ML21209A178

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1 to Updated Final Safety Analysis Report, Chapter 10, Steam and Power Conversion System
ML21209A178
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Site: Summer South Carolina Electric & Gas Company icon.png
Issue date: 04/30/2021
From:
Dominion Energy South Carolina
To:
Office of Nuclear Reactor Regulation
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TABLE OF CONTENTS Section Title Page 10.0 STEAM AND POWER CONVERSION SYSTEM 10.1-1 10.1

SUMMARY

DESCRIPTION 10.1-1 10.2 TURBINE GENERATOR 10.2-1 10.2.1 DESIGN BASES 10.2-1 10.

2.2 DESCRIPTION

10.2-1 10.2.2.1 General 10.2-1 10.2.2.2 Turbine Generator Control 10.2-2 10.2.2.3 Turbine Generator Overspeed Protection 10.2-3 10.2.2.4 Generator Gas System 10.2-4 10.2.3 TURBINE MISSILES 10.2-5 10.2.4 EVALUATION 10.2-7 10.

2.5 REFERENCES

10.2-7 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1 10.3.1 DESIGN BASES 10.3-1 10.3.1.1 Codes and Standards 10.3-1 10.3.1.2 Heat Balance 10.3-2 10.3.1.3 Design Conditions 10.3-2 10.3.1.4 Environmental Conditions 10.3-2 10.

3.2 DESCRIPTION

10.3-3 10.3.2.1 General 10.3-3 10.3.2.2 Main Steam System Piping 10.3-4 10.3.2.3 Main Steam Isolation Valves 10.3-5 10.3.2.4 Main Steam Safety Valves 10.3-6 10.3.3 EVALUATION 10.3-6 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-6 10.3.5 WATER CHEMISTRY 10.3-8 10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-9 10.3.6.1 Fracture Toughness 10.3-9 10.3.6.2 Materials Selection and Fabrication 10.3-10 10.

3.7 REFERENCES

10.3-11 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4-1 10.4.1 MAIN CONDENSER 10.4-1 10.4.1.1 Design Bases 10.4-1 10.4.1.2 System Description 10.4-2 10.4.1.3 Safety Evaluation 10.4-3 10.4.1.4 Tests and Inspections 10.4-3 10.4.1.5 Instrumentation 10.4-4 10.4.2 CONDENSER AIR REMOVAL SYSTEM 10.4-4 10.4.2.1 Design Bases 10.4-4 10.4.2.2 System Description 10.4-4 10.4.2.3 Safety Evaluation 10.4-5 10.4.2.4 Tests and Inspections 10.4-5 10.4.2.5 Instrumentation 10.4-5 10-i Reset April 2021

TABLE OF CONTENTS (Continued)

Section Title Page 10.4.3 TURBINE GLAND SEALING SYSTEM 10.4-6 10.4.3.1 Design Bases 10.4-6 10.4.3.2 System Description 10.4-6 10.4.3.3 Safety Evaluation 10.4-7 10.4.3.4 Tests and Inspections 10.4-7 10.4.3.5 Instrumentation 10.4-7 10.4.4 TURBINE BYPASS SYSTEM 10.4-7 10.4.4.1 Design Bases 10.4-7 10.4.4.2 System Description 10.4-8 10.4.4.3 Safety Evaluation 10.4-10 10.4.4.4 Tests and Inspections 10.4-10 10.4.4.5 Instrumentation Applications 10.4-11 10.4.5 CIRCULATING WATER SYSTEM 10.4-11 10.4.5.1 Design Basis 10.4-11 10.4.5.2 System Description 10.4-12 10.4.5.3 Safety Evaluation 10.4-12 10.4.5.4 Tests and Inspections 10.4-13 10.4.5.5 Instrumentation 10.4-13 10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-14 10.4.6.1 Design Bases 10.4-14 10.4.6.2 System Description 10.4-14 10.4.6.3 Safety Evaluation 10.4-16 10.4.6.4 Tests and Inspections 10.4-16 10.4.6.5 Instrumentation Application 10.4-17 10.4.7 CONDENSATE AND FEEDWATER SYSTEMS 10.4-17 10.4.7.1 Condensate System 10.4-17 10.4.7.2 Feedwater System 10.4-20 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-25 10.4.8.1 Design Bases 10.4-25 10.4.8.2 System Description 10.4-27 10.4.8.3 Safety Evaluation 10.4-32 10.4.8.4 Tests and Inspections 10.4-33 10.4.8.5 Instrumentation Applications 10.4-33 10.4.9 EMERGENCY FEEDWATER SYSTEM 10.4-34 10.4.9.1 Design Bases 10.4-34 10.4.9.2 System Description 10.4-36 10.4.9.3 Safety Evaluation 10.4-38 10.4.9.4 Inspection and Testing Requirements 10.4-41 10.4.9.5 Instrumentation Requirements 10.4-41 10.4.10 TURBINE BUILDING CLOSED CYCLE COOLING WATER SYSTEM 10.4-44 10.4.10.1 Design Bases 10.4-44 10.4.10.2 System Description 10.4-45 10.4.10.3 Safety Evaluation 10.4-46 10.4.10.4 Tests and Inspection 10.4-46 10.4.10.5 Instrumentation 10.4-46 10.4.11 REFERENCES 10.4-47 10-ii Reset April 2021

