ML16207A580

Revision 18 to Updated Safety Analysis Report, Q&R 5.2-1 Through Q&R 5.4-24

ML16207A580
Person / Time
Site:	South Texas
Issue date:	04/28/2016
From:	South Texas
To:	Office of Nuclear Reactor Regulation
Shared Package
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References
NOC-AE-16003371
Download: ML16207A580 (95)

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STPEGS UFSAR Q&R 5.2-1 Revision 16 Question 005.1 In addition to the two code cases identified in Section 5.2.1.2 of the FSAR, identify all other ASME Code Cases (including those that are listed as acceptable in Regulatory Guides 1.84 and 1.85) that were used in the construction of each Quality Group A components within the reactor coolant pressure boundary. These code cases should be id entified by code case number , revision, and title for each component to which the code case has been applied.

Response The unapproved or conditionally approved (per Regul atory Guides 1.84 and 1.85) code cases used in the construction of the STPEGS Class l components, specifically Code Cases 1739 and 1528, have been addressed in Section 5.2.1.2.

In the case of code cases approved by the N RC via Regulatory Guides 1.84 and 1.85, the Applicant sees no need to specifically address the usage of these code cases in the STPEGS UFSAR since Regulatory Guides 1.84 and 1.85 are viewed by th e Applicant as the NRC's communication of review/endorsement of code cases.

STPEGS UFSAR Q&R 5.2-2 Revision 16 Question 005.3 Your response to Request No. 005.1 is unacceptable. Footnote 6 of the Codes and Standards Rule, Section 50.55a of 10 CFR Part 50, stat es that the use of specific Code Cases may be authorized by the Commission upon request. Therefore, each Quality Group A component within the Reactor Coolant Pressure Boundary to which a Code Case has been applied should be identified by Code Case number, revision, and title. This includes those ASME Code Cases wh ich are identified as acceptable to the Commission in Regulatory Guides 1.84 and 1.85. Revise the FSAR to provide the information

requested.

Response As stated in the response to Question 005.1, unapproved or conditionally approved (per Regulatory Guides [RGs] 1.84 and 1.85) code cases used in the construction of the ST PEGS Class l reactor coolant pressure boundary (RCPB) components, specifically Code Cases 1739 and 1528, have been addressed in Section 5.2.1.2. In the case of c ode cases approved by the NRC via RGs 1.84 and 1.85, we see no need to specifically address the usage of these code cases in the STPEGS UFSAR; however, all code cases (approved, conditionally approved, unapproved) used in the construction of STPEGS Class 1 RCPB components are identified in the manufacturers' data reports, which are included in the STPEGS QA data package.

STPEGS UFSAR Q&R 5.2-3 Revision 16 Question 005.4 Your response to Request No. 005.2 states that in some cases portions of the Reactor Coolant Pressure Boundary that meet the exclusion requirements of Footnote 2 of the Codes and Standards Rule, Section 50.55a of 10 CFR Part 50, and with the interface criteria as defined in the ANS Nuclear Power Plant Standard Committee Policy 2.3 (Draft 6), ar e classified less than Safety Class 2. This is an incorrect interpretation of the regulation and is unacceptable. Under no circumstances, regardless of interface criteria, may a component within the Reactor Coolant Pressure Boundary, as defined in 10 CFR 50.2(V) of the Code of Federal Regulations and meeting the exclusion requirements of Footnote 2, be classified less than Quality Group B, Safety Class 2, (i.e., must be constructed to ASME Section III, Class 2 in conformance with Regulatory Position C.1 of Regulatory Guide 1.26), and, in addition, the component must be designed to seismic Category I requirements in conformance with Regulatory Position C.1.a of Regulatory Guide 1.29 and the pertinent quality assurance requirements of Appendix B to 10 CFR Part 50. The ANS Nuclear Power Plant Standard Committee Policy 2.3 (Draft 6) document is unacceptable for use in the licensing process, as the document is in conflict with Federal Regulations. Revise the FSAR as appropriate to comply with the above requirements.

Response The statement, "This is an incorrect interpretation of the regulation and is unacceptable," is not understood. The reasons are as follows:

1. The regulation is clear and unambiguous in making exceptions of all piping, pumps, and valves from the Group A (Safety Class 1) requirements provided either of two criteria is met. Westinghouse meets these criteria in piping arrangements wherein non-nuclear safety equipment is provided within the Reactor Coolant Pressure Boundary (RCPB).

2. The regulatory basis for making equipment of the RCPB excluded from Group A requirements meet Group B (Safety Class 2) requirements derives from Position C.1 of Regulatory Guide (RG) 1.26. However, the Westinghouse approach to RG 1.26 has always been based on the standard front page allowance (of each RG) that "methods and solutions different from those set forth in the guides will be acceptable if they provide a basis for the findings requisite to the issuance or continuance of a permit or license by the Commission." The last corporate letter in which Westinghouse set forth comments on RG 1.26 was NS-CE-1740, sent to the Secretary of the Commission on April 28, 1978. A serious deficiency in the RG is the lack of rules gove rning the boundaries between classes of interconnected equipment (usually known as "interface crit eria"). This is covered by Comment No. 8 of the cited letter. Given the existence of fully rational interface criteria, there would be no doubt about the acceptability of having some equipment of the RCPB exempted from the requirements associated with Group B.

STPEGS UFSAR Q&R 5.2-4 Revision 16 Response (Continued)

3. The regulatory basis for making equipment of the RCPB excluded from Group A requirements meet seismic Category I requirements derives from Position C.1.a of RG 1.29. Again, Westinghouse takes exception to the use of RG 1.29. The deficiency of RG 1.29 applying to this case is the same one cited for RG 1.26.

4. Ever since the inception of the American Nucl ear Society (ANS) system of classification, Westinghouse has been using that system of classification. In the early days, internal Westinghouse interface criteria were applied; later, with the issue of American National Standards Institute (ANSI) N18.2a-1975, the interface criteria of that standard were used; all in recognition of the necessity of using good in terface criteria to fully and rationally classify equipment. Table Q005.4-1 identifies where in the RCPB, as defined in lOCFR50.2(v), non-nuclear safety (NNS) and nonseismic Category I pi ping is provided for this project; this is representative of previous pr ojects. In all cases, the inte rface criteria of ANSI N18.2a-1975 are used to ensure that classification is consistent with the exception criteria set forth in Footnote 2 of lOCFR50.55a for the RCPB and the requirements of lOCFR50, Appendix A, Criterion 55 are met for RCPB Containment penetrations. Piping arrangements have been shown for every plant for which Westinghouse has been the nuclear supplier since the ANS system of classification was adopted many years ago. The

drawings showing this were contained in respective SAR's and the pl ants were licensed on that basis.

5. It is Westinghouse policy to classify equipment on a rational basis with full consideration of safety. We feel this has been done in the instant case, others like it, and believe the safety of the plant has not been jeopardized in any way. In summary, the Westinghouse arrangements of pipi ng are not in violation of the regulation, nor has there been any neglect of the full consideration of safety.

STPEGS UFSAR Q&R 5.2-5 Revision 16 TABLE Q005.4-1 NNS PIPING IN RCP B Item Location Figure 1 ECCS check valve test lines for 6.3-1 a) accumulator 6.3-4 b) high head injection system c) low head injection system 2 accumulator nitrogen supply line 6.3-4 3 reactor coolant drain tank subsystem and supporting piping system 11.2-1 STPEGS UFSAR Q&R 5.2-6 Revision 16 Question 121.5 The inspection program requirements, as detailed in Request No. 121.1, have recently been revised to reflect information gained from recent inspection program reviews. Therefore, Request No. 121.1 is now superseded by the following request. We still require that your inspection program for Class 1, 2, and 3 components be in accordance with the revised rules in 10 CFR Part 50, Section 50.55a, Paragraph (g). To evaluate your inspection program, the following minimum information is necessary for our review:

(1) A preservice inspection plan to consist of the applicable ASME Code Edition and the exceptions to the code requirements.

(2) An inservice inspection plan submitted within six months of anticipated commercial operation. The preservice inspection plan will be reviewed to determine compliance with preservice and inservice requirements. The basis for the determination will be compliance with:

(1) The Edition of Section XI of the ASME Code stated in your FSAR or later Editions of Section XI referenced in the FEDERAL REGISTER that you ma y elect to apply.

(2) All augmented examinations established by the Commission when added assurance of structural reliability was deemed necessary. Examples of augmented examination requirements can be found in staff positions on (a) high energy fluid systems in SRP Section 3.2, (b) turbine disk integrity in SRP Section 10.2

.3, and (c) feedwater inle t nozzle inner radii. Your response should define the applicable Section XI Edition(s) and subsections. If any examination requirements of the Edition of Section XI in your FSAR can not be met, a relief request including complete technical justification to su pport your conclusion must be provided. The inservice inspection plan should be submitted for review within six months of anticipated commercial operation to demonstrate compliance with 10 CFR Part 50, Section 50.55a, Paragraph (g). Submittal at that time will permit you to incorporate Section XI requirements in effect six months prior to commercial operation and any augmented examination requirements established by the Commission. Your response should define all examination requirements that you determine are not practical within the limitations of design, geometry, and materials of construction of the components.

Response HL&P's inservice inspection (ISI) program for Class 1, 2, and 3 components is in compliance with the rules of 10CFR Part 50, Section 50.55a, Para graph (g). ASME Code Class 1, 2, and 3 components shall be examined in accordance with the applicable technical specifications and the requirements of the applicable edition/addenda of Section XI of the ASME Boiler & Pressure Vessel Code. The STPEGS UFSAR Q&R 5.2-7 Revision 16 Response (Continued) 1980 Edition of Section XI with addenda through the Winter 1981 Addenda was applied to the preservice inspection (PSI) of both units. The 19 83 Edition of Section XI with addenda through the Summer of 1983 Addenda was applied to the firs t ten year inspection in terval of both units.

The PSI and ISI plans contained a detailed listing of every weld and item required by the code to be examined, including all augmented examination requirements. The inspection plans identified all general exclusions, component exclusions and exceptions, code exceptions, and code-required examination exceptions. Relief requests including complete technical justification were submitted to

support our conclusions and request. Upon completion of their development, the PSI plans were submitted to the NRC prior to the start of PSI examinations. PSI summary reports containing the results of PSI examinations were submitted to the NRC prior to the issuance of the operating license of each unit. Upon completion of the PSI, the plans were revised and served as the basis for development of master ten-year ISI plans. The ISI plan for the first ten year inspection interval of each unit was submitted to the NRC within six months after the issuance of the operating license of each unit. The results of each ISI will be submitted to the NRC within ninety days after completion

of the inspections conducted duri ng a refueling outage, as requir ed by ASME Section XI, Section IWA-6000.

STPEGS UFSAR Q&R 5.2-8 Revision 16 Question 121.7 Provide a sketch of the STPEGS l and 2 reactor vessels (including dimensions) showing all longitudinal and circumferential welds, and al l forgings and/or plates. Welds should be identified by a shop control number (such as a procedure qualification number), the heat of filler metal, type and batch of flux, and the welding pr ocess. Each forging and/or plate should be identified by a heat number and material specification.

Response The STPEGS Unit 1 and Unit 2 reactor vessel ma terials identification, location, and material properties are tabulated in Tables 5.3-3 and 5.3-4, respectively.

Identification and location of the Unit 1 and Unit 2 reactor vessel beltline region materials are shown in Figures Q121.7-1 and Q121.7-2, respectively. Additional information for the beltline region materials is presented in the responses to items (3) and (4) of Question 121.8.

STPEGS UFSAR Q&R 5.2-9 Revision 16 Refer to Figure Q121.7-1

STPEGS UFSAR Q&R 5.2-10 Revision 16 Refer to Figure Q121.7-2

STPEGS UFSAR Q&R 5.2-11 Revision 16 Question 121.8 Supply the following information for each of the ferritic materials of the pressure-retaining components in the reactor c oolant pressure boundary of th e STPEGS 1 and 2 plants.

(1) The unirradiated mechanical properties as required by the testing programs in Section III of the ASME Code and Appendix G of 10 CF R Part 50 (test result s to be presented should include Charpy V-notch, dropweight, la teral expansion, tensile, upper shelf energy, T NDT and RTNDT). If any of these properties ha ve not been determined by a test method required by Appendix G of 10 CFR Part 50, state the actual te st procedure used and/or the method used to estimate the test result together with a complete technical justification for the procedure used and the associated test data.

(2) Identify the material(s) in the reactor coolant pressure boundary that will limit the pressure-temperature operating cu rves at the beginning-of-life. For each reactor vessel beltline weld, plate or forging provide the following additional information:

(3) The chemical composition (particularly the Cu, P, and S content) and the maximum end-of-life fluence.

(4) The relationship used to predict the shift in RT NDT and percent decrease in upper shelf energy as a function of neutron fluence.

(5) Identify the material(s) in the reactor coolant pressure boundary that will limit the pressure-temperature operating curves at the end-of-life.

Response 1. The ferritic pressure-retaining base materials and weldments of the STPEGS reactor vessels, steam generators, and pressurizers meet the fracture toughness requirements of Section III of the ASME Code (appropriate edition and/or addendum given in Table 5.2-

1) and Appendix G of lOCFR50.

The Unit l and Unit 2 reactor vessel material pr operties are tabulated in Tables 5.3-3 and 5.3-4, respectively.

