generator low pressure trip) have been previously reviewed by the NRC as documented in Amendment 113 issued September 5, 1995.

Waterford 3 uses a method equivalent to that specified in ISA 67.04 (recommended practice),

method 3 for determining allowable values. The 'allowance" as defined in 67.04 is the periodic test error (PTE) of the tested equipment that is described in the Waterford technical specification bases. A check calculation is not required due to the conservative methods of combining the "measurable" uncertainties which assure adequate margin exists between the analytical limit and the allowable value that equals or exceeds the value of uncertainties not measured during the channel operational test.

Channel operability is determined as described in the current technical specification bases for sections 2.0 and 3.3. Specifically, "a channel is inoperable if its actual setpoint is not within its Allowable Value and corrective action must be taken." This requirement is not changed by EPU.

Question 2:

The Waterford 3 License Amendment Request NPF-38-249, EPU, dated November 13, 2003, (the application) states on page 2.13-10 that, as part of the power uprate, the response times for core protection calculator system low departure from nucleate boiling ratio and high low-power density trips were reviewed and enhancements to clarify the time requirements were identified, which included reductions in some of the times required to be assumed in safety analyses.

Please identify these response time reduction items and the related safety analysis sections.

to W3Fl-2004-0035 Page 2 of 15 Response 2:

Section 2.13 of the Power Uprate Report (PUR) discusses assumptions regarding the reactor protection system, including the core protection calculator (CPC) system, related to Final Safety Analysis Report (FSAR) Chapter 15 safety analyses. The changes are shown in the markup of Technical Requirements Manual (TRM) Table 3.3-2 included in the PUR. The TRM Bases markup includes new Bases section 3/4.3.1 and 3/4.3.2. The new TRM Bases improve the clarity of design bases by explicitly discussing the times that may be assumed in safety analyses for the various CPC trip functions, including the module-based trip functions; this information had not previously been documented in TRM Bases.

A detailed review of contributors to the CPC response times was performed in conjunction with Waterford 3 3716 MWt Extended Power Uprate (EPU) work. Time delays associated with hardware response times and for test software and actual plant software for the various software routines invoked for the various different CPC functions were reviewed to develop rigorous values for the CPC response time test acceptance criteria. This resulted in the refinements in the response times specified in the TRM Table 3.3-2:

TRM Table 3.3-2 PUR markup, CPC Functional Unit Previous time (sec) TRM Table 3.3-2 (sec.)

9a & 10 a., Neutron Flux 0.429 0.191 Power from Excore Detectors 9b & 10 b., CEA Positions 0.424 0.186 9c / 9d* / 1Og /1 Oh* 0.379 0.236 / 0.271 CEA Positions: CEAC Penalty Factor 1Oc, Cold Leg Temperature 0.300 0.285 10d, Hot Leg Temperature 0.429 0.285 10e, Primary Coolant Pump 0.237 0.185 Shaft Speed re 1Of, Pressurizer Pressure 0.429 0.186

9d and 1Oh were previously covered under 9c and 1Og The above times documented in the PUR represent improved values demonstrating the time response the equipment is capable of achieving. This information is used to derive the minimum time that needs to be assumed in safety analyses. The safety analysis time accounts for hardware delay times and time delays associated with CPC software, and accounts for differences in the processing time for CPC test software compared to CPC reactor trip software.

As documented in the EPU PUR, CPC trips are assumed for the following events:

Minimum Assumed Assumption EPU Pre-EPU PUR (TRM Analysis Delay Event Section CPC Trip Bases) Delay Time Time (sec.) (sec.) (sec.)

Excess Main 2.13.1.1.3 VOPT 0.370 0.50 Note 1 Steam Flow to W3F1 -2004-0035 Page 3 of 15 Minimum Assumed Assumption EPU Pre-EPU PUR (TRM Analysis Delay Event Section CPC Trip Bases) Delay Time Time (sec.) (sec.) (sec.)

Excess Main 2.13.1.2.3 Low DNBR 0.332 0.34 0.35 Steam Flow w/LOOP .

HFP Inadvertent 2.13.1.2.4 Low RCP Speed 0.2315 0.30 0.30 ADV Opening w/LOOP .