LIST OF TABLES Table Title Page No.

RN 10.1-1 Deleted (RN 01-020) 10.1-4 01-020 10.2-0 Turbine Shutdown Signals 10.2-8 10.2-1 Turbine Generator Overspeed Protection System 10.2-9 10.2-2 Turbine Overspeed Protection System 10.2-10 Failure Analysis 10.3-1 Environmental Conditions Considered in Main Steam Supply System 10.3-12 Design 10.3-1a Main Steam Safety Valve Setpoints 10.3-13 10.3-2 Steam Generator For Blowdown Rate 10.3-14 10.4-1 Condenser Air Removal 10.4-48 10.4-2 Turbine Bypass Valve Setpoints 10.4-50 10.4-3 Circulating Water System Design Parameters 10.4-52 10.4-3a Water Level Versus Time for a Postulated Circulating Water System 10.4-54 Expansion Joint Failure 10.4-4 Condensate System Equipment Parameters 10.4-55 02-01 10.4-5 Feedwater System Equipment Parameters 10.4-57 10.4-6 Feedwater System Failure Analysis 10.4-59 10.4-7 Steam Generator Blowdown System 10.4-60 Component Design Parameters 10.4-8 Emergency Feedwater System Failure Analysis 10.4-63 10.4-9 Turbine Building Closed Cycle Cooling Water System 10.4-65 Design Parameters 10-iii Reset April 2021

LIST OF FIGURES Figure No. Title 10.1-1 Steam and Power Conversion Systems Composite (2 Sheets) 10.1-2 Calculated Turbine Power Heat Balance 10.1-3 Maximum Calculated Turbine Power Heat Balance 10.2-1 Deleted (RN 01-043) RN 01-043 10.2-2 Turbine Control Diagram Stop Valves 10.2-3 Deleted 10.2-3a Turbine Control Diagram Control & Combined Intermediate Valves 10.2-3b Turbine Control Diagram Control & Combined Intermediate Valves 10.2-4 Turbine Control Diagram Trip 10.2-5 Generator Gas System 10.3-1 Main Steam (Nuclear) 10.3-2 Main Steam (Non-Nuclear) 10.3-3 Main and Reheat Steam (Non-Nuclear) 10.3-4 Main Steam Dump System 10.4-1 Condenser Air Removal 10.4-2 Deleted 10.4-2a Deleted 10.4-2b Deleted 10.4-3 Main Steam Dump System Loop Diagram 10.4-4 Main Steam Dump System Loop Diagram (3 Sheets) 10.4-4a Functional Diagram Main Steam System (Nuclear) 10.4-4b Functional Diagram Main Steam System 10.4-5 Circulating Water Cooling 10.4-6 Deleted 10.4-7 Deleted by Amendment 96-03 10.4-7a Condensate Polishing 10.4-8 Condensate 10.4-8a Deleted (RN 06-041) RN 06-041 10.4-9 Condensate - Auxiliary Condensers and Blowdown Heat Exchangers 10.4-10 Feedwater (Non-Nuclear) 10-iv Reset April 2021