The fracture toughness requirements satisfied by the steam generator a nd pressurizer base materials and weldments are discussed in Section 5.2.3.3.1. As stated in Section 5.2.3.3.1, the test results for steam generator and pressurizer materials are given in the QA data package which is provided to Houston Lighting and Power Company.

2. The materials that limit the pressure-temperatu re operating curves at the beginning-of-life are identified in Tables Q121.8-lc and Q121.8-2c for Un it l and Unit 2, respectively.

STPEGS UFSAR Q&R 5.2-12 Revision 16 Response (Continued)

3. The chemical composition of the Unit l reactor vessel beltline region plate and weld materials is given in Tables Q121.8-la and Q121.8-lb. The chemical composition of the Unit 2 beltline materials is given in Tables Q121.8-2a and Q121.8-2b. The maximum end-of-life fluence at the inne r wall and at 1/4 T is given in Tables Q121.8-lc and Q121.8-2c for Un it l and Unit 2, respectively.

4. Shift in RT NDT and decrease in upper shelf energy predicted using the Regulatory Guide 1.99 and the Westinghouse methodologies are given in Tables Q121.8-lc and Q121.8-2c for Unit l and Unit 2, respectively.

5. The materials that limit the pressure-temperatu re operating curves at the end-of-life are identified in Tables Q121.8-lc and Q 121.8-2c for Unit 1 and Unit 2, respectively.

STPEGS UFSAR Q&R 5.2-13 Revision 16 TABLE Q121.8-la SOUTH TEXAS UNIT NO. 1 REACTOR VESSEL BELTLINE PLATE CHEMICAL COMPOSITION Intermediate Shell Lower Shell Heat No. B8120-2 B8120-1 C4326-2 B9566-2 B9575-2 B9575-1 Plate No. R1606-1 R1606-2 R1606-3 R1622-1 R1622-2 R1622-3 C 22 .19 .25 .22 .21 .21 Mn 1.24 1.18 1.43 1.31 1.40 1.39 P 009 .008 .007 006 .006 .007 S .015 .013 .018 .014 .010 .013 Si .19 .19 .21 .20 .26 .25 Ni .63 .61 .62 .61 .64 .66 Cr .03 .03 .07 .05 .05 05 Mo .56 .53 .61 .58 .60 .60 Cu .04 .04 .05 .05 .07 .05 V .004 .004 .004 .002 .003 .003 Cb <.01 <.01 <.01 <.01 <.01 .01 Pb N.D. N.D. N.D. <.001 <.001 <.001 W .01 <.01 <.01 <.01 <.01 <.01 As .003 .003 .004 .005 .003 .005 Sn .002 .002 .003 .003 .005 .006 Co .011 .012 .011 .009 .006 .007 N2 .009 .008 .009 .010 .011 .008 Al .016 .017 .017 .019 .027 .029 B <.001 <.001 <.001 <.001 <.001 <.001 Ti <.01 <.01 <.01 <.01 <.01 <.01 Zr <.001 <.001 <.001 <.001 <.001 <.001 Q&R 5.2-14 STPEGS UFSAR Revision 16 TABLE Q121.8-1b SOUTH TEXAS UNIT NO. 1 REACTOR VESSEL BELTLINE REGION WELD CHEMICAL COMPOSITION Weld Weld Control Weld Wire Flux Chemical Composition (%)

Location Process No. Type Heat No. Type Lot No. C Mn P S Si Ni Cr Mo Cu V Inter. and Lower Sub-arc G1.70 B4 89476 Linde 0145 .14 1.19 .004 .012 .13 .07* .01 .47 .02* .003 Shell Long Seams 0091

Inter. To Lower Sub-arc E3.13 B4 89476 Linde 1061 .10 1.33 .007 .010 .48 .07* .02 .52 .02* .003 Shell Girth Seam 124

• Based on CE NPSD-1039 Rev. 1, "Best Estimate Copper And Nickel In CE Fabricated Reactor Vessel Welds."

Q&R 5.2-15 STPEGS UFSAR Revision 16 TABLE Q121.8-1c SOUTH TEXAS UNIT NO. 1 REACTOR VESSEL BELTLINE REGION MATERIAL INFORMATION BELTLINE PLATE MATERIAL MAXIMUM END-OF-LIFE Fluence (10 19 N/cm 2) RT NDT ( F) Use (Ft-Lb) Average T NDT RT NDT Use Inner Inner Wall 1/4 T Inner Wall 1/4 T Plate No. F F Ft-Lb Wall 1/4 T RG 1.99 W RG 1.99 W RG 1.99 W RG 1.99 W R1606-1* -40 10 109.5 2.1 1.2 65 93 5.0 81 24.5 8 21.5 8 R1606-2 -20 0 94.0 2.1 1.2 58 93 5.0 81 21.0 8 18.5 8 R1606-3* -20 10 105.5 2.1 1.2 58 93 5.0 81 23.5 10 21.0 10 R1622-1 30 111.0 2.1 1.2 58 93 5.0 81 25.0 10 22.0 10 R1622-2 30 122.0 2.1 1.2 58 93 5.0 81 27.5 14 240 14 R1622-3 30 127.0 2.1 1.2 58 93 5.0 81 28.5 10 25.0 10

• Material that will limit the pressure-temperature operating curves at the beginning and end of life.

BELTLINE WELD MATERIAL MAXIMUM END-OF-LIFE Fluence (10 19 N/cm 2) RT NDT ( F) Use (Ft-Lb) Average Weld Weld T NDT RT NDT Use Inner Inner Wall 1/4 T Inner Wall 1/4 T Seam No Control No.

F F Ft-Lb Wall 1/4 T RG 1.99 W RG 1.99 W RG 1.99 W RG 1.99 W 101-124A & G1.70 50 158 68 .39 . 50 70 50 60 27.5 6 24.0 3 101-142A 101-124B&C G1.70 50 158. 1.20 68 50 80 50 70 31.5 6 27.0 6 &101-142 B&C 101-171 E3.13 70 100 2.10 1.20 58 93 50 81 22.5 6 20.0 6

STPEGS UFSAR Q&R 5.2-16 Revision 16 TABLE Q121.8-2a SOUTH TEXAS UNIT NO. 2 REACTOR VESSEL BELTLINE CHEMICAL COMPOSITION Intermediate Shell Lower Shell Heat No. NR62067-1 NR62230-1 NR62248-1NR64647-1NR64627-1 NR64445-1 Plate No. R2507-1 R2507-2 R2507-3 R3022-1 R3022-2 R3022-3 C .22 .23 .21 22 .22 .23 Mn 1.55 1.53 1.50 1.46 1.46 1.49 P .006 .006 .005 .002 .003 .004 S .012 .007 .007 .008 .008 .014 Si .21 .25 .22 .19 .20 .20 Ni .65 .64 .61 .63 .61 .60 Cr .05 .03 .05 .02 .02 .03 Mo .56 .55 .53 .49 .51 .51 Cu .04 .05 .05 .03 .04 .04 V .002 .002 .002 .002 .002 .002 Cb <.01 <.01 .01 <.01 <.01 <.01 Pb <.001 <.001 <.001 <.001 <.001 <.001 W <.01 <.01 <.01 <.01 <.01 <.01 As .014 .018 .012 .011 .009 .010 Sn <.001 .001 .001 .001 .001 .002 Co .011 .013 .014 .009 .009 .012 N2 .009 .010 .011 .011 .011 .014 Al .021 .022 .025 .020 .018 .023 B <.001 <.001 <.001 <.001 <.001 <.001 Ti <.01 <.01 <.01 <.01 <.01 <.01 Zr .001 .001 .001 <.001 <.001 <.001 Q&R 5.2-17 STPEGS UFSAR Revision 16 TABLE Q121.8-2b SOUTH TEXAS UNIT NO. 2 REACTOR VESSEL BELTLINE REGION WELD CHEMICAL COMPOSITION Weld Weld Control Weld Wire Flux Chemical Composition (%)

Location Process No. Type Heat No. Type Lot No. C Mn P S Si Ni Cr Mo Cu V Inter. and Lower Sub-arc G3.02 B4 90209 Linde 1054 .14 1.27 .004 .009 .16 .11* .11 .53 .04* .006 Long Seams 0091

Inter. To Lower Sub-arc E3.12 B4 90209 Linde 1061 .10 1.31 .008 .010 .52 .11* .08 .50 .04* .007 Shell Girth Seam 124 And Lower Shell Long. Seams

• Based on CE NPSD-1039 Rev. 2, "Best Estimate Copper And Nickel In CE Fabricated Reactor Vessel Welds." Sample weighted mean.

Q&R 5.2-18 STPEGS UFSAR Revision 16 TABLE Q121.8-2c SOUTH TEXAS UNIT NO. 2 REACTOR VESSEL BELTLINE REGION MATERIAL INFORMATION BELTLINE PLATE MATERIAL MAXIMUM END-OF-LIFE Fluence (10 19 N/cm 2) RT NDT ( F) Use (Ft-Lb) Average T NDT RT NDT Use Inner Inner Wall 1/4 T Inner Wall 1/4 T Plate No. F F Ft-Lb Wall 1/4 T RG 1.99 W RG 1.99 W RG 1.99 W RG 1.99 W R2507-1* 10 109 1.9 1.1 55 90 50 78 24.0 8 21.5 8 R2507-2* 10 129 1.9 1.1 55 90 50 78 28.5 10 25.0 10 R2507-3 40 122 1.9 1.1 55 90 50 78 27.0 10 24.0 10 R3022-1 30 124 1.9 1.1 55 90 50 78 27.5 6 24.0 6 R3022-2 40 118 1.9 1.1 55 90 50 78 26.0 8 23.0 8 R3022-3 40 123 1.9 1.1 55 90 50 78 27.0 8 24.0 8

• Material that will limit the pressure-temperature operating curves at the beginning and end of life.

BELTLINE WELD MATERIAL MAXIMUM END-OF-LIFE Fluence (10 19 N/cm 2) RT NDT ( F) Use (Ft-Lb) Average Weld Weld T NDT RT NDT Use Inner Inner Wall 1/4 T Inner Wall 1/4 T Seam No Control No.

F F Ft-Lb Wall 1/4 T RG 1.99 W RG 1.99 W RG 1.99 W RG 1.99 W 101-124A G3.02 70 146 .62 .36 50 67 50 58 25 10 22 5 101-124B&C G3.02 70 146 1.1 .62 50 78 50 67 28.5 10 25 10 101-142A E3.12 70 101 .62 .36 50 67 50 58 17 10 15 5 101-142B&C E3.12 70 101 1.1 .62 50 78 50 67 19.5 10 17 10 101-171 E3.12 70 101 1.9 1.1 55 90 50 78 22 10 19.5 10

STPEGS UFSAR Q&R 5.2-19 Revision 16 Question 121.16 Confirm that the reactor vessel fasteners for Units 1 and 2 will be inspected according to the requirements of Sections III and XI of the ASME Code as supplemented by Regulatory Guide 1.65, "Materials and Inspections for Reactor Vessel Closure Studs." Response ASME Section III During fabrication, the nondestructive examination of the STPEGS Units l and 2 reactor vessel fasteners (studs) was performed in accordance with the requirements of the AS ME Code Section III, as supplemented by Regulatory Guide 1.65, "Materials and Inspections for Reactor Vessel Closure Studs." Specifically, the bolting ma terial, including nuts and washers, was ultrasonically examined after heat treatment in accordance with ASME SA-388, "Ultrasonic Examination of Heavy Steel Forgings." The calibration location used to establish the first back reflection for the radial ultrasonic testing was based on good sound representative material; to assure that the material is respresentative, the selection of the reference location was based on a preliminary ultrasonic examination of material representing at least three units of an item. In addition, as stated in Section 5.3.1.3.3 of the STPEGS UFSAR, magnetic particle or liquid penetrant examination was performed on all exterior closure stud surfaces and all nut surfaces after final machining or rolling.

ASME Section XI During preservice and the first interval of inservice inspections, the reactor vessel closure studs, including nuts and washers, were examined in accordance with ASME Section XI as supplemented by ASME Code Case N-307-1 and Regulatory Guide 1.65. Several NDE methods were used to accomplish examinations as described below. A surface examination was performed on the entire outside surface of the stud and the inside surface of the stud excluding the 0.625-inch diameter porti on of the inside bore and the non-load bearing region of the stud above the threads. Surface examination were performed with Fluorescent MT and PT methods. Examination of the 0.625-inch diameter bore hole is performed with a high angle refracted longitudinal wave UT sound beam. The out er 1/4" of the shaft, threads and "Roto-Lok" lugs were examined with a combination UT45° a nd UT60° refracted shear wave from the inside surface of the stud (excluding the 0.625-inch bore) and a UT60° refracted shear wave from the 0.625-inch bore.

STPEGS UFSAR Q&R 5.2-20 Revision 16 Response (Continued) The outside surface of the RV nuts was examined with a Fluorescent MT examination. The inside threaded surface of the nut was not accessible for a technically adequate surface examination. In lieu of the surface examination of th e threaded surfaces of the RV nut, an ultrasonic examination was performed on the threaded region from the OD and end surface of the nut. The UT examination provided coverage of the thread root area in two directions. A UT0° examination was performed 360° around the nut end surface to examine the threaded area for circumferential flaws. A UT43° examination from the OD was used to examine the threaded area in clockwise and counterclockwise directions to detect axial flaws. A Relief Request (RR-ENG-12) was approved by the NRC for UT of the threaded area of the RV nuts in lieu of the ASME Section XI required surface examination. A visual (VT-1) examination was performed on the washers as required by ASME Section XI.