Main Steam Line 2.13.1.3.3 VOPT 0.370 0.43 0.63 Break (pre-trip power excursion)

Low Power CEA 2.13.4.1.2 VOPT 0.370 0.429 0.50 Withdrawal CEA Withdrawal 2.13.4.1.3 VOPT 0.370 0.50 Note 1 at Power CEA Ejection 2.13.4.3.2 VOPT 0.370 0.629 0.40 Letdown Line 2.13.6.3.1 Pressurizer 0.2693 Note 3 Note 1 Break Pressure out-of-range Steam 2.13.6.3.2 Hot Leg 2.744 2.7 Note 2 Generator Tube Saturation Rupture Asymmetric 2.13.9.1.1 Differential Cold 0.370 0.4 0.40 Steam Leg Temperature Generator Transient Note 1: A different trip signal was assumed in the pre-EPU analyses as documented in the PUR.

Note 2: Not documented in PUR/FSAR. Results of SGTR are insensitive to trip delay time due to assumption of LOOP concurrent with reactor trip.

Note 3: A 0.20 second delay time is assumed. However, due to the slow depressurization of the event and timing of trip to maximize radiological consequences, this is a non-limiting event for DNBR performance.

Thus, while the refinements in CPC response timing allowed for assuming reduced delay times in safety analyses, this improved timing has not been credited in all analyses and margin still remains to the required minimum times. In some cases (e.g., CEA Ejection), additional conservatism was added to the EPU analyses by assuming an increased CPC delay time.

Question 3:

The application states on page 2.4-1 that the EPU also affects the atmospheric dump valve (ADV) controllers. The existing ADV analog controllers are being replaced with more accurate digital controllers. The ADV controllers perform safety-related functions, and therefore, covered

- to W3Fl-2004-0035 Page 4 of 15 by Part 50 of Title 10 of the Code of Federal Regulations (10 CFR), Appendix A, General Design Criterion 1, "Quality Standards and Records,' which requires, in part, that structures, systems, and components important to safety shall be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed.

Additionally, 10CFR50.55a(h) requires, in part, that protection systems satisfy the criteria of the Institute of Electrical and Electronics Engineers (IEEE) Standard 603, 'Criteria for Safety Systems for Nuclear Power Generating Stations." Discuss the modification package of the ADV controllers to be installed at the Waterford 3 and address the following design requirements:

a. Compliance with IEEE-603 (or IEEE-279) requirements

b. Software life cycle process planning i

c. Design verification and validation process

d. Configuration management process

e. Maintenance, testing, and calibration process

f. Environmental considerations, such as electromagnetic interference, radio-frequency interference, effects of temperature and humidity, etc.

Response 3:

Following the conference call with the NRC staff on March 10, 2004, Entergy was notified, by its contractor, that the SBLOCA analysis performed in support of the EPU did not support that one high pressure safety injection (HPSI) pump and one ADV could mitigate the SBLOCA as Entergy had assumed in the November 13, 2003, submittal and stated during the March 10, 2004, call. The EPU analysis performed for the SBLOCA indicated that one HPSI pump and two ADVs were required to mitigate the SBLOCA assuming a single failure of one emergency diesel generator (EDG). This situation was entered into the Waterford 3 10 CFR 50 Appendix B corrective action program and the information was conveyed to the NRC NRR Project Manager for Waterford 3 by telephone on March 12, 2004.

As a result of this information, Entergy reassessed the SBLOCA analysis and determined that a loss of one train of DC power would be a worse single failure than the loss of one EDG. Loss of one train of DC power will disable one EDG as well as the controls to one ADV. Therefore, one HPSI pump and two ADVs can not be credited for the SBLOCA assuming a single failure of one train of DC power. Thus acceptable results must be obtained utilizing one HPSI pump and one ADV.

Entergy is currently working with the contractor to re-perform the S2M SBLOCA analysis to achieve acceptable results utilizing one HPSI pump and one ADV. Renodalization of the S2M model is being performed to more accurately model the ADVs in an effort to achieve acceptable results. Additionally, HPSI pump flow capability is also being reassessed in support of this effort. Based on ongoing work, it is possible that new ADV digital controllers may not be needed following the completion of the EPU SBLOCA reanalysis.