LIST OF FIGURES (Continued)

Figure No. Title 10.4-11 Feedwater (Non-Nuclear) 10.4-12 Feedwater (Nuclear) 10.4-13 Steam Generator Blowdown 10.4-14 Nuclear Blowdown Processing System Holdup Tank and Demineralizers 10.4-15 Nuclear Blowdown Processing System Spent Resin Storage Tank 10.4-16 Emergency Feedwater (Nuclear) 10.4-17 Liquid Effluents from Nuclear Plant to Fairfield Penstock 10-v Reset April 2021

LIST OF EFFECTIVE PAGES (LEP)

The following list delineates pages to Chapter 10 of the Virgil C. Summer Nuclear Station Final Safety Analysis Report which are current through April 2021. The latest changes to pages and figures are indicated below by Revision Number (RN) in the Amendment column along with the Revision Number and date for each page and figure included in the Final Safety Analysis Report.

Page/Fig. No. Amend. No. Date Page/Fig. No. Amend. No. Date Page 10-i Reset April 2021 Fig. 10.2-4 RN11-015 November 2011 10-ii Reset April 2021 10.2-5 RN12-010 December 2013 RN05-043 March 2014 10-iii Reset April 2021 Page 10.3-1 02-01 May 2002 10-iv Reset April 2021 10.3-2 02-01 May 2002 10-v Reset April 2021 10.3-3 02-01 May 2002 10-vi Reset April 2021 10.3-4 02-01 May 2002 10-vii Reset April 2021 10.3-5 02-01 May 2002 10-viii Reset April 2021 10.3-6 02-01 May 2002 Page 10.1-1 99-01 June 1999 10.3-7 RN03-034 October 2003 10.1-2 RN02-022 October 2002 10.3-8 02-01 May 2002 10.1-3 00-01 December 2000 10.3-9 02-01 May 2002 10.1-4 02-01 May 2002 10.3-10 02-01 May 2002 Fig. 10.1-1 (Sh 1) 02-01 May 2002 10.3-11 02-01 May 2002 10.1-1 (Sh 2) 02-01 May 2002 10.3-12 RN03-008 June 2003 10.1-2 02-01 May 2002 10.3-13 02-01 May 2002 10.1-3 02-01 May 2002 10.3-14 RN04-018 August 2004 Page 10.2-1 RN05-038 June 2009 10.3-15 RN04-018 August 2004 10.2-2 RN11-015 November 2011 10.3-16 02-01 May 2002 10.2-3 RN11-015 November 2011 Fig. 10.3-1 RN05-007 October 2006 10.2-4 RN11-015 November 2011 RN00-085 November 2011 10.2-5 RN11-015 November 2011 RN15-001 August 2017 10.2-6 RN11-015 November 2011 10.3-2 RN11-015 November 2011 RN12-035 April 2018 10.2-7 RN11-015 November 2011 RN18-001 April 2018 10.2-8 RN11-015 November 2011 10.3-3 RN03-020 June 2003 10.2-9 RN11-015 November 2011 10.3-4 RN03-028 July 2003 10.2-10 RN11-015 November 2011 Page 10.4-1 RN09-012 February 2010 10.2-11 RN11-015 November 2011 10.4-2 RN06-041 November 2011 10.2-12 RN11-015 November 2011 10.4-3 RN02-022 October 2002 Fig. 10.2-1 02-01 Deleted 10.4-4 02-01 May 2002 10.2-2 RN12-013 May 2015 10.4-5 RN02-057 April 2004 10.2-3 96-03 Deleted 10.4-6 RN02-022 October 2002 10.2-3a RN12-013 May 2015 10.4-7 RN02-022 October 2002 10.2-3b RN12-013 May 2015 10.4-8 02-01 May 2002 10-vi Reset April 2021

LIST OF EFFECTIVE PAGES (LEP)