ASME Section XI - Second Inspection Interval

During the second inspection interv al, the reactor vessel closure st uds, including nuts and washers, are examined in accordance with ASME Section XI as supplemented by ASME Code Case N-307-2.

Since the inservice inspection requirements of Regulatory Guide 1.65 (regulatory position C.4) are now addressed in Section XI, the South Texas Pr oject has discontinued its inservice inspection commitment to Regulatory Guide 1.65. The South Texas Project performs PT and/or MT surface examinations on RPV closure studs removed from the vessel flange during refueling outages in accordance with Section XI scheduling requirements. These examinations are evaluated in accordance with Section XI acceptance standards in lieu of the Section III acceptance standards cited in the regulatory guide. The Section XI standards are more appropriate for service-induced flaws or degradation. Several NDE methods are used to accomplish examinations similar to those used during preservice and the first interval inservice inspections.

The above techniques may be modified as necessary if the modified technique can be demonstrated to be equivalent or superior to t hose already being used. This woul d be in accordance with ASME Section XI, Paragraph IWA-2240. The above techniques or requirements may also be modified as allowed by later mandated and adopted ASME Section XI Code editions per 10CFR50.55a.

STPEGS UFSAR Q&R 5.2-21 Revision 16 Question 122.7 Verify whether or not the vessel su pports, the seal ledge, and the he at lifting lugs are part of the Reactor Coolant Pressure Boundary. If they are, provide the unirradiated mechanical properties to the same extent as requested previously by Part 1 of Question 121.8 for the ferritic materials of the pressure-retaining components in the RCPB. Discuss or tabulate separately the mechanical properties of the components fabricated from SA533 Class 2 material. Also, provide the specific welding materials and their specifications as requested in Item 122.6, above.

Response The vessel supports, seal ledge, and head lifting bosses are not pressure retaining parts of the reactor vessel. The vessel supports are weld metal buildup of ASME welding material specifications SFA 5.4 and SFA 5.5. The seal ledge is SA516 Gr 70, weld ed to the reactor vessel flange using ASME welding material specification SFA 5.1. The head lifting bosses for the replacement head on Unit 1 are SA508 Class 3 welded to the replacement head forging using ASME welding material specifications SFA 5.5. CN-2994 STPEGS UFSAR Q&R 5.2-22 Revision 16 Question 122.8 In Table 5.2-2 change Code Case 1432-2 to Code Case 1423-2. The former designation pertains to SA 516 Grade 55 carbon steel plates.

Response The Code Case 1432-2 designation for reactor coolant piping branch nozzles is a typographical error; this should be Code Case 1423-2.

STPEGS UFSAR Q&R 5.2-23 Revision 16 Question 122.9 Weld cladding procedures do not have to be qualified for use in accordance with Position C.2 of Regulatory Guide 1.43, "Control of Stainless Steel Weld Cladding of Low-Alloy Components", when applied to SA 533 Grade B Class 1 plate made to fi ne-grain practice and heat-treated to develop a fine-grained structure. Provide the grain sizes of the SA 533 material and the forging grade SA 508 Class 3 material for which no qualifications are required by Westinghouse when cladding RCPB ferritic steel components. In addition, give the degree of conformance with Position C.3 of Regulatory Guide 1.43.

Response The Westinghouse practice re garding qualification weld cladding procedures is not based on specific grain size considerations. Instead, the primary aspect of determining the need for qualification is the susceptibility of a material to underclad cracking. Data have shown that SA533 and SA508 Class 3 materials made to fine grain practice (i.e., addition of aluminum and quenched and tempered resulting in a fine grain structure) exhi bit resistance to underclad cracking, while SA508 Class 2 material is susceptible to underclad cracking.

Therefore, as stated in Secti on 5.2.3.3.2, qualification is required for high heat input processes, such as the submerged-arc wide-strip welding process and the submerged-arc 6-wire process, used as SA508 Class 2 material.

Production welding is monitored to ensure that essential variables remain within the limits established by the qualification. If the essential variables exceed the qualification limits, an evaluation will be performed to determine if the cladding is acceptable for use.

STPEGS UFSAR Q&R 5.2-24 Revision 16 Question 122.10 Provide the basis for Westinghouse not applying to Class 2 and 3 ferritic steel components of the RCPB any of the recommendations of Regulatory Guide 1.50, "Control of Preheat Temperature for Welding of Low-Alloy Steel".

Response Westinghouse experience has shown that high integrity low-alloy steel weldment quality is obtainable with proper control of welding materials and variab les along with qualification of procedures, as required by the ASME Code Sections III and IX, and without maintaining the preheat temperature until a post weld heat treatment has been performed, as recommended by Regulatory Guide 1.50. Welding of Class 2 and 3 ferritic stee1 components is performe d in accordance with the requirements of the ASME Code Sections III and IX.

In addition, it should be pointed out that the development of restrictive preheat requirements in the past has been related primarily to practices used for weldments in thick sections (greater than six inches). These thick section c onsiderations encountered on Class 1 equipment are not generally applicable to Class 2 and 3 ferritic steel components.

STPEGS UFSAR Q&R 5.2-25 Revision 16 Question 122.11 Provide the degree of conformance with the preheat recommendations of the ASME Code,Section III, Appendix D, D 1200, during procedure qualifi cation and production welding of ferritic steel components of the RCPB, the engineered safety features, and the Steam and Feedwater System.

Response NSSS Scope Preheat practices utilized on Class 1 reactor coolant pressure boundary components (reactor vessel, steam generators, pressurizer) are in compliance with the recommendations of the non-mandatory Appendix D of the ASME Code,Section III. The recommendations of this non-mandatory appendix are not imposed upon suppliers of Class 2 and 3 auxiliary equipment; furthermore, a survey of vendor manufacturing procedures for Class 2 and 3 equipment has not been performed to determine the degree of conformance with the non-mandatory Appendix D on Class 2 and 3 auxiliary equipment.

However, welding procedures for all ASME Code classified equipment comply with all applicable mandatory requiremets of the ASME Code.

BOP Scope Field Erection Welds

Welding procedures for all ASME Code classified equipment were qualified in accordance with Section IX and all the mandatory requirements of the code. In the development of these procedures, the recommendations found in the nonmandatory preheat procedures (ASME Code Section III, Appendix D) were considered and the specified preheat temperatures comply with the suggested minimum preheat temperatures.

STPEGS UFSAR Q&R 5.2-26 Revision 16 Question 122.12 Provide information on the moisture control for low-hydrogen, covered-arc-welding electrodes when welding ferritic steel components of the RCPB, the engineered safety features, and the Steam and Feedwater System. Give the degree of conformance with the requirements of the AWS Dl.1, "Structural Welding Code".

Response The requirements of AWS Dl.1, Section 4.5, "Structural Welding C ode Electrodes for Shielded Metal Arc Welding", are met. Both Westinghouse and B&R follow the recommendations in AWS Dl.1, Section 4.5.2.1, "Approved Atmospheric Exposure Time Periods", for permissible atmospheric exposure of low-hydrogen electrodes.

STPEGS UFSAR Q&R 5.2-27 Revision 16 Question 122.13 For all applicable components of the RCPB and the engineered safety features, shop-welded or field-welded, of ferritic steel or austenitic stainless steel, give the degree of conformance with the recommendations of Regulatory Guide 1.71, "Welder Qualification for Areas of Limited Accessibility".

Response Westinghouse practice requires welder qualification to ASME Code,Section III and IX requirements.

Experience shows that the current Westinghouse shop practice produces high quality welds. Limited accessibility qualification or requalification, as described by Regulatory Guide 1.71, "Welder Qualification for Areas of Limited Accessibility", is an unduly restrictive requirement for component manufacture, where the welders' physical position relative to the welds is controlled and does not present any significant problems. In addition, shop welds of limited acce ssibility are repetitive due to multiple production of similar components, and such welding is closely supervised and monitored. Further assurance of acceptabl e weld quality is provided by the performance of required nondestructive evaluations. Field Erection Welds: Field erection welds, including limited access welds, are made by welders and/or welding operators trained and qualified in accordance with ASME Section IX using welding procedures properly qualified to meet the requireme nts of ASME Section III and Section IX. Before welding, the accessibility is checked and during welding, each limited access production weld is monitored for adherence to the proper welding procedure, parameters and te chniques. In addition, the acceptability of prod uction welds is checked by the performance of the requi red nondestructive examinations.

STPEGS UFSAR Q&R 5.2-28 Revision 16 Question 211.10 In Section 5.2.2 references are made to WCAP-7769. Provide a comparison of South Texas parameters for all parameters listed in Table 2-2. Where differences exist, show that these differences will not affect the conservatism of the results given in WCAP-7769.

Response WCAP-7769, Revision 1 differentiates between the loss of load transient with the steam dump and Reactor Coolant System (RCS) pressure control systems functioning and the turbine trip event. The transient as discussed in the WCAP (p. 3-35) is the turbine trip event without direct reactor trip. That the UFSAR depicts a higher peak pressure than that shown in the WCAP (Fi gure 3-24) is due to rod motion delay time. WCAP-7769 assumed one second for rod motion following r eactor trip set-point versus two seconds assumed for the UFSAR. The 2-second delay is not unique to South Texas.

Table 2-2 from WCAP-7769 (Table Q 211.10-1) is provided with South Texas parameters provided in the far right column. As stated in the WCAP the pressurizer safety valve is sized based on the peak surge rate into the pressurizer following a complete loss of load without reactor trip and with en ergy relief only thru the steam generator (SG) and pressurizer safety valves. The actual safety valve capacity must be equal to or greater than the required capacity.

The ratio of the actual safety valve capacity and the peak surge rate is an entry in Table 2-2. If this ratio is greater than the ratio for that type of plant listed in Table 2-2, then the assumptions of the WCAP envelope the plant in question. The value for a 4-loop plant is given as l.056. The value of this ratio for South Texas is 1.l4. That is the cap acity of the safety valve is 1.14 times greater than the surge rate into the pressurizer. Numerous analyses have been performed in support of the EPRI Safety and Relief Valve Test Program (NUREG-0737, Item II.01) where in RCS overpressure protection was addressed similar to that in WCAP-7769. Indeed this particular transi ent was analyzed for the enveloping (worst case) 4-loop plant and presented in a repo rt "Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves in Westinghouse-Designed Plants". EPRI Report NP-2296-LD, March, 1982. The maximum pressurizer pressure reported for this limiting event, 4-loop plant, was 2555 psia, which agrees quite well with that shown in the UFSAR (approximately 2560 psia). For the enveloping plant, the analysis c onducted with the reac tor tripping on the sec ond Reactor Protection System (RPS) signal shows a peak pressurizer pressure of 2565 psia. The differences between the two reactor trip points (approximately two seconds) is diluted considering sa fety valve sizing and the assumptions for safety valve flow rate versus pressure used in the analyses (linear, from 0 to l00 percent over the pressure range of 2500 to 2575 psia).

STPEGS UFSAR Q&R 5.2-29 Revision 16 Response (Continued) Figure 2-1 of the WCAP shows that only 90 percent of safety valve flowrate is required to turn around the overpressure transient assuming no reactor trip. With l00 percent of safety valve capacity, the pressurizer pressure p eaks at less than 2575 psia. With reactor trip occurring at the first reactor trip setpoint, approximately 60 percent of total safety valve flow rate was required to tu rn around the overpressure transient.

TABLE Q211.10-1 TYPICAL PLANT THERMAL-HY DRAULIC PARAMETERS Units 2-Loop 3-Loop 4-Loop South Texas Heat Output, Core MWt 1,780 2,652 3,411 3,800 System Pressure psia 2,250 2,250 2,250 2,250 Coolant Flow gpm 178,000 265,500 354,000 376,400 Average Core Mass Velocity 10 6 lb/hr-ft 2 2.42 2.33 2.50 -- Inlet Temperature F 545 544 522.5 560 Core Average Tmod F 581 580 588 596 Core Length FT 12 12 12 14 Average Power Density kw/1 102 100 104 99 Maximum Fuel Temperature F <4100 <4200 <4200 <4200 Fuel Loading kg/1 2.7 2.6 2.6 2.6 Pressurizer Volume Ft 3 1000 1400 1800 2100 Pressurizer Volume Ratioed to Primary System Volume 0.157 0.148 0.148 0.150 Peak Surge Rate for Pressurizer Safety Valve sizing Transient Ft 3/sec 21.8 33.2 41.0 51.5 Pressurizer Safety Valve Flow at 2500 psia - 3+ percent Accumulation Ft 3/sec 26.1 36.1 43.3 58.7 Ration of Safety Valve Flow to Peak Surge Rate 1.197 1.087 1.056 1.14 Full Power Steam Flow per Loop lb/sec 1078 1076 1038 1178 Nominal Shell-side Steam Generator Water Mass per Loop lb 100,300 106,000 106,000 139,000 STPEGS UFSAR

Q&R 5.2-30 Revision 16 STPEGS UFSAR Q&R 5.2-31 Revision 16 Question 211.11 Your statement that Brown & Root is responsible for the design and mounting of the supports for the pressurizer safety valves does not provide the necessary assurance that the valve mounts meet the Westinghouse criteria. Discuss th e anticipated loads on the safety valve supports and verify that loading due to water relief, incl uding the passage of a water slug and the effects of water hammer have been considered.