Therefore, Entergy is deferring the response to any questions regarding ADV digital controllers until a final determination has been made regarding their need for EPU. This deferral has been discussed with the NRC NRR Project Manager for Waterford 3.

to W3Fl-2004-0035 Page 5 of 15 Question 4:

If ADV controllers use the commercial software-based devices, the digital components to be used in safety systems must be qualified for their intended application. Address the Waterford 3 plant-specific dedication of commercial grade digital equipment for nuclear safety application with respect to the guidance provided in NRC Standard Review Plan (SRP), Appendix 7.0-A, Section C.3.8, "Review of the Acceptance of Commercial-Grade Digital Equipment," and SRP Section 7.1, Acceptance Criteria on Supplemental Guidance for Digital Computer-Based Safety Systems."

Response 4:

See response to question 3 above.

Question 5:

The ADVs are credited for small-break loss-of-coolant accident (SBLOCA) mitigation at greater than 70 percent rated power. A new Technical Specification (TS) was proposed. Because the ADV controllers are digital devices, the common mode failure due to software error should be considered. Additional surveillance may be required after detecting one ADV inoperable.

Discuss the adequacy of the proposed TS with respect to the common mode failure concern.

Response 5:

See response to question 3 above.

Question 6:

The EPU application, in Section 2.13.1.1.4.1, "General Description of the Event," states that one ADV may be inadvertently opened due to operator error or due to a failure in the ADV control system. Analyze the consequence for inadvertently open all ADVs due to a common mode failure at ADV digital controllers.

Response 6:

See response to question 3 above.

Question 7:

In Attachment 1, "Analysis of Proposed Technical Specification Changes," Section 4.0, states that in an effort to improve clarity for the operators, the word "indicated" or phrase "an indicated" is being added to identify those values in TS that can be compared directly to plant instrument readings to ensure TS compliance. The staff considers that the plant instrument readings from indicators can only be used for channel check to detect a gross failure of an instrument channel.

It is not acceptable to be used for TS compliance. There is no assurance that the "indicated" reading is reliable and conservative. The number in the TS should be based on safety analysis, and should meet the requirements of 10 CFR 50.36.(c)(2) to establish the lowest functional to W3Fl-2004-0035 Page 6 of 15 capability or performance level of equipment required for safe operation of the facility.

Therefore, the word Indicated" or "an indicated" cannot be used in the TS.

Response 7:

Following discussions with the NRC staff on March 10, 2004, and March 31, 2004, regarding the use of the word 'indicated" and phrase "an indicated" in technical specifications, Entergy concurs with the NRC staff that the technical specification bases is an appropriate place to convey this type of information. Entergy has therefore decided to withdraw its request to use this terminology in the technical specifications as requested in the November 13, 2003, submittal but will instead retain the information in the technical specification bases as described, for information only, in the November 13, 2003, submittal. Revised technical specification mark-ups reflecting this withdrawal will be submitted by July 15, 2004, in conjunction with the technical specification change committed to in the March 4, 2004, supplement regarding primary-to-secondary leakage.

Question 8:

Section 7.8.3.2 of the final safety analyses report (FSAR), "Diverse Emergency Feedwater Actuation System (DEFAS)," states that the DEFAS actuation signals are interlocked with steam generator pressure. The power uprate requires a setpoint change on "steam generator pressure-low." Verify that the proposed setpoint change does not affect the DEFAS operation or cause inadvertent actuation of the DEFAS.

Response 8:

The function of the steam generator pressure DEFAS pressure interlocks, described in FSAR 7.8.3.2, is to "arm" the DEFAS circuit when steam generator pressure is above a minimum pressure. This is achieved by steam generator and main steam pressure instrumentation that is independent of the instrumentation associated with the setpoint change on "steam generator pressure-low." The purpose of the DEFAS pressure interlocks is to ensure the DEFAS will not permit emergency feedwater flow to a faulted steam generator. On decreasing steam generator pressure, DEFAS is disarmed and will not actuate. Actuation of the revised "steam generator pressure-low" setpoint will not be affected by the DEFAS steam generator pressure interlocks, nor will the DEFAS steam generator pressure interlocks be affected by the "steam generator-low" setpoint due to the existing independence between the DEFAS and plant protection system instrumentation loops. Additionally, DEFAS is actuated by decreasing steam generator level and only when the steam generator pressure interlock is above the DEFAS arming setpoint; DEFAS is not actuated by decreasing steam generator pressure. Consequently, the setpoint change on "steam generator pressure-low" will not affect DEFAS operation or cause inadvertent actuation of the DEFAS.