Page/Fig. No. Amend. No. Date Page/Fig. No. Amend. No. Date 10.4-9 00-01 December 2000 10.4-40 02-01 May 2002 RN12-030 November 2017 10.4-10 RN04-012 July 2004 10.4-41 RN11-022 August 2012 Page 10.4-11 RN08-001 May 2009 10.4-42 00-01 December 2000 10.4-12 02-01 May 2002 RN12-030 November 2017 10.4-13 02-01 May 2002 10.4-43 00-01 December 2000 10.4-14 00-01 December 2000 10.4-44 RN10-018 November 2011 10.4-15 RN06-041 November 2011 10.4-45 RN10-018 November 2011 10.4-16 00-01 December 2000 10.4-46 00-01 December 2000 10.4-17 02-01 May 2002 Page 10.4-47 02-01 May 2002 10.4-18 RN06-041 November 2011 10.4-48 02-01 May 2002 10.4-19 RN06-041 November 2011 10.4-49 02-01 May 2002 10.4-20 02-01 May 2002 10.4-50 RN04-003 February 2004 10.4-21 02-01 May 2002 10.4-51 RN04-003 February 2004 10.4-22 RN06-006 June 2006 10.4-52 RN08-001 May 2009 10.4-23 RN09-013 April 2021 10.4-53 02-01 May 2002 02-01 May 2002 RN18-042 October 2018 10.4-54 02-01 May 2002 10.4-24 RN09-013 April 2021 10.4-55 02-01 May 2002 RN04-012 July 2004 10.4-56 RN06-041 November 2011 10.4-25 02-01 May 2002 10.4-57 02-01 May 2002 10.4-26 00-01 December 2000 10.4-58 02-01 May 2002 10.4-27 RN04-026 August 2004 10.4-59 02-01 May 2002 10.4-28 00-01 December 2000 10.4-60 02-01 May 2002 10.4-29 00-01 December 2000 10.4-61 RN05-008 October 2005 10.4-30 00-01 December 2000 10.4-62 02-01 May 2002 10.4-31 00-01 December 2000 10.4-63 02-01 May 2002 RN12-030 November 2017 10.4-32 RN04-026 August 2004 10.4-64 02-01 May 2002 10.4-33 00-01 December 2000 RN12-030 November 2017 10.4-34 RN01-082 March 2003 10.4-65 02-01 May 2002 10.4-35 02-01 May 2002 Fig. 10.4-1 RN09-012 February 2010 RN12-030 November 2017 RN06-024 December 2012 10.4-36 00-01 December 2000 10.4-2 96-03 (Deleted)

RN12-030 November 2017 10.4-2a 96-03 (Deleted) 10.4-37 00-01 December 2000 RN12-030 November 2017 10.4-2b 96-03 (Deleted) 10.4-38 00-01 December 2000 10.4-3 02-01 May 2002 RN12-030 November 2017 10.4-4 (pg 1) 02-01 May 2002 10.4-39 00-01 December 2000 10.4-4 (pg 2) 02-01 May 2002 RN12-030 November 2017 10-vii Reset April 2021

LIST OF EFFECTIVE PAGES (LEP)

Page/Fig. No. Amend. No. Date Page/Fig. No. Amend. No. Date 10.4-4 (pg 3) 02-01 May 2002 10.4-4a 96-03 September 1996 RN19-006 June 2019 10.4-4b 96-03 September 1996 RN19-006 June 2019 10.4-5 RN14-025 May 2015 10.4-6 96-03 Deleted RN18-011 August 2018 10.4-7 96-03 Deleted 10.4-7a RN06-041 November 2011 RN10-014 November 2011 RN10-018 November 2011 RN18-011 August 2018 RN18-026 October 2018 Fig. 10.4-8 RN15-024 January 2016 RN12-030 November 2017 10.4-8a Deleted November 2011 10.4-9 RN06-024 December 2012 RN18-010 May 2018 10.4-10 RN11-025 July 2012 RN19-009 June 2019 10.4-11 RN08-031 November 2011 10.4-12 RN09-001 June 2010 10.4-13 RN07-028 November 2008 10.4-14 RN06-008 July 2012 RN12-011 November 2012 10.4-15 RN04-037 May 2005 10.4-16 RN14-029 January 2016 RN15-024 January 2016 RN16-004 July 2016 RN12-030 November 2017 10.4-17 RN03-025 August 2003 RN15-005 August 2019 10-viii Reset April 2021

10.0 STEAM AND POWER CONVERSION SYSTEM 10.1

SUMMARY

DESCRIPTION The steam and power conversion system is shown schematically by Figure 10.1-1, RN Sheets 1 and 2. Principal design and performance characteristics are given in detail in 02-022 Section 10.4. The heat balance guaranteed by the turbine manufacturer is shown by Figure 10.1-2. Figure 10.1-3 shows the maximum calculated turbine power (stretch power) heat balance.