Response Westinghouse now has the responsibili ty for the design, fabrication, and supervision of installation of the pressurizer safety and relief valve manifold assembly. The design of this assembly, including valve supports, has been completed. Loads due to water relief, including the passage of a water slug and the effects of water hammer have been considered. Stresses are within code allowable limits.

STPEGS UFSAR Q&R 5.2-32 Revision 16 Question 211.12 Your response to Question 211.2 is not acceptable. Per the requirements of BTP RSB 5-2 the low temperature overpressure protection system must be designed to meet the requirements of IEEE 279 and must be designed to function dur ing an operating basis earthquake.

Provisions to allow testing prior to shutdown must be prov ided to assure operability of the system.

Provide a discussion of a direct cu rrent bus failure which would cause isolation of letdown flow (fail closed valves) and initiate an overpressure transient. On some recently reviewed plants, this failure would simultaneously disable a PORV. If the DC bus failure was assumed to be the initiating event, the overpressure protection system would not meet the single failure criteria.

Response In accordance with the guidelines of BTP RSB 5-2, the cold overpressure protection system is designed to the guidance of IEEE 279 and is de signed to function during an operating basis earthquake.

Provisions to allow testing of this cold overpressure protection system are provided.

The STPEGS design is not subject to the postulated failure of a power-operated relief valve (PORV) and simultaneous isolation of letdown by the failure of a DC bus. Two of the three parallel letdown orifice isolation valves are fail-cl osed valves in the letdown line inside Containment. However these valves are powered from Class 1E AC power, rather than DC. The failure of a DC vital bus may result in the loss of one PORV but will not cause any valve in the letdown line inside Containment to change positions. If the letdown line has been in service when the DC bus failure occurs, causing the loss of a PORV, the valves in the letdown line between the RCS and the letdown relief valve will remain open. Thus, in addition to the unaffected PO RV, the letdown relief valve (with a set pressure of 600 psig) is available to provide RCS overpressure protection with one or more charging pumps in operation. In addition, the redundant PORV is on a different DC bus and will be operable at this time.

STPEGS UFSAR Q&R 5.2-33 Revision 16 Question 250.3N -

Deleted STPEGS UFSAR Q&R 5.2-34 Revision 16 Question 250.4N If the reactor coolant pipe and/or fittings are fabricated from SA351, Grade CF8A (centrifugal cast stainless steel), discuss the effectiveness of your ultrasonic examinati on procedures and the ability of the instrumentation to detect flaws, if they exist, in the volume of the cast stainless steel weldments required to be examined by the regulations.

Response The ultrasonic examination procedure which was used to examine welds in SA351, Grade CF8A (Centrifugal Cast Stainless Steel) piping during the preservice in spection (PSI) of STPEGS Unit 1 meets the requirements ASME Code Section XI.

This refracted longitudinal wave ultrasonic examination procedure has been acceptable to the NRC in meeting the inservice inspection (ISI) regulatory requirements at several other PWR plants. HL&P is aw are that recent studies by research organizations indicate that th e acoustic properties of SA351, Grade CF8A material may reduce the effectiveness of some ultrasonic examination pro cedures for flaw detection. HL&P is currently evaluating potential methods for determining the effectiveness of the procedure which will be used.

STPEGS UFSAR Q&R 5.2-35 Revision 16 Question 250.6N All preservice examination requirements defined in Section XI of the ASME Code that have been determined to be impractical must be identified and a supporting technical justification must be provided. The relief requests should include at least the following information:

1. For ASME Code Class 1 and 2 components, provide a table similar to IWB-2500 and IWC-2500 confirming that either the entire Section XI preservice examination was performed on the component or relief is requested with a technical justification supporting your conclusion.

2. Where relief is requested for pressure retaining welds in the reactor vessel, identify the specific welds that did not receive a 100 percent preservice ultrasonic examination and estimate the extent of the examination that was performed.

3. Where relief is requested for piping system welds (Examination Category B-J, C-F, and C-G), provide a list of the specific welds that did not receive a complete Section XI preservice examination including drawing or isometric identification number, system, weld number, and physical configuration (e.g., pipe-to-nozzle weld, etc.). Estimate the extent of the preservice examination that was performed. When the volumetric examination was performed from one side of the weld, discuss whether the entire weld volume and the heat-affected-zone (HAZ) and base metal on the far side of the weld were examined. State the primary reason that a specific examination is impractical (e.g., support or component restri cts access, fitting prevents adequate ultrasonic coupling on one side, component-to-component weld prevents ultrasonic examination, etc.). Indicate any alternative or supplemental examinations performed and method(s) of fabrication examination.

Response During and/or after the preservice inspection (PSI) of STPEGS Unit 1, HL&P will identify and document any Section XI examination requirements determined to be impractical and provide technical justification for such determination. Documentation of the compliance of the PSI program with Section XI examination requirements will be provided. Where applicable, requests for relief will be submitted in accordance with the criteria specified in this question.

STPEGS UFSAR Q&R 5.2-36 Revision 16 Question 440.14N FSAR Section 5.2.2 states that the transient for wh ich the overpressure protection requirements are determined is a complete loss of steam flow to the turbine, no reactor trip, with credit taken for the steam generator safety valves and maintaining main feedwater (MFW) flow. However, WCAP-7769, Rev. 1, which is referenced in the FSAR, also states that for plants having turbine driven MFW pumps another analysis is required, i.e., a simultaneous loss of load and MFW, with credit taken for Doppler feedback and reactor trip (other than reactor trip on turb ine trip) and no credit taken for PORV, ADV, and steam dump ope ration, reactor and pressurizer controls and spray. Discuss whether this analysis was performed for STPEGS, and what the results were.

Response WCAP-7769 discusses the generic met hodology for sizing safety valves. It is intended to relate this methodology to a typical plant. The results presen ted in the WCAP are not intended to demonstrate that the STPEGS complies with ASME Code requirements. Such compliance is demonstrated in an overpressure protection report specifically for the STPEGS which is prepared in accordance with Article NB-7300 of Section III of the ASME Code. Section 5.2.2 will be modi fied to clarify this item. The following additional information may provide more insight into the process employed to verify that adequate Reactor Coolant System (RCS) overpressure protection is provided:

Verification of adequate overpressure protection for the RCS is accomplished in several stages. Initially, all transients that may cause overpressurization of the RCS are identified. That transient which is anticipated to result in the maximum system pressure and maximum safety valve capacity is then chosen as the design transient for determining the actual safety valve capacity to be provided.

This design transient is then analyzed, utilizing input parameters that are conservatively chosen to result in a higher RCS pressure and safety valve capacity requirement.

Following selection of the valve capacity, the overpressure transients previously identified are analyzed to verify that the chosen capacity results in peak RCS pressures within that identified in Article NB-7000 of Section III of the ASME Code.

For STPEGS, the protection is afforded for the follo wing events which envelop those credible events which could lead to overpressure of the RCS if adequate overpressure prot ection were not provided:

1. Loss of Electrical Load and/or Tu rbine Trip (Sections 15.2.2 and 15.2.3)

2. Uncontrolled Rod Withdraw al at Power (Section 15.4.2)

3. Loss of Reactor Coolant Flow (Section 15.3)

4. Loss of Normal Feedwater (Section 15.2.7)

5. Loss of Offsite Power (LOOP) to th e Station Auxiliaries (Section 15.2.6)

STPEGS UFSAR Q&R 5.2-37 Revision 16 Response (Continued) Review of these transients shows that the turbine trip transient results in the maximum system pressure and the maximum safety valve relief requirements. Therefore, to determine the required safety valve capacity, the turbine trip transient wa s analyzed, with additional conservatisms included over those considered for Chapter 15 analyses. The sizing of the pressurizer safety valves was based on analysis of a complete loss of steam flow to the turbine with the reac tor operating at 102 percent of the engineered safeguards design power. In this analysis, feedwater (FW) flow was assumed to be lost; (This is more conservative than maintaining (FW) flow in that it reduces heat transfer capability thereby increasing primary system pressure). No credit was taken fo r operation of pressurizer power operated relief valves (PORVs), pressurizer level control system, pressurizer spray system, rod control system, steam dump system, or steam line (PORVs). The reactor was maintained at full power (no credit for reactor trip), and steam relief through the steam ge nerator (SG) safety valves was considered. The maximum surge rate into the pressurizer during this transient was identified and a total safety valve capacity in excess of this value was chosen. As no reactor trip was assumed, the safety valves by themselves provide adequate capacity to turn around the overpressure transient.

Following selection of the safety va lve size and quantity the overpressur e transients listed above were analyzed. These analyses confirmed that the overpressure protection afforded the RCS is in accordance with ASME Code requirements. Discussion of those transients and their results is provided in Chapter 15.

STPEGS UFSAR Q&R 5.2-38 Revision 16 Question 440.17N Has the delay due to the time it takes to discharge the water from the pressurizer safety valve loop seals been accounted for in the limiting pressure transient? If it has not been accounted for, how would this delay affect the results?

Response The delay due to the time it takes to discharge the water from the pr essurizer safety valve loop seals has been accounted for in the limiting pressure transient.

STPEGS UFSAR Q&R 5.2-39 Revision 16 Question 440.18N WCAP-7769, Section 3.4 assumes failure of one steam generator safety relief valve per loop. Provide assurance that your remaining safety valves can provide the required minimum capacity.

Response As stated in the WCAP the maximum steam generator (SG) safety valv e required capacity is 78 percent of the provided capacity for the limiting case which is the loss of electrical load transient.

Twenty safety valves are provided. If 78 percent of the valves open, 78 percent of the total provided relieving capacity is available. Sixteen valves would provide 80 percent of the total relieving capacity.

STPEGS UFSAR Q&R 5.2-40 Revision 16 Question 440.20N Section 5.4.13 cites a backpressure compensation feature on the pressuri zer safety valves. Provide a discussion of this feature which explains how this function is performed.

Response Backpressure compensation for the pressurizer safety valves is provided by a balancing bellows and balancing piston. These features ar e incorporated in Crosby style HB safety valves and were tested as part of the recently completed EPRI safety valve test program (NUREG-0737, Item II.D.1). The results from these tests demonstrat ed that backpressure has little if any effect on valve performance.

STPEGS UFSAR Q&R 5.2-41 Revision 16 Question 440.21N For RCS pressure control during low temperature operation, discuss whether the analyses performed to determine the maximum pressure for the postulated worst case mass and heat input events assumed relief by the pressurizer PORVs only or whether credit is also taken for the RHR relief valves. If credit is taken for the RHR relief valves, then demonstrate that the overpre ssure protection functions would not be defeated by interlocks which would isolate the RHR system, or by common mode failures (e.g., failure of a DC bus). See also Question 440.28N.

Response No credit is taken for the Residual Heat Removal (RHR) relief valves in the Cold Overpressure Mitigation System (COMS) analysis. In the COMS analysis it is assumed only one power-operated relief valve (PORV) is available for RCS pressure mitigation.

STPEGS UFSAR Q&R 5.2-42 Revision 16 Question 440.22N In accordance with Section 5.2.2.11.2 the bounding mass input analysis for RCS pressure control during low temperature operation was performed assuming letdown isolation with 2 charging pumps operating. There has been an operating plant inci dent involving inadvertent SI pump actuation during low temperature conditions. Our position is that the low temperat ure overpressure protection system (LTOPS) be designed to handle actuation of one high head safety injection (HHSI) pump. Therefore discuss whether the STPEGS LTOPS has sufficient capacity for this type of transient.

Response In accordance with WCAP-10529, "Cold Overpressure Mitigation System", we assume in the Cold Overpressure Mitigation System (COMS) analysis that a charging/letdown flow mismatch results from the isolation of letdown in coincidence with the inadvertent st art of a charging pump, delivering full flow. Consistent with standard Technical Specification 3.5.3 during low temperature operation the high-head safety injection (HHSI) pumps will be locked out of service.

STPEGS UFSAR Q&R 5.2-43 Revision 16 Question 440.24N In Section 5.2.2.11.1 of the FSAR, you indicate that an auctioneered system temperature is continuously converted to an allo wable pressure and then compared to the actual RCS pressure. "This comparison will provide an actuation signal to the PORVs when require d, to prevent pressure-temperature conditions from exceeding the allowable limits". Our review of the low temperature overpressure protection design for ce rtain other Westinghouse plants i ndicates that a failure in the temperature auctioneer for one PORV (signalling it to remain closed) could al so fail the other PORV closed (by denying its permissive to open). Address this concern about a potential common mode failure in the low temperature overpressure protection system for STPEGS.

Response Past Cold Overpressure Mitigation System (COMS) logic called for the output of the temperature auctioneer of either train to serve as a permissive for the other train's pow er-operated relief valve (PORV). This is not the case for STPEGS. Failure of the temperature auc tioneer will only disable the PORV in one train.

STPEGS UFSAR Q&R 5.2-44 Revision 16 Question 440.25N Provide your limiting Appendix G curve for the first eighteen full power months of operation. Discuss the operational procedures which will minimize the likelihood of an overpressure event.

Response See the response to MEB Q251.14N a nd Figures Q251.14N-1 through Q251.14N-4.