Question 9:

Verify the inconsistency between TS and BASES. For example, TS 3/4.2.6, "Reactor Coolant Cold Leg Temperature," Limiting Condition for Operation 3.2.6 states '"The reactor coolant cold leg temperature shall be maintained between 5360F and 5490 F" while Bases 3/4.2.6 insert

- - to W3F1 -2004-0035 Page 7 of 15 states "The safety analysis assumes that cold leg temperature is maintained between 5530 F and 5520 F or indicated temperatures of 5560F and 549 0F."

Response 9:

The Technical Specification Bases insert, provided for information only in the November 13, 2003, submittal, contains typographical errors. The information only Bases insert should read

'The safety analysis assumes that cold leg temperature is maintained between 5330 F and 5520 F or indicated temperatures of 5360 F and 5490F."

The remainder of the Technical Specification Bases, provided for information only, has been reviewed and no further typographical errors were identified.

Quality and Maintenance Question 10: of your letter dated January 29, 2004 (Supplement 1), states that test, "Load Changes," will be performed only at 95 percent power. This test occurred various times between 50 percent and 100 percent power during initial power ascension tests.

Given the planned modifications on the secondary plant (ADV controller replacement, high pressure main turbine rotor blade replacement, moisture separator reheater relief valve capacity change), please describe how one test will be sufficient to adequately ascertain plant response as specified in FSAR Section 14.2.12.3.31, "Control Systems Checkout."

Response 10:

Changes to the control systems implemented by EPU do not change the design functions of the equipment or the method of performing or controlling the function. A discussion of the aggregate impact of the EPU modifications is presented in Attachment 2 of the January 29, 2004, supplement, and concludes that the modifications will not result in a significant change to the plant's dynamic response to anticipated initiating events. As further discussed in , the aggregate impact of control systems modifications has been evaluated using the long term cooling (LTC) computer code analyses. The LTC code has been benchmarked against actual plant data; specifically, steady state conditions, and three separate plant transients, with good agreement. 32 different cases were run to model EPU conditions, with no unacceptable system interactions or unacceptable dynamic system responses.

Testing to satisfy the requirements of FSAR Section 14.2.12.3.31 is detailed in several locations in the January 29, 2004, supplement:

Attachment 1, page 3 - Plant Control System and Instrumentation, states to uCollect plant data and confirm performance as expected." Attachment 3, page 2 indicates that this test will be performed prior to startup, and at numerous power levels between 0% and 100%

EPU rated thermal power (RTP).

Attachment 1, page 3 - Plant Control System and Instrumentation, states to "Perform load change testing to verify automatic operation of the various control systems". Attachment 3, to W3F11-2004-0035 Page 8 of 15 page 4, Load Changes, describes this test as a "5% ramp to verify control system response". It is indicated that this test will be performed at 95.0% of Rated Thermal Power (3716 MWt). The test is further described in Attachment 4, page 9 - SIT-TP-721, Load Changes (Control Systems Checkout), as satisfying in part the requirements of FSAR Section 14.2.12.3.31.

Attachment 3, page 3 - Transient Data Record, indicates that data collection will be performed at numerous power levels from 20% to 100% EPU RTP. Attachment 4, page 2 -

Transient Data Record, describes the test as establishing ".. a plant baseline data record during the slow initial power increases of the plant."

FSAR Section 14.2.12.3.31 requires the following tests under section 14.2.12.3.31.3:

A. "Monitor control systems' performance during steady-state operation (50% and 80%), and following selected plant trips." As indicated above, control systems performance will be monitored at numerous power levels between 0% and 100%. In orderto facilitate reactor testing, power ascension will not be suspended between 0% and 80%, thus the data collected at 50% and 80% power will not be representative of steady state conditions. This is considered acceptable since the plant has previously been operated at these power levels prior to power uprate. Entergy believes that such tests at pre-EPU power levels would not confirm any new or significant aspect of performance which has not already been demonstrated by previous operating experience or is routinely demonstrated through plant operation. Rather, steady state conditions will be established, and control systems monitored at various power levels greater than the prior licensed power; specifically 92.5%,

95.0%, 97.5%, and 100% post EPU RTP.

Large transient testing will not be performed for EPU. The justification for exception to large transient testing is detailed in the January 29, 2004, supplement, Attachment 5, "Justification for Exception to Large Transient Testing."