The steam and power conversion system includes the following:

1. Main Steam System.
2. Turbine Generator.
3. Condensate System.
4. Condenser Air Removal System.
5. Feedwater System.
6. Turbine Bypass System.
7. Circulating Water System.
8. Steam Generator Blowdown System.
9. Emergency Feedwater System.

00-01 The thermal energy of steam generated by a 3 loop, Pressurized Water Reactor Nuclear Steam Supply System (NSSS) is converted to electrical energy through a tandem compound, 1800 rpm turbine generator.

Steam is produced in 3 steam generators where heat is transferred from the reactor coolant system to the feedwater. This steam flows from each steam generator to a distribution header. From this distribution header, 4 main steam lines convey the steam to a double flow, high pressure turbine. Steam exiting the high pressure turbine normally passes through 2 moisture separator reheaters prior to entering 2, double flow, low pressure turbines. Steam exits from the low pressure turbines to the main condenser. The high and low pressure turbines are equipped with a total of 6 extraction points which provide steam for feedwater heating. Moisture separator drains, steam reheater drains and high pressure heater drains are returned to a deaerating heater where they become part of the feedwater. Low pressure heater drains and steam packing condenser drains are cascaded to the main condenser. RN 02-022 10.1-1 Reformatted Per Amendment 00-01

Steam exhausted from the low pressure turbines is condensed and deaerated in a 2 shell surface condenser. Condensate is collected in a hotwell sized for a holding capacity of approximately 2 minutes at maximum condensate pump flow. Condensate is normally pumped from the hotwell by 2 of the 3 condensate pumps. The condensate RN passes through the steam packing condenser and 3 stages of low pressure heaters to 02-022 the deaerating heater and deaerator storage tank. Each of the 3 stages of low pressure heaters is comprised of 2 parallel 50 percent capacity trains.

The feedwater booster pumps take suction from the deaerator storage tank and discharge to the feedwater pump suction. The feedwater pumps discharge to 2 trains of high pressure heaters. Feedwater exiting these heaters passes into a single header from which it is distributed to the feedwater flow control valves. The feedwater flows from the feedwater flow control valves through the containment isolation valves into the steam generators.

The Emergency Feedwater System provides an additional means for the supply of feedwater to the steam generators for use when the Feedwater System is not available.

This permits continued transfer of reactor coolant thermal energy to feedwater in the steam generators. The Emergency Feedwater System consists of 2 electric motor driven and 1 turbine driven emergency feedwater pumps. These pumps, when required, provide feedwater to the steam generators from a reserve supply maintained in the condensate storage tank. A backup source of water is provided by connection to the Service Water System.

Noncondensible gases removed from the condenser by the Condenser Air Removal System are monitored for radioactivity. The condenser offgas is normally discharged to 02-01 the Auxiliary Building Exhaust System charcoal filters. Provision is made for discharge of the noncondensibles to atmosphere.

00-01 Should a 100 percent loss of turbine load occur, reactor coolant thermal energy is dissipated through the formation of steam in the steam generators and subsequent bypassing of the steam to the condenser and/or the atmosphere through the Turbine Bypass System and through the power operated relief valves.

10.1-2 Reformatted Per Amendment 00-01

The following portions of the steam and power conversion system are safety-related:

1. Main Steam System piping inside the Reactor Building.
2. The portion of the Main Steam System which forms a part of the containment boundary, including main steam safety valves, power operated relief valves, and main and branch steam isolation valves.
3. The main steam piping to the emergency feedwater pump turbine.
4. The Emergency Feedwater System.
5. Feedwater System piping from the feedwater containment isolation valves to the steam generators.
6. Steam generator blowdown piping from the steam generator to and including the containment isolation valves.

10.1-3 Reformatted Per Amendment 00-01

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10.2 TURBINE GENERATOR 10.2.1 DESIGN BASES