STPEGS UFSAR Q&R 5.2-45 Revision 16 Question 440.26N The staff is concerned that your proposed LTOP system does not adequately protect the reactor vessel during transient events where the vessel wall temperature lags behind the temperature used in the variable setpoint ca lculator. For example, starting a RCP in a loop with a hot steam generator when the RCS is water solid causes the RCS pressure and temperature to rise. Your LTOP system would automatically raise the PORV setpoint as a function of auctioneered cold or hot leg temperature, but the vessel wall will not be heated in this transient at the same rate. Thus, due to the LTOP system auctioneering scheme, the part of the RCS most vulnerable to brittle fracture may not be adequately protected because the relief valves would open at a higher pressure than what the true vessel wall temperature would allow. If, during a cooldown, a mass input event occurred, your proposed LTOP system may not protect the coldest location in the vessel since the setpoint would not be based on the coldest fluid temperature.

Address the above concerns by discussing the following:

a. Discuss the events you considered when esta blishing the worst case scenario for LTOPs evaluation, show how the event selected is wors t case regarding vessel te mperature, and show how your LTOP system protects th e vessel at its coldest location.

b. Include in your analyses the most limiting single active failure, and justify the choice.

c. Include in your analyses the effects of system and component response times, including:

1. temperature detectors

2. pressure detectors

3. logic circuitry Show the response times that were assumed and the extent of conservatism in the assumed values.

Response a. The events considered when establishing the worst case scenario for Cold Overpressure Mitigation System (COMS) evaluation are documented in WCAP-10529, "Cold Overpressure Mitigation System". The worst case event from the standpoint of vessel temperature is the heat input transient. In the heat input transient we assume a reactor coolant pump (RCP) is started when the steam generator (SG) is 50°F hotter than the Reactor Coolant System (RCS). The conservatism built in to our setpoint determination algorithm ensures the coldest location

in the vessel is protected. For any given RCS temperature, setpoints are selected such that the Appendix G pressure limit is satisfied for the RCS temperature 50°F less than the temperature used in the analysis. For example, if selecting setpoints STPEGS UFSAR Q&R 5.2-46 Revision 16 Response (Continued) for a RCS temperature of 200°F, we select se tpoints that satisfy the Appendix G pressure constraints at 150°F.

b. In the COMS analysis it is assumed one power-o perated relief valve (PORV) is inoperative. This results in the availability of only one PORV for RCS pressure mitigation. c. 1. The response time of the temperature dete ctors are not considered in COMS analysis for the following reasons: In the case of the mass input transient we have isothermal conditions in the RCS, therefore the response time of the temperature detectors is not a factor. In the case of the heat input transient the temperature of the RCS is increasing. Delay in temperature detector response will result in a measured temperature that is less than the actual RCS temperature, which is conservative. 2. We assume there is a 0.6 second delay before the PORV starts to stroke. The breakdown is as follows:

• 0.4 sec pressure transmitter delay

• 0.1 sec solenoid actuation delay

• 0.1 sec logic circuitry delay 3. See item 2, above.

STPEGS UFSAR Q&R 5.3-1 Revision 16 Question 121.11 The pressure-temperature limit calculation methods gi ven in the Technical Specifications are those given in Topical Report WCAP-7924A. The NRC staff has review ed and accepted this report with the following exception. The evaluation stipulated that the method for determining the shift in RTNDT is not acceptable and that an acceptable method must be included in the FSAR. Section 5.3.2.1 of the STPEGS FSAR presented an alternate method of determining the shift in RTNDT as a function of fluence. This method has been evaluated and found unacceptable It is our position that all of the methods recommended in Revision 1 to Regulatory Guide 1.99, "Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials" be used to evaluate radiation damage to the reactor vessel materials of STPEGS Un its 1 and 2. Revise the FSAR accordingly.

Response The method used by Westinghouse to evaluate radiation damage to the reactor vessel materials of STPEGS Units l and 2 results in greater shifts in RTNDT than those determined using the method recommended by Revision 1 of Regulatory Guide 1.99, as shown in the response to item (4) of Question 121.8. Therefore, the Westinghouse methodology, which we consider acceptable, results in more conservative RT NDT shifts than the Regulatory Guide 1.99 method for the STPEGS reactor vessel materials.

STPEGS UFSAR Q&R 5.3-2 Revision 16 Question 121.14 Confirm that all bolting and other fasteners, used in the RCPB of STPEGS Units l and 2, with nominal diameters exceeding l inch, meet the minimum requirements of 25 mils lateral expansion and 45 ft-lbs in terms of Charpy V-not ch tests conducted at the preload temperature or at the lowest service temperature, whichever is lower (10 CFR Part 50, Appendix G, paragraph IV.A.4).

Response Reactor vessel bolting material properties are given in Tables 5.3-5 and 5.3-6 for Unit 1 and Unit 2, respectively. The requirements applicable to the ferritic materials for bolting (with nominal diameters greater than 1 in.) used in pressure retaining applications of the STPEGS Class 1 re actor coolant pressure boundary equipment have been reviewed with regard to the requirements of lOCFR50 Appendix G.

The current lOCFR50 Appendix G, Paragraph IV.A.4, minimum requirements for materials for bolting with nominal diameters exceeding 1 in. are 25 mils lateral expansion and 45 ft-lbs in terms of Charpy V-notch tests. It should be noted that, for bolting with diameters greater than 1 in. to 4 in. the 10CFR50 Appendix G 45 ft-lb requirement exceeds the applicable ASME Code requirements, which include no ft-lb absorbed energy minimum. With the exceptions discussed herein, the ferritic pressure retaining bolting in the STPEGS Class l reactor coolant pressure boundary equipment is required to meet 25 m ils lateral expansion and 45 ft-lbs in terms of Charpy V-notch tests as the lowest preload or service temper ature. The only bolting materials on which requirements consistent with 1OCFR50 Appendix G and the ASME Code (specifically the 45 ft-lb requirement for bolting with diameters greater than 1 in. to 4 in.) have not been imposed are the reactor coolant pump No. 1 seal housing bolting material and the reactor coolant pump cartridge seal bolting material. This bolting materi al satisfies the ASME code requirement of 25 mils lateral expansion at 68°F. Although not required by the ASME Code, Charpy V-notch tests were performed on this bolting material at 68°F; based on a partial review of the

available data, the 45 ft-lb minimum is satisfied.

STPEGS UFSAR Q&R 5.3-3 Revision 16 Question 251.2N Indicate whether the individuals performing the fracture toughness te sts were qualified by training and experience and whether their competency was demonstrated in accordance with a written procedure. If the above information cannot be provided, state why the information cannot be provided, and identify why the method used for qualifying individuals is equivalent to those of

Paragraph III.B.4 of Appendix G, 10 CFR Part 50.

Response The STPEGS Unit 1 reactor vessel was fabricated to ASME Code Section III requirements. Combustion Engineering, Inc. met the requirements of Section III and Paragraph III.B.4 of Appendix G, 10CFR50 by schooling and training of personnel performing fracture toughness tests. The individuals performing fracture toughness tests have demonstrated competency to perform the tests in accordance with the written procedures of Combustion Engineering, Inc. and trained and qualified personnel supervised all testing.

STPEGS UFSAR Q&R 5.3-4 Revision 16 Question 251.3N To demonstrate compliance with Paragraph III.C

.1 of Appendix G, 10 CFR Part 50, provide CVN impact test data and curves for the base metal and welds in the reactor vessel beltline region.

Response The test data is provided in Tables Q251.3N-1 through Q251.3N-6. Curves are provided in Figures Q251.3N-1 through Q251.3N-6.

Q&R 5.3-5 Revision 16 STPEGS UFSAR TABLE Q251.3N-1 SOUTH TEXAS UNIT 1 REACTOR VESSEL BELTLINE REGION TOUGHNESS PROPERTIES INTERMEDIATE SHELL BASE MATERIAL PLATE R1606-1 PLATE R1606-2 PLATE R1606-3 Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -40 7 3 0 -40 9 4 0 -10 21 12 5 -40 9 4 0 -40 8 3 0 -10 22 13 5 -40 12 6 0 -40 7 3 0 -10 17 9 0

-10 12 7 0 -10 19 12 5 40 47 30 25

-10 17 11 0 -10 14 7 0 40 40 28 20

-10 18 10 0 -10 13 7 0 40 39 24 20 20 36 23 15 40 52 35 25 60 47 34 25 20 28 20 10 40 58 37 30 60 43 30 20 20 19 12 5 40 29 18 10 60 40 27 20 60 58 31 30 50 43 31 20 70 69 54 50 60 46 39 25 50 45 29 20 70 50 36 30 60 60 23 30 50 49 34 25 70 52 39 30 70 69 44 50 60 60 39 40 100 72 52 50 70 64 42 40 60 63 44 40 100 74 55 50 70 62 41 35 60 54 37 30 100 58 46 40 100 89 60 70 100 81 58 60 160 86 67 80 100 84 57 70 100 69 50 50 160 83 60 80 100 73 50 50 100 78 59 60 160 83 62 80 100 110 74 100 160 91 65 100 212 91 72 100 160 108 78 100 160 98 69 100 212 98 68 100 160 111 79 100 160 93 66 100 212 128 82 100

T NDT = -40 F T NDT = -20 F T NDT = -20 F RTNDT = 10 F RTNDT = 0 F RTNDT = 10 F Q&R 5.3-6 Revision 16 STPEGS UFSAR TABLE Q251.3N-2 SOUTH TEXAS UNIT 1 REACTOR VESSEL BELTLINE REGION TOUGHNESS PROPERTIES LOWER SHELL BASE MATERIAL PLATE R1622-1 PLATE R1622-2 PLATE R1622-3 Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -40 24 15 5 -40 7 3 0 -40 11 6 0 -40 15 11 0 -40 8 4 0 -40 10 5 5 -40 19 13 0 -40 10 7 0 -40 11 5 0 0 24 20 10 0 36 24 10 0 31 23 5 0 54 40 30 0 36 25 10 0 27 21 5 0 51 36 25 0 28 22 5 0 53 39 20 30 52 36 25 30 50 36 20 30 51 37 25 30 68 47 30 30 61 43 30 30 54 40 25 30 69 49 35 30 60 44 30 30 62 44 30 100 96 66 80 100 78 53 40 100 87 53 40 100 102 68 70 100 83 55 40 100 107 65 50 100 84 59 60 100 55 38 25 100 84 57 40 160 110 64 100 160 113 79 90 160 120 73 90 160 109 70 100 160 114 74 90 160 123 74 90 160 113 73 100 160 115 79 90 160 116 73 90 212 112 70 100 212 120 76 100 212 128 72 100 212 108 73 100 212 122 78 100 212 127 75 100 212 113 68 100 212 124 79 100 212 126 80 100