B. "Monitor control systems performance during ramp unit load changes (100%)." As indicated in above, Waterford 3 plans to perform a load change test to gather data as part of EPU power ascension. This will be integrated with EPU modification tests. Attachment 3, of the January 29, 2004, supplement, indicates that the test will be performed at 95% power.

Waterford 3 now plans to perform this integrated systems test by changing power from 100% to 90%; followed by an increase in power from 90% to 95%. This follows a similar power profile as the integrated testing of the original startup test, SIT-TP-721.

All control systems will be in automatic for this test, with one exception: the control element drive mechanism control system (CEDMCS) will remain in manual, vice auto-sequential.

Except during a reactor power cutback (RPC), plant procedures no longer provide for the use of the reactor regulating system (which operates through CEDMCS) to control reactor power. Rather, reactor power is controlled through the addition or removal of soluble boron from the RCS via the chemical volume control system (CVCS). Therefore, the ramp unit load change test will be performed in the allowed (normal) configuration, with CEDMCS in manual, and reactivity will be controlled using boration/dilution via the CVCS.

C. "Initiate control system transients on selected control systems, and monitor system response (50, 80, and 100 percent)." This test was performed during initial startup testing by SIT-TP-to W3F11-2004-0035 Page 9 of 15 721 for the steam bypass control system (SBCS), feedwater control (FWC), and reactor regulating system (RRS).

As described in the initial Waterford 3 Startup Report, an individual control system transient test was performed for SBCS at 50% power only; an individual control system transient test was performed for FWC at 50% and 80% power only; and an individual control system transient test was performed for RRS at 50% and 100% power only.

Modifications to control systems are required for EPU to ensure the plant will be maintained within desired operating bands during normal operations, and will stabilize the plant during minor load changes and load rejection events. These adjustments do not change the design functions of the equipment or the method of performing or controlling the function. The changes to the SBCS, FWC, and RRS are setpoint adjustments only; no physical changes are required. As specified in Attachment 1 of the January 29, 2004, supplement, a channel calibration will be performed to verify the proper operation of each control system in response to changes in input parameters. Control system transient testing will not be performed at 50% nor 80% power for EPU. This is considered acceptable since the plant has previously been operated at these power levels prior to power uprate. Entergy believes that repeating these tests at pre-EPU power levels would not confirm any new or significant aspect of performance which has not already been demonstrated by previous operating experience or is routinely demonstrated through plant operation. In addition, the new setpoints have been evaluated using the LTC Code, with acceptable results. No new system interactions or unacceptable transient behavior of control systems was identified.

Of the control system transient tests performed during initial startup, only the test of the RRS was performed at greater than 80% power. This test involved changing the turbine load, and observing the RRS respond to change reactor power by operating CEDMCS in Auto-Sequential. With the exception of a RPC, plant procedures no longer provide for use of the RRS for the control of reactor power. Rather, reactor power is controlled through the addition or removal of soluble boron from the RCS via the CVCS. Since Waterford 3 no longer uses the RRS to control reactor power at 100%, the control system transient test of the RRS at 100% will not be performed.

The RRS is used to stabilize reactor power between 50% and 70% following a RPC. As discussed above, control system transient testing will not be performed at these power ranges since the plant has previously been operated at these power levels prior to power uprate. Entergy believes that repeating these tests at pre-EPU power levels would not confirm any new or significant aspect of performance which has not already been demonstrated by previous operating experience or is routinely demonstrated through plant operation Therefore, individual control systems transient testing will not be performed. Rather, channel calibration of the individual control systems, and the integrated testing at steady state and during ramp unit load change described above will be performed to demonstrate acceptable control system performance.

Attachment 2 to W3FI-2004-0035 Page 10 of 15 Question 11:

Attachment 4 of Supplement 1 states that test SIT-TP-707, "Steam Bypass Control System (SBCS) Capacity Checks,"will not be performed. Given the planned modifications on the ADV controllers and SBCS, provide details on the testing method(s) planned to verify and validate that the ADVs will not actuate prior to the SBCS in the event of a load reject.

Response 11:

A pending calculation constitutes the basis for concluding that the SBCS will actuate prior to the ADVs in the event of a load rejection from 100% power. The probability that the SBCS will actuate prior to the ADVs in the event of a load rejection decreases as the initial power level decreases. However, when completed, the calculation is expected to demonstrate that the likelihood that the SBCS will actuate prior to the ADVs in the event of a load rejection will be less after EPU than currently for all initial power conditions. Additionally, reanalysis of the EPU SBLOCA is currently underway (see response to Question 3 above) and the ADV actuation setpoint may increase thus providing additional margin.

Performance of a channel calibration of the SBCS and each ADV will demonstrate the proper response of these systems to plant parameters, and will validate the assumptions of the calculation. The channel calibration of the ADVs is discussed in Attachment I to the January 29, 2004, supplement.

Question 12:

Attachment 4 of Supplement 1 states that test SIT-TP-724, "Temperature Decalibration Verification," will not be performed. The evaluation/justification for not performing the test states in the first sentence, "Algorithms contained within the core protection calculator systems (CPCS) are unchanged." The next sentence begins, "The update algorithm within CPCS accommodates for a change in cold leg temperature..." Based on the lack of clarity in the justification, please explain whether the algorithms within the CPCS are changed or unchanged, and if changed, what test(s) will be performed for validation and verification.

Response 12:

The CPC algorithms are unchanged for EPU, as stated in letter W3F1-2004-004 dated January 29, 2004. The "UPDATE" algorithm is a program within the CPC System that updates the latest values of departure from nucleate boiling ratio (DNBR) and quality margin available from another CPC algorithm (the "STATIC" program) and determines the DNBR and local power density based on current temperature, pressure, core power, core flow, and power distribution.

The "UPDATE" program does not calculate an actual DNBR; this is done by the "STATIC" program. However, the "UPDATE" program looks at the rate of change of the input variables, including cold leg temperature, to calculate the rate of change of DNBR over the 100 milliseconds it takes to run "UPDATE." This allows updates for the changes in DNBR to be done 20 times over the two seconds required for the "STATIC" program to run a detailed DNBR calculation. The DNBR algorithm limits on minimum and maximum cold leg temperature of 4950 F and 580 0F, documented in Technical Specification Section 2 Bases, are not impacted by the proposed change in Technical Specification limits on cold leg temperature and thus do not require revision and are not being revised for EPU.

to W3Fl-2004-0035 Page 11 of 15 Question 13: of Supplement 1 describes that a modification of the reactor coolant system Taverge versus pressurizer level program will occur to accommodate a lower reactor coolant system operating temperature. Please provide additional details regarding testing to verify proper operation of affected control systems (i.e. pressurizer level and pressure control).

Response 13:

This question requests additional detail regarding testing to verify proper operation of pressurizer level and pressurizer pressure control systems. The pressurizer pressure control system (PPCS) utilizes a single setpoint (vice a program setpoint) which is manually adjusted.

EPU implements no changes to the PPCS or setpoint.

The RCS average coolant temperature (Taverage) for 100% power will change from the current hot full power average temperature of 5740F to 571.9 0 F for EPU. Therefore the change in Taverage will be reflected in the Taverage program and in the pressurizer level setpoint program.

The temperature for which the maximum pressurizer level setpoint is programmed corresponds to 100% power. Also Tavge for hot zero power is being reduced from 544.6 'F to 541 OF. The temperature for which the minimum pressurizer level setpoint is programmed corresponds to 15% power. The RRS/PLCS setpoints (pre-uprate and post uprate) are provided in the table below. The planned changes to the setpoints from the current values are highlighted in bold.

SUMMARY

OF PRESSURIZER LEVEL CONTROL SYSTEM SETPOINT CHANGE CURRENT Extended Power Uprate ENGINEERING SETPOINTS SETPOINTS PARAMETER ENGINEERING UNITS ENGINEERING UNITS REACTOR REGULATING SYSTEM - REACTOR PROGRAM UNIT CALCULATOR TREF (100) 574.0 OF 571.95 OF TNL 544.6 OF 541.0 'F Tp, 549.0 OF 545.6 OF TP2 574.0 OF 571.9 OF Isp, 33.1% 33.1%

LSP2 55.6% 55.6%

The following figure provides a graphical comparison of the current vs. the EPU pressurizer level setpoint program.