T NDT = -30 F T NDT = -30 F T NDT = -30 F RTNDT = 30 F RTNDT = 30 F RTNDT = 30 F 30~F Q&R 5.3-7 Revision 16 STPEGS UFSAR TABLE Q251.3N-3 SOUTH TEXAS UNIT 1 REACTO R VESSEL BELTLINE REGION TOUGHNESS PROPERTIES INTER & LOWER SHELL LONG. INTER TO LOWER SHELL GIRTH WELD SEAMS CODE NO. G1. 70 WELD SE AM CODE NO. E3.13 Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -110 19 11 0 -80 26 17 5 -110 10 6 0 -80 25 16 5 -110 13 8 0 -80 19 12 0 -80 41 26 20 -40 28 22 10 -80 39 25 20 -40 23 17 5 -80 34 20 15 -40 32 26 10 -40 98 65 60 -10 69 54 50 -40 89 58 50 -10 66 53 50 -40 63 44 30 -10 68 54 50 10 122 72 70 60 94 71 80 10 131 77 80 60 83 62 70 10 161 90 100 60 85 64 80 100 151 80 100 100 97 71 90 100 162 90 100 100 98 73 90 100 156 90 100 100 96 74 90 160 164 91 100 160 101 77 100 160 155 84 100 160 99 76 100 160 155 83 100 160 100 79 100 T NDT = -50 F T NDT = -70 F RTNDT = -50 F RTNDT = -70 F Q&R 5.3-8 Revision 16 STPEGS UFSAR TABLE Q251.3N-4 SOUTH TEXAS UNIT 2 REACTOR VESSEL BELTLINE REGION TOUGHNESS PROPERTIES INTERMEDIATE SHELL BASE MATERIAL PLATE R2507-1 PLATE R2507-2 PLATE R2507-3 Temp. Energy Lat. Exp. Shear Temp Energy Lat. Exp. ShearTemp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -40 13 6 0 -40 13 6 0 -40 11 4 0 -40 12 6 0 -40 6 3 0 -40 13 6 0 -40 11 6 0 -40 12 6 0 -40 10 4 0 30 48 34 25 10 44 27 15 20 60 41 25 30 51 36 25 10 37 25 15 20 51 35 20 30 48 34 25 10 51 32 20 20 53 36 20 40 50 35 25 20 50 35 20 60 74 48 35 40 51 38 25 20 68 45 25 60 92 57 60 40 58 42 25 20 58 38 25 60 75 48 35 50 65 46 30 50 81 56 35 100 70 52 30 50 65 47 30 50 67 46 25 100 93 61 60 50 64 46 30 50 73 50 30 100 90 60 60 60 72 49 30 60 88 55 40 160 121 76 100 60 61 46 25 60 75 48 35 160 124 81 100 60 73 50 30 60 88 54 40 160 120 75 100 100 88 58 60 100 85 58 40 212 122 81 100 100 87 60 60 100 93 61 40 212 123 85 100 100 87 61 70 100 115 74 70 212 122 86 100 160 107 72 100 160 128 79 100 160 109 72 100 160 130 80 100 160 100 69 100 160 125 76 90 212 108 71 100 212 127 81 100 212 110 72 100 212 130 80 100 212 110 72 100 215 131 78 100 T NDT = -10 F T NDT = -10 F T NDT = -40 F RTNDT = -10 F RTNDT = -10 F RTNDT = -40 F Q&R 5.3-9 Revision 16 STPEGS UFSAR TABLE Q251.3N-5 SOUTH TEXAS UNIT 2 REACTOR VESSEL BELTLINE REGION TOUGHNESS PROPERTIES LOWER SHELL BASE MATERIAL 5 PLATE R3022-1 PLATE R3022-2 PLATE R3022-3 Temp. Energy Lat. Exp. Shear Temp Energy Lat. Exp. ShearTemp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -40 13 6 0 -40 13 6 0 -40 11 4 0 -40 12 6 0 -40 6 3 0 -40 13 6 0 -40 11 6 0 -40 12 6 0 -40 10 4 0 30 48 34 25 10 44 27 15 20 60 41 25 30 51 36 25 10 37 25 15 20 51 35 20 30 48 34 25 10 51 32 20 20 53 36 20 40 50 35 25 20 50 35 20 60 74 48 35 40 51 38 25 20 68 45 25 60 92 57 60 40 58 42 25 20 58 38 25 60 75 48 35 50 65 46 30 50 81 56 35 100 70 52 30 50 65 47 30 50 67 46 25 100 93 61 60 50 64 46 30 50 73 50 30 100 90 60 60 60 72 49 30 60 88 55 40 160 121 76 100 60 61 46 25 60 75 48 35 160 124 81 100 60 73 50 30 60 88 54 40 160 120 75 100 100 88 58 60 100 85 58 40 212 122 81 100 100 87 60 60 100 93 61 40 212 123 85 100 100 87 61 70 100 115 74 70 212 122 86 100 160 107 72 100 160 128 79 100 160 109 72 100 160 130 80 100 160 100 69 100 160 125 76 90 212 108 71 100 212 127 81 100 212 110 72 100 212 130 80 100 212 110 72 100 215 131 78 100 T NDT = -10 F T NDT = -10 F T NDT = -40 F RTNDT = -10 F RTNDT = -10 F RTNDT = -40 F Q&R 5.3-10 Revision 16 STPEGS UFSAR TABLE Q251.3N-6 SOUTH TEXAS UNIT 2 REACTOR VESSEL BELTLINE REGION TOUGHNESS PROPERTIES 6 INTER & LOWER SHELL LONG. INTER TO LOWER SHELL GIRTH WELD SEAMS CODE NO. G3. 02 WELD SE AM CODE NO. E3.12 Temp. Energy Lat. Exp. Shear Temp. Energy Lat. Exp. Shear

( F) (ft-lb) (mils) (%) ( F) (ft-lb) (mils) (%) -100 14 8 0 -80 22 16 5 -100 28 18 10 -80 25 17 5 -100 23 12 5 -80 22 15 5 -80 39 24 20 -40 48 35 25 -80 32 18 15 -40 30 22 10 -80 40 23 20 -40 43 33 20 -40 85 55 50 -10 52 38 30 -40 93 66 60 -10 58 42 35 -40 98 69 60 -10 63 46 40 -10 88 57 60 30 92 66 80 -10 94 65 60 30 94 66 80 -10 98 66 60 30 92 65 80 60 131 80 80 60 97 69 90 60 146 83 95 60 104 71 90 60 156 85 100 60 88 66 80 100 146 87 100 100 107 74 95 100 145 84 100 100 98 68 95 100 147 86 100 100 92 66 90 160 98 74 100 160 98 75 100 160 106 77 100 T NDT = -70 F T NDT = -70 F RTNDT = -70 F RTNDT = -70 F STPEGS UFSAR Q&R 5.3-11 Revision 16 Figure Q251.03N-1

STPEGS UFSAR Q&R 5.3-12 Revision 16 Figure Q251.03N-2

STPEGS UFSAR Q&R 5.3-13 Revision 16 Figure Q251.03N-3

STPEGS UFSAR Q&R 5.3-14 Revision 16 Figure Q251.03N-4

STPEGS UFSAR Q&R 5.3-15 Revision 16 Figure Q251.03N-5

STPEGS UFSAR Q&R 5.3-16 Revision 16 Figure Q251.03N-6

STPEGS UFSAR Q&R 5.3-17 Revision 16 Question 251.4N To demonstrate compliance with the beltline material test requirements of Paragraph III.C.2 of Appendix G, 10 CFR Part 50:

a. Indicate the post-weld heat treatment used in th e fabrication of the test welds and the vessel beltline welds.

b. Indicate whether the test specimens for the longitudinal seams were removed from excess material and welds in the vessel shell course following completion of the longitudinal weld joints. c. Indicate whether the test specimens for the girth seams were prepared using excess material and welds in the vessel shell course following completion of the girth weld joints.

d. If the test specimens mentioned in b and c above were not removed from excess material and welds in the vessel shell course following completion of the longitudinal/girth weld seams, identify the base materials used to fabricate the welds from which the longitudinal and girth weld test specimens were obtained.

Response Tests specimens for the longitudinal and girth seams were removed from separate weldments per Paragraph NB-2430 of the ASME Code.

The weldment for each vessel was made with the same heat of filler metal and lot of flux and the same welding conditions as used in joining the vessel intermediate and lower shell course weld seam. The following plates and heat treatment were used in fabricating the weldment for each vessel.

Unit 1 Surveillance weld (Pla te R1606-2 to Rl606-3)

Unit 2 Surveillance weld (Pla te R2507-1 to R2507-2) Unit 1 Surveillance weld - 1150°F, 13 hr, 15 min, furnace cooled Unit 1 Girth weld seam - 1150°F, 11 hr, 35 min, furnace cooled Unit 2 Surveillance weld - 1150°F - 7 hr, 22 min, furnace cooled Unit 2 Girth weld seam - 1150°F - 7 hr, 50 min, furnace cooled STPEGS UFSAR Q&R 5.3-18 Revision 16 Question 251.5N To demonstrate compliance with the fracture toughness requirements of Paragraph IV.A.1 of Appendix G, 10 CFR Part 50:

a. Provide the RTNDT for all RCPB welds whic h may be limiting for operation of the reactor vessel. b. Indicate whether there are any RCPB heat-affected zones which require CVN impact testing per Paragraph NB-4335.2 of the 1977 ASME Code. Provide CVN im pact test data for these heat-affected zones which may be limiting for operation of the reactor vessel.

Response a. RTNDT of the welds which may be limiting for operation of the reactor vessel are as follows: Unit 1 Unit 2 Weld Seams RTNDT ( F) RTNDT ( F) Intermediate shell longitudinal

-50 -70 Intermediate shell to lower shell girth -70

-70 Lower shell longitudinal

-50 -70 b. No reactor coolant pressure boundary (RCPB) heat-affected zones require Charpy V-Notch (CVN) impact testing per Paragraph NB-4335.2 of the l977 ASME Code si nce the weld is not made by electroslag, electrogas, or thermit proc ess; and the joint is postweld heat treated.

STPEGS UFSAR Q&R 5.3-19 Revision 16 Question 251.6N To demonstrate that the surveillance capsule program complies with Paragraph II.B, Appendix H, 10 CFR Part 50:

a. For the submerged-arc weld surveillance specimens (Code No. E3.13) provide the weld wire type and heat identification, flux type and lot identification, weld process and heat treatment used for the weld sample fabrication.

b. Provide a sketch which indicates the azimuthal location for each capsule relative to the reactor core. Response a. Information relative to the fabrication of weld surveillance sa mple (Code No. E3.13) is as follows: Weld wire type B4 (Lo Cu and P) Weld wire heat no. 89476 Flux type Linde 124 Flux lot no. 1061 Weld process Automatic submerged arc Heat treatment 1150F - 13 hr, 15 min, - Furnace Cooled

b. See Figure Q251.6N-1.

STPEGS UFSAR Q&R 5.3-20 Revision 16 Figure 251.06-1N STPEGS UFSAR Q&R 5.3-21 Revision 16 Question 251.7N To demonstrate the surveillance cap sule program complies with Para graph II.C.3 of Appendix H:

a. Provide the withdrawal schedule for each capsule.

b. Provide the lead factors for each capsule.

c. Indicate the estimated reactor vessel end-of-life fluence at the 1/4 wall thickness as measured from the inside diameter.

Response a. & b. The STPEGS Unit 1 and 2 Reactor Vessel Material Surveillance Capsule Withdrawal Schedule (see Figure Q251.06N-1) is: Capsule Vessel Lead Withdrawal Iden Location Factor Time U 58.5 4.00 1st Refueling Y 241 3.69 5 EFPY V 61 3.69 9 EFPY X 238.5 4.00 15 EFPY W 121.5 4.00 Standby Z 301.5 4.00 STandby c. The estimated reactor vessel end-of-life fluence at the 1/4 wall thickness is 1.2 x 10 19 n/cm² for Unit 1 and 1.1 x 10 19 n/cm² for Unit 2.

STPEGS UFSAR Q&R 5.3-22 Revision 16 Question Q251.13N (SRP 5.3.1) With regards to fracture toughness requirements of 10CFR50.55a and the May 27, 1983 revisions to Appendices G and H to 10CFR50 (48FR24009; 48FR24011):

a. Identify any ferritic reactor coolant pressure boundary materials that do not comply with these requirements.

b. For any materials that cannot meet these requirements provide alternative fracture toughness data and analyses to demonstrate equivalence to the requirement s to 10CFR Part 50.

Response All reactor coolant pressure boundary materials comply with the requirements of 10CFR50.55a and the May 27, 1983, revisions to Appendices G and H to 10CFR50. (See also the response to NRC Q251.14N).

STPEGS UFSAR Q&R 5.3-23 Revision 16 Question 251.14N (SRP 5.3.1) To demonstrate compliance with Appendix G, 10CFR Part 50, as revised May 27, 1983 (48FR24009), submit fracture mechanics analyses, or pressure-temperature limit curves for the closure flange region of the Unit 1 and Unit 2 reactor pressure vessels.

Response STPEGS Unit 1:

The new 10CFR50 Appendix G rule states that the minimum metal temperature of the closure flange regions should be at least 120

°F higher than the limiting RT NDT for these regions when the pressure exceeds 20 percent of the preservice hydrostatic test pressure (621 psig for Westinghouse plants). For STPEGS Unit 1 the minimum temperature of the closure flange and vessel flange regions is 120°F since the limiting RTNDT is 0°F (see Table 5.3-3). The South Texas Unit 1 heatup curve shown in Figure Q251.14N-1 is not impacted by the new 10CFR50 rule. However, the cu rrent STPEGS Unit 1 cooldown curve is impacted by the new 10CFR50 rule. A revised Unit 1 cooldown curve which meets the Appendix G requirement (see Figure Q251.14N-2) has been provided in the Technical Specifications.

For STPEGS Unit 2, the minimum temperature of the closure flange and vessel flange regions is 110°F since the limiting RTNDT is -10°F (see Table 5.3-4).

Westinghouse reviewed the reasons for the different curves between Unit 1 and Unit 2. The differences resulted from the very conserva tive assumptions utilized in the derivation of the Unit 2 curves. Adoption of the assumptions utilized in the derivation of the Unit 1 curv es demonstrated that the Unit 1 curves are also applicable to Unit 2 for 32 EFPY. These curves have been incorporated in the Technical Specifications.

STPEGS UFSAR Q&R 5.3-24 Revision 16 Figure Q251.14N-1

STPEGS UFSAR Q&R 5.3-25 Revision 16 Figure Q251.14N-2

STPEGS UFSAR Q&R 5.4-1 Revision 16 Section Question 211.13 Provide assurance that adequate alarms are provided to detect leakage from the RHR in the event of a small leak or a significant pipe break. Specifically, provide the following information: (1) Demonstration should be provided that the leak detection system will be sensitive enough to initiate (by alarm) operator action, permit identification of the faulted line and isolation of the line prior to 30 minutes and prior to the leak creating undesirable consequences such as flooding of redundant equipment. (2) It should be shown that the leak detection system can identify the faulted train and that the leak is isolable. (3) Directions given to the operator to isolate the faulted train and to return the intact train to service should be provided. (4) The leak detection system should meet the following requirements: (a) Control room alarm (b) IEEE-279 except single failure requirements Response The Residual Heat Removal System (RHRS) is located inside Containment. All leakages originating from RHRS components will be detected by the Reactor Coolant Pressure Boundary Leakage Detection System, as discussed in UFSAR Section 5.2.5. RHRS leakage will be determined by: (a) Containment Normal Sump Level and Flow (b) Containment air particulate radioactivity (c) Reactor containment fan cooler (RCFC) drain flow (d) Containment humidity (e) RHRS process parameters: RHRS pump discharge flow, RHR Heat Exchanger inlet temperature and pressure, and RHR Heat Exchanger outlet temperature and flow. (1) The reactor coolant pressure boundary (RCPB) leak detection systems are sufficiently sensitive to assure small increases in leakage can be detected prior to affecting safe plant operation. RCPB leakage is collected and monitored to determine flow rate to an accuracy of 1 gal/min, or its equivalent.