Attachment 2 to W3F1 -2004-0035 Page 12 of 15 Pressurizer Level Setpoint Program 90*

80 -

70 -

EPU Max Level 55.6% at 571.9 0F 60 -

Level (%)

50 -

I - Current EPU Current Min Level 33.1% Max Level 55.6% at at 545.6-F 574.0 0F 401 30 -

Current Min Level 33.1%

at 549.00 F 20 10 _ I I I I 535 540 545 550 555 560 565 570 575 580 TaVerage (deg. F) to W3Fl-2004-0035 Page 13 of 15 The PLCS maintains pressurizer level by starting and stopping charging pumps, and by controlling the rate of letdown flow. The design of the PLCS will not change. No changes are planned for the pressurizer level control setpoints other than the pressurizer level setpoint vs. RCS Taverage program detailed above. Therefore changes to the current setpoints for charging and letdown control are not planned for Extended Power Uprate.

No hardware changes are associated with this modification. Therefore, as detailed in Attachment 1, page 3 to the January 29, 2004, supplement, the principle retest for the setpoint change to the PLCS will be a channel calibration. In addition to the channel calibration of the PLCS, data will be collected and system response observed for both the PLCS and the PPCS during the steady state and transient testing described in the response to Question 10 above.

Question 14:

Attachment I of Supplement 1 briefly describes the impact of individual modifications on dynamic plant response. The information currently provided in the application is not sufficient for the staff to evaluate how the scope of EPU related modifications, known system interactions, transient behavior of systems important to safety, functional system requirements in response to anticipated operational occurrences (AOOs), and other factors were considered in the aggregate. Please describe the process/methodology used in considering how, in the aqaregate, the planned EPU modifications could affect expected system interactions, transient behavior of systems important to safety, functional system requirements in response to A0Os, and other factors which could affect the dynamic response of the plant.

Response 14:

A review of each planned modification was performed to determine the potential contribution to the aggregate impact. Where a potential aggregate impact was identified, the modification was modeled into applicable EPU safety analysis or evaluated utilizing the LTC computer code, which yielded acceptable results. These results will be validated in part by the planned steady state and transient testing described in the response to Question 10 above.

As discussed in Attachment 5 of the January 29, 2004, supplement, the aggregate impact of control systems modifications has been evaluated using the LTC computer code analyses.

32 different cases were run to model EPU conditions with no unacceptable system interactions or unacceptable dynamic system responses.

The LTC computer code includes models of the reactor coolant system and core, steam generators, steam supply system, feedwater and condensate systems, and the NSSS control and protective systems. The level of modeling detail in the nuclear steam supply system (NSSS) control systems includes transmitter and instrumentation response times, control system dynamic compensation, and valve and valve actuator characteristics. LTC includes models of the reactor protection system (RPS) trip logic and the engineered safety features (ESF) trip logic. This level of modeling insures that the LTC code is suitable for evaluating control systems interactions. Additionally, the LTC code has been benchmarked to W3F1 -2004-0035 Page 14 of 15 against actual Waterford 3 plant data; specifically, steady state conditions, and three separate plant transients, with good agreement.

The following is a discussion of the aggregate impact evaluation of each EPU modification:

The change to the low steam generator pressure trip setpoint (764 psia to 662 psia) was incorporated into all applicable EPU safety analyses with acceptable results.

The ADV controllers will be maintained at a lower setpoint. This change was incorporated into all applicable EPU safety analyses with acceptable results.

The high pressure turbine steam path must be replaced to facilitate EPU. This change will not modify or impact the turbine throttle and governor valves. Also, change to the current turbine control system is not required to make this transition. Therefore, both the design function of the high pressure turbine and the system response to event initiators will not change as a result of this modification. Based on this, Entergy concluded that no aggregate impact potential exists due to the replacement of the high pressure turbine.

Additional moisture separator reheater (MSR) shell side relief valve capacity will be provided. These relief valves provide overpressure protection to the MSR for all postulated conditions (the worst case event is that of inadvertent closure of all downstream steam valves). The higher relief capacity is required to match the higher steam flow capacity of the new high pressure turbine steam path. This is a piping protection design function. The design function is unchanged by the addition of relief capacity. This modification will not result in a significant change in the plant's dynamic response to anticipated initiating events. Based on this, Entergy concluded that no aggregate impact potential exists due to the addition of MSR shell side relief valve capacity.

A main generator stator rewind and a core step iron modification will be performed to restore the main generator to its original capability. A new alkalizer skid will be retrofitted into the existing generator stator cooling water system. These generator modifications do not change the design function for the main generator, nor will a new system interaction be created. Based on this, Entergy concluded that no aggregate impact potential exists due to the rewind of the main generator or installation of a stator cooling water alkalizer skid.

Generator output breakers are being replaced with breakers with a higher current interrupt rating to support the higher planned power generation. Additionally, Main transformer A will be replaced and main transformer B cooling will be upgraded to support the higher planned power generation. The replacement of main transformer A is required to restore it to the original nameplate capability. The additional cooling for main transformer B is required to preclude long term degradation mechanisms which could shorten the useful life of the transformer. These modifications do not change the design function of the equipment, nor will any new system interactions be created. Based on this, Entergy concluded that no aggregate impact potential exists due to these modifications.

- to W3Fl-2004-0035 Page 15 of 15

The detailed evaluation of the feedwater heater drain system has not been completed, however based on the preliminary analysis only minor changes to select system level control valves are expected. These changes would have minimal impact on the feedwater heater drain system, requiring minor system tuning during power ascension and initial plant operation at full power. These modifications will not result in a significant change to the plant's dynamic response to anticipated initiating events.

Additional support staking of the main condenser tubes will be performed to minimize the effects of flow induced vibration. This is a static, structural modification which will not result in a significant change to the plant's dynamic response to anticipated initiating events.

Changes to various setpoints in the reactor regulating system (RRS), pressurizer level control system (PLCS), steam bypass control system (SBCS), and feedwater control system (FWCS) are required to accommodate the new normal operating bands for Taverage, steam pressure, and feedwater flow rate. These adjustments do not change the design functions of the equipment or the method of performing or controlling the function. These changes were evaluated using the LTC computer code and the analysis yielded acceptable results.

In summation, all changes that were screened as having the potential to contribute to an aggregate impact were analyzed using EPU safety analyses, the LTC computer code analysis, or both as applicable, with acceptable results. These results will be validated in part by the planned steady state and transient testing described in the response to Question 10 above.

Attachment 3 To W3F1 -2004-0035 List of Regulatory Commitments to W3Fl-2004-0035 Page 1 of 1 List of Regulatory Commitments The following table identifies those actions committed to by Entergy in this document. Any other statements in this supplement are provided for information purposes and are not considered to be regulatory commitments.

TYPE (C eck one) SCHEDULED ONE- CONTINUING COMPLETION COMMITMENT TIME COMPLIANCE DATE (If ACTION Required)

As stated in PUR Section 2.5.3.1 and in PUR X 6/30/04 , Entergy has committed to complete the evaluations of control room habitability in response to Generic Letter 2003-01 by September 30, 2004. This evaluation will include a validation of the inleakage assumptions made in dose consequence analyses. It is Entergy's intent to provide updated information on control room unfiltered inleakage and its impact on control room analyses in support of EPU. It is projected that additional information will be submitted to the NRC by June 30, 2004.

Entergy has therefore decided to withdraw its X 7/15/04 request to use this terminology in the technical specifications as requested in the November 13, 2003, submittal but will instead retain the information in the technical specification bases as described, for information only, in the November 13, 2003, submittal. Revised technical specification mark-ups reflecting this withdrawal will be submitted by July 15, 2004, in conjunction with the technical specification change committed to in the March 4, 2004, supplement regarding primary-to-secondary leakage.

v t e Letter Sequence Supplement
TAC:MC1355, (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request Acceptance Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement, Supplement Administration Withholding Request Acceptance, Withholding Request Acceptance Meeting, Meeting, Meeting Questions 10 February 2004 28 January 2004 16 March 2004 24 March 2004 31 March 2004 8 April 2004 20 April 2004 26 March 2004 4 May 2004 21 June 2004 30 January 2004 18 February 2004 23 February 2004 2 March 2004 29 September 2004 29 October 2004 26 October 2004 Answers Results Approval, Approval, Approval, Approval Other: ML040300802, ML040631055, ML042520157, ML042670485, ML050870511, ML051090111, W3F1-2004-0085, Schedule Clarification for Amendment Request NPF-38-249, Extended Power Uprate, W3F1-2004-0101, to Amendment Request NPF-38-256, Alternate Source Term, Waterford Steam Electric Station, Unit 3
MONTHYEAR2004-03-04 [Table View]

W3F1-2004-0035, Supplemental to Amendment Request for Extended Power Uprate

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W3F1-2004-0035, Supplemental to Amendment Request for Extended Power Uprate

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