STPEGS UFSAR Q&R 5.4-2 Revision 16 Response (Continued) Primary monitoring methods: (a) The containment normal sump is monitored by a differential temperature actuater level device. The rate of le vel change, is calculated a nd alarmed for an increasing rate approaching 1 gal/min is generated. Manual calculations may be obtained from control room level indicators. (b) The Containment air particulate radioactivity monitor is a microprocessor - based system, which is designed to sample a representative isotope, and provide an alarm representative of a 1 gal/min leak to the Containment atmosphere. (c) RCFC drain flow is monitored by a standpipe and level instrument designed to indicate flow. Flow rate is indicated in the control room, and alarmed by the plant computer at a rate of 1 gal/min above the normal drain flow. Secondary monitoring methods: (d) Containment air humidity is measured with a temperature-compensated dew cell. Percent humidity is monitored in the control room. (2) (a) During normal plant operation the RHRS is not in operation and, therefore, is not considered to be a source of leakage to the containment atmosphere. The RHRS is isolated on the suction side by motor operated valves XRH0060A, XRH0060B, XRH0060C a nd XRH0061A, XRH0061B, XRH0061C, and, on the

discharge side, by series sets of check valves (Figures 5.4-6, 6.3-1, 6.3-2, 6.3-3, and 6.3-4). Leakage past the check valves is considered negligible, since check valve leakage testing is performed during power operation. (b) When the RHRS is in operation, the leaking RHRS train can be identified by the operator as follows:

i. Large pipe break - a large break in an RHRS line will be indicated by abnormal readings from pressure an d flow indicators for that train.

ii. Small pipe break - for leakage rates too low to cause significant instrument fluctuations, the operator can identify the faulted train by isolating each train in succession and observing the effect on the RCPB leak detection system. If the leak is in the is olated train, the operator will see a decreasing sump (See Sections 5.2.5.

4.2 and 5.2.5.6.2), indicating that the faulted train has been isolated.

STPEGS UFSAR Q&R 5.4-3 Revision 16 Response (Continued) (c) RHRS single failure analysis and system reliability considerations are presented in Section 5.4.7.2.6. The system is designed in such a manner that three separate flow circuits are available, any one of which satisfies the system design criteria.

This allows individual flow isolatio n for train oriented leak detection. (3) By interpreting process parameters and alarms, the operator will determine the proper course of action. An RHRS loop may then be isolated, in preparation for maintenance, without affecting the ability of the plant to achieve cold shutdown. (4) (a) The occurrence of leaks will be alarmed in the control room (See Section 5.2.5). (b) The RCPB Leakage Detection System was designed to conform with NRC General Design Criterion 30 and Regulation Guide 1.45. (5) Intersystem leakage between the RHR and CCW systems would be detected by increasing level in the CCW surge tank and a high radiation alarm in the affected CCW loop.

STPEGS UFSAR Q&R 5.4-4 Revision 16 Question 211.14 Describe the consequences of loss of compone nt cooling water flow to the RHR and RCS pumps. Justify the time period that the pumps could operate without CCW. What signals, indicators, and alarms are provided to alert the operator to a loss of component cooling to the pumps? Response The RHR pumps operate with cooling water be ing supplied to the seal coolers. Loss of component cooling water would result in higher s eal unit temperature and consequently shorter seal lifetime, but would not cause or require a rapid shutdown of the pumps. Component cooling water temperature is measured at the outlet of the RHR pump seal cooler and monitored by the plant computer. A high temperature indicates a malf unction or low flow in the cooling water circuit to the pump. Loss of component cooling water (CCW) to the RCS pumps was previously addressed in the Section 5.4.1.3.3.

STPEGS UFSAR Q&R 5.4-5 Revision 16 Question 211.16 Per the discussion in Section 6.3.2.2 it is indicated that the flow control valves for the RHR systems fail to the maximum cooling position on failure of the nonsafety grade air system. Discuss the potential for this failure and the consequences of thermal shock and technical specification (cooldown limit) violation resulting from this failure.

Response The potential for failure of the nonsafety grade air system is, of course, dependent on the air system design. However, it is considered highly improbable that the air system failure would occur precisely during the few hours per year that it could cause the cooldown rate to exceed the Technical Specification limit of 100°F/hr.

The cooldown rate depends on several factors, including the RCS temperature, the RHR flow rate, the component cooling water and essential cooling water (ECW) temperatures, and the auxiliary loads on the component cooling water (CCW) system. Under expe cted conditions, the cooldown rate would not exceed the Technical Specification lim it of 100°F/hr, even if the butterfly valves were failed to the maximum cooling position from the moment RHR was initiated. Under the most conservative and severe set of assumptions, with all three RHR trains running and no operator action, the fa ilure would have to occur pr ecisely during the short period of time that the RCS temperature was between 350°F (RHR cut-in) and 250°F, in order to cause a cooldown rate in excess of the Technical Specification limit. Below an RCS temperature of 250°F, even under this severe set of assumptions, the cooldown rate would not exceed the Technical Specification limit.

Plant cooldown can be controlled, even if instrument air is not available. The methods of doing this are listed below in order of preferability:

1. The simplest method of controlled cooldown w ithout instrument air is to put only one RHR train in operation for the first portion of cooldown. Even with the butterfly valve controlling flow through RHR heat exchanger (HX) fully open and the bypass butterfly valve fully closed, the cooldown rate will not even reach 50°F/hr over the first, most critical, hour. If desired, the other trains can be cut in as required to achieve a more efficient cooldown rate, but still remain in compliance with the Technical Specification limit. 2. Another means is by intermittent operation of the RHR pumps for the first part of cooldown, using administrative control to ensu re that the cooldown rate does not exceed the Technical Specification limit.

3. A third method is to maintain continuous operation of the RHR pumps while periodically closing valves XRH0031A, XRH0031B, and XRH0031C to prevent the cooled RHR flow from returning to the RCS , thus carrying out the first pa rt of cooldown in a stepwise manner. (With this method, the RHR miniflow lines must be opened.)

STPEGS UFSAR Q&R 5.4-6 Revision 16 Response (Continued) In summary, the event causing an excessive cool down rate would have to involve both the air failure occurring precisely during a specific peri od of just a few hours, and the existence of unusually low ECW and CCW temperatures. Furthermore, there are simple actions which can be taken to control the cooldown rate should this highly unlikely event occur.

STPEGS UFSAR Q&R 5.4-7 Revision 16 Question 282.1N Provide a summary of operative in structions to be used for the steam generator secondary water chemistry control and monitoring program, addressing the following:

1. Sampling frequency for the critical chemical and other parameters and of control points or limits for these parameters for each mode of operation: normal operation, hot startup, cold startup, hot shut down, cold wet layup;

2. Procedures used to measure the values of the critical parameters;

3. Location of process sampling points;

4. Instructions for the recording and management of data;

5. The program element defining corrective actions for off-control point chemistry conditions detailing time allowed at off-chemistry conditions.

Branch Technical Position MTEB 5-3 describes an acceptable means for monitoring secondary side water chemistry in PWR steam generators, includi ng corrective actions for off-control point chemistry conditions. However, the staff is amenable to alternatives, particularly to Branch Tec hnical Position B.3.b(9) of MTEB 5-3 (96-hour time limit to repair or plug confirmed condenser tube leaks).

6. The program element identify (a) the authority responsible for the interpretation of the data and (b) the sequence and timing of administrative events required to initiate

corrective action.

Response The Secondary Water Chemistry Program for Sout h Texas Project Electr ic Generating Station provides for effective, long-term, reliable operation of the steam generators and secondary side components. System corrosion will be controlled by feeding all-volatile chemicals to the secondary systems for minimizing dissolved oxygen and maintaining an alkaline pH in the feedwater to each steam generator. All-volatile treatment will also be used for wet layup of secondary systems during periods of unit shutdown.

Impurity ingress into the secondary systems will be controlled by the condensate polishing system, the steam generator blowdown system, and the deaerator.

A sampling and analysis program will be maintained for monitoring the blowdown from each steam generator. Concentration levels for each parameter have been established with specific operational action required in the event that a concentration level is exceeded.

STPEGS UFSAR Q&R 5.4-8 Revision 16 Response (Continued)

1. The sampling frequency and action level requirem ents will be included in plant procedures. These frequencies and action level requirements will be developed in accordance with industry experience and EPRI TR-102134 "PWR Secondary Wate r Chemistry Guidelines".

2. Laboratory analyses will be performed usi ng procedures based upon ASTM or Standard Methods for Analysis of Water and Wastewater or by methods demonstrated to be equivalent or better than those listed above.

3. The location of the secondary sampling points are shown in Figure Q282.01N-1.

4. 4. Analytical results are recorded on the appropriate Worksheet, Log Sheet, Data Sheet, or other approved form. Key plant chemistry data is transferred to daily chemistry reports as well as plotted graphically to show abnormal trends of parameters.

5. Plant Chemistry Specifications define corrective action for off-control chemistry conditions and detail time allowed at off-chemistry conditions. These specifica tions are based upon industry experience and EPRI TR-102134 "PWR Secondary Wate r Chemistry Guidelines". 6a. Plant Chemistry Specifications identify the Chemistry Manager as the authority responsible for interpreting chemistry data. 6b. When an analysis indicates that a chemical parameter is not within specified limits, appropriate actions are taken as soon as possible. If the sample was taken to satisfy a technical specification surveillance requirement, when the applicable surveillance procedure is consulted to determine the co rrective action required. If the sample was not taken to satisfy a technical specification surveillance requirement, then Plant Chemistry Specifications are consulted to determine the corrective action required.

STPEGS UFSAR Q&R 5.4-9 Revision 16 Figure 282.01N-1

STPEGS UFSAR Q&R 5.4-10 Revision 16 Question 410.8N In considering the event that the rupture disks of the pressurizer relief tank are blown out and become missiles, describe the associated hazards to the safety-related equipment and whether missile protection features are provided.

Response The rupture disks of the pressuri zer relief tank are designed to burst , not blow out as a panel. The hazard associated with this failure mode is lessened. Potential missiles created by these rupture disks would be stopped by st ructural steel, the pressurizer surge line or by two levels of grating above the pre ssurizer relief tank.

STPEGS UFSAR Q&R 5.4-11 Revision 16 Question 440.28N Provide the basis for sizing the RHR relief valves. Also justify using 600 psig as the valve set pressure, in view of the fact that the RHR system design pressu re is also 600 psig. Other recent Westinghouse plants, which also have RHR system s designed to 600 psig, utilize 450 psig as the valve setpoint. If the RHR relief valve is utilized for LTOPS purpose, discuss the suitability of the valve capacity and setpoint for this purpose.

Response As reported in Section 5.4.7.1, each Residual Heat Removal (RHR) subsystem is equipped with a pressure relief valve designed to relieve the combined flow of all the charging pumps at the relief valve set pressure of 600 psig. The potential and capacity for charging pumps to overpressurize the Residual Heat Removal System (RHRS), therefore, represent the sizing basis for the valves. The reason for the variation in relief valve set pressures between the STPEGS and other Westinghouse designs is that the STPEGS relief valve is in the RH R pump discharge rather than the suction line. In effect, to protect against system overpressurization via a pump suction side relief valve, the developed head of the subject pump must be considered in the establishment of the relief valve set pressure. C onsequently, the set pressure variance to effect the same system protection is appropriate.

The STPEGS Cold Overpressure Mitigation System (COMS) does not take credit for the availability or relief capacity of the RHR relief valves

STPEGS UFSAR Q&R 5.4-12 Revision 16 Question 440.29N Figure 5.4-6 "RHRS Piping Diagram" indicates ESF signals to the RHR inlet valves and does not show the open permissive and auto closure interlocks. Are these interlocks combined with the ESF controls? If so, can the RHR inlet valves be ina dvertently opened when the RCS is at high pressure or closed when the plant is on RHR cooldown in the event of an ESF actuation? Figure 5.4.6 should show the interlocks and power dive rsity as described in the text.

Response For consistency in representation of signals to equipment, the Engineered Safety Feature (ESF) symbol has been used to represent protection-grade (Class lE) signals to equipment. On Figure 5.4-6, the ESF symbol for the Residual Heat Removal (RHR) inlet isolation valv es represents the open permissiveinterlock signal to the valves from the Solid-State Protection System (SSPS), which are Class lE signals. These signals are discussed in Sections 5.4.7 and 7.6.2; the logic diagram for these valves is shown in Figure 7.6-2. As shown on this figure, no other si gnals are sent to these valves.

The power diversity for these valves is discussed in the above referenced sections, and is also shown on Figures 7.6-2 and 5.4-6.

STPEGS UFSAR Q&R 5.4-13 Revision 16 Question 440.30N With regard to the information in Appendix 5.4.

A "Cold Shutdown Capability" identify the most limiting single failure with regard to cooldown capability and verify that the statement of Table 5.4.A-1 that the auxiliary feedwater storage tank (AFST) "capacity of 500,000 gallons is adequate to support 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at hot standby conditions followe d by 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> cooldown to RHR cut in condition with a margin for contingencies" considers this failure.

Response The answer is included into UFSAR Table 5.4A-1 Section VII.

STPEGS UFSAR Q&R 5.4-14 Revision 16 Question 440.32N For each mode of operation, state whether the RHR inlet valve motor power supply breakers are locked open. If the breakers are locked open during modes 1, 2, and 3, state how the plant is brought to cold shutdown from the control room.

Response The residual heat removal (RHR) inlet isolation valve motor power supply breakers (one valve in each inlet line) are power locked out with the valves in the closed position during plant modes 1, 2, and 3. These power lockouts preclude simultaneous opening of the two RHR system inlet isolation valves which can be postulated to occur due to control circuitry fire damage; i.e., multiple hot shorts.

Operator action outside of the control room is required to cl ose the power supply breakers for the inlet isolation valves prior to establishing RHR system operation. This situation is not in conformance with the guidelines of Branch Technical Position RSB 5-1 because the consequences of simultaneous valve opening has greater safety significance than the ability to be able to perform a shutdown (including opening of the RHR inlet isolation valves) from the control room.

STPEGS UFSAR Q&R 5.4-15 Revision 16 Question 440.33N

a. Table 5.4.A-1 "Compliance Comparison with BTP RSB 5-1" states that during cold shutdown boron sampling is not required. Will boronom eters be used for boron concentration measurements, and if so, are they safety grad e? We consider periodic boron concentration measurements necessary, particularly if the plant is in natural circulation.

b. Table 5.4.A-1, Item V, indicates that "test data and analysis for a plant similar in design to STPEGS will verify adequate mixing and cooldown under natural circulation conditions."

State which plant test would be utilized, and justify why the plant is similar to the STPEGS design, considering possible differe nces in core and RCS design, T avg, upper head volume and temperature, and other pertinent parameters.

Response a) STPEGS can periodically measure boron con centration by use of the Post- Accident Sampling System (PASS) (Section 9.3.2). The PASS panel is provided back-up power from the highly reliable TSC Diesel. This shouldbe available in the event of a Loss of Offsite Power (LOOP). b) STPEGS and Diablo Canyon Unit 1 have been comp ared in detail to as certain any differences between the two plants that could potentially affect natural circulation flow and attendant boron mixing. Because of the similarity between the plants, it was concluded that the natural circulation capabilities would be similar. Th erefore, the results of prototypical natural circulation cooldown tests conducted at Diablo Canyon will be representative of the capability at STPEGS. The general configurat ion of the piping and components in each reactor coolant loop is the same in both STPEGS and Diablo Canyon. Th e elevation head represented by these components and the system piping is similar in both plants. To compare the natural circulat ion capabilities of STPEGS and Diablo Canyon, the hydraulic resistance coefficients were compared. The coeffi cients were generated on a per loop basis. The hydraulic resistance coefficients applicable to normal flow conditions are as follows:

Diablo Canyon Unit 1 STPEGS Reactor Core & Internals 128.4 x 10-10 149.7 x 10-10 ft/(Loop gal/min) 2 Reactor Nozzles 36.7 x 10-10 27.3 x 10-10 ft/(Loop gal/min) 2 RCS Piping RV Outlet to SG Inlet 4.0 x 10-10 ft/(Loop gal/min) 2 STPEGS UFSAR Q&R 5.4-16 Revision 16 Response (Continued) Diablo Canyon Unit 1 STPEGS SG Outlet to RC Pump Inlet 10.0 x 10-10 ft/(Loop gal/min) 2 RC Pump Discharge 4.0 x 10-10 ft/(Loop gal/min) 2 To RV Inlet Total RC Loop 24.0 x 10-10 18.0 x 10-10 ft/(Loop gal/min) 2 Steam Generator 114.5 x 10-10 132.1 x 10-10 ft/(Loop gal/min) 2 Total 303.6 x 10-10 327.1 x 10-10 ft/(Loop gal/min) 2 Flow Ratio Per Loop STPEGS = ~ 303.6 - 1/2 = 0.963 Diablo Canyon 327.1 The general arrangement of the reactor core and internals is the same in Diablo Canyon and STPEGS.

The coefficients indicated represent the resistance seen by the flow in one loop. The reactor vessel outlet nozzles co nfiguration for both plants is the same. The radius of curvature between the vessel inlet nozzle and downcomer section of the vessel on the two plants is different. Based on 1/7 scale model testing performed by Wes tinghouse and other literat ure, the radius on the vessel nozzle/vessel downcomer junctu re influences the hydraulic resistance of the flow turning from the nozzle to the downcomer. The Diablo Canyon vesse l inlet nozzle radius is significantly smaller than that of STPEGS, as reflected by the higher coefficient for Diablo Canyon. Steam generator (SG) units were also compared to ascertain any variation that could affect natural circulation capability by changing th e effective elevation of the heat sink or the hydraulic resistance seen by the primary coolant. It was concluded that ther e are no differences in the design of the SGs in the two plants that would adversely affect the natural circulation characteristics.

It is expected that the relative e ffect of the coefficients would be the same under natural circulation conditions such that the natural ci rculation loop flowrate for STPEGS would be within five percent of that for Diablo Canyon.

For typical 4-loop plants there ar e two potential flow paths by whic h flow crosses the upper head region boundary in a reactor. Thes e paths are the flow nozzles into the upper head and the guide tubes. The flow nozzles provide a flow path between the downcomer region and the upper head region. The temperature of the fl ow which enters the head via this path corresponds to the STPEGS UFSAR Q&R 5.4-17 Revision 16 Response (Continued) cold leg value (i.e., Tcold). Fluid may also be exchanged between the upperplenum region (i.e., the portion of the reactor between the upper core plate and the upper support plate) and the upper head region via the guide tubes. Guide tubes are dispersed in the upper plenum region from the center to the periphery. Because of the nonuniform pressure distribution at the upper co re plate elevation and the flow distribution in the upper plenum region, the pressure in the guide tube varies from location to location. These guide tube pressure variations create the potential fo r flow to either enter or exit the upper head region via the guide tubes.

To ascertain any difference between the upper head cooling capabilities between Diablo Canyon and STPEGS, a comparison of the hydraulic resistance of the upper head regions was made. These flow paths were considered in parallel to obtain the following results.

Diablo Canyon Unit 1 STPEGS Flow area (ft

2) 0.77 0.788 Loss coefficient 1.51 1.50 Overall hydraulic resistance (ft

-4) 2.57 2.413 Relative head region flow rate 1.00 1.03 (Based on hydraulic resistance) As indicated above, the effective hydraulic resistance to flow in STPEGS is slightly less than Diablo Canyon. Assuming that the same pressure differentia l existed in both plants the STPEGS head flow rate would be 103 percent of the Diablo Canyon flow.

It can, therefore, be concluded th at the results of the natural circulation cooldown tests performed at Diablo Canyon will be representative of the natural circulation and boron mixing capability of STPEGS. The results of these tests will be reviewed for applicability.

STPEGS UFSAR Q&R 5.4-18 Revision 16 Question 440.35N Recent plant experience has identified a potential problem regarding the loss of shutdown cooling during certain reactor coolant system maintenance operations. On a number of occasions when the reactor coolant system has been partially drained, improper RCS level control, a partial loss of reactor coolant inventory, or operating the RHR system at an inade quate NPSH has resulted in air binding of the RHR pumps with a subsequent lo ss of shutdown cooling. Regarding this potential problem, provide the follow ing additional information. a. Discuss the design or procedural provisions incorporated to maintain adequate reactor coolant system inventory, level contro l, and NPSH during all operations in which RHR cooling is required. b. Discuss the provisions incorporated to ensure the rapid detection of air binding of the RHR pumps so that they are not damaged. What provi sions are there to vent or otherwise remove the trapped air in the pumps and rapidly put the RHR system back into service prior to excessive core heatup? c. Discuss the provisions incorporated to provide alternate met hods of shutdown cooling in the event of loss of RHR cooling during shutdown maintenance. These provisions should consider maintenance periods during which more than one cooling system may be unavailable, such as loss of steam generators when the reactor coolant system has been partially drained for steam generator inspection or maintenance.

Response STPEGS responded to the industry issue of shutdown cooling assurance in the response to Generic Letter 88-017, "Loss of Decay Heat Removal".Correspondence ST-HL-AE-3097 dated August 3, 1989, ST-HL-AE-3398 dated March 9, 1990 and ST-H L-AE-3741 dated April 15, 1991 detail the design and administrative provisions to minimize the potential for loss of shutdown cooling.

STPEGS UFSAR Q&R 5.4-19 Revision 16 Question 440.36N

a. Describe the compliance of the reactor vessel head vent system (RVHVS) with NUREG-0737 Item II.B.1 "RCS Vents".Provide an item by item comparison of the NUREG-0737 requirements with the STPEGS RVHVS design.

b. The FSAR indicates that the RVHVS is also used for primary coolant letdown. State during what operational modes the RVHVS would be us ed for letdown, whether it would be used together with or as an alternate to CVCS le tdown, and whether there could be interference between the letdown function and the system's primary function of head venting.

c. Revise Figure 5.1-1 to depict the RVHVS as described in the Amendment 38 submittal, including the existence of redundant remote operated isola tion and throttling valves. Also clarify whether the system discharges to the PRT, as stated in Section 5.4.15, or to the reactor coolant drain tank, as shown in Figure 5.1-1.

Response A. 1. A description of the design, lo cation, size, and power supply fo r the Head Vent System is provided in Section 5.4.15. As indicated in Section4 5.4.15.3, a break in a vent pipe would be similar to the hot leg break case in WCAP

-9600 and the results presented therein are applicable. 2. Westinghouse Emergency Response Guideline FRI-3, "Response to Voids in the Reactor Vessel" provides guidance on the operation of the Head Vent System. STPEGS plant specific procedures relating to the operation of the Head Vent System will be developed by Houston Lighting and Power. Also see Appendix 7A, Item II.B.1 for further information.

B. As described in Section 5.4.A.1, the safe s hutdown design basis for the STPEGS is hot standby. The cold shutdown capability of the pl ant has however been evaluated. In this scenario the head vent line may be used as a letdown path should the primary Chemical and Volume Control System (CVCS) letdown path be unavailable. C. The Heat Vent System discharges to the pr essurizer relief tank (PRT). Figure 5.1-1 will be corrected.

STPEGS UFSAR Q&R 5.4-20 Revision 16 Question 440.37N State what provisions have been made for pressurizer and RCS loop venting.

Response Noncondensable gases would be expected to collect in the reactor vessel head or the pressurizer. The reactor vessel may be vented via the Reactor Vessel Head Vent System while the pressurizer may be vented via the safety-related power-operated relief valves (PORVs).

STPEGS UFSAR Q&R 5.4-21 Revision 16 Question 440.73N What relief provisions are provided to accommodate thermal expansion of the water trapped between the two RHR inlet valves during heatup?

Response Two isolation valves in series are provided in each Residual Heat Removal (RHR) inlet leading from the reactor coolant loop hot legs to the suction of the RHR pumps. The isolation valve nearest to the hot leg is located more than ten feet away from the hot leg connec tion and below the elevation of the hot leg loop piping. The Reactor Coolant System (RCS) side of the trapped volume in question is therefore not close coupled to the RCS loop piping a nd is cold trapped, i.e., arranged to preclude the formation of convection currents of hot reactor coolant which could heat the trapped volume. Given this physical layout, the mechanism by which thermal heat up and expansion of the trapped volume could occur during normal plant operation is limited to the heat up of this volume as the Containment ambient temperatur e increases during plant heatup. The maximum pressure which would occur in this line segment was calculated based on the following conservative assumptions: The line is isolated as the Containment ambient temperature, and trapped water volume temperature, increase from 65°F to 120°F. Zero leakage is assumed to occur both past the seats and through the stems of the isolation valves. The results of the analysis demonstrate that the p eak pressure which occurs in the trapped volume is less than the design pressure of the 12-in. schedule 160 piping and the isolation valves at the applicable temperature. It is th erefore concluded that overpressure protection is not required for the RHR inlet line to accommodate thermal expansion of the trapped water volume during plant heatup.

STPEGS UFSAR Q&R 5.4-22 Revision 16 Question 440.74N What is the capacity of the RHR discharge line relief valves downstream of the RHR HX.

Response This relief valve is for thermal relie f only and has a low flow capacity (20 gal/min).

STPEGS UFSAR Q&R 5.4-23 Revision 16 Question 440.75N Discuss the adequacy of the RHR pump bypass valve manual on-off controls. Other recent Westinghouse plants have automatic recirculation control valve modulation based on total pump flow. Discuss the required operator actions.

Response Since the Residual Heat Removal (RHR) pump is not used as a safety injection pump on STPEGS an automatic miniflow arrangement has not been provided. The RHR pumps are manually started by the operator when needed for Reactor Coolant System (RCS) cooling. For pump protection the pump will trip on low flow and operator action is required to open the miniflow valve on a low flow alarm.

STPEGS UFSAR Q&R 5.4-24 Revision 16 Question 440.76N Will alarms be provided to indicate excessive RHR pump seal temperatures; e.g., component cooling water outlet high temperature alarms?

Response A temperature element is located downstream of the residual heat removal (RHR) pumps on each component cooling water (CCW) line (Figur es 9.2.2-1 through 9.2.2-3). This output signal is transmitted to the plant computer. If the preset temperature setpoint is exceeded it will be alarmed as a computer alarm. The operator then checks the computer to determine what condition has alarmed and takes correc tive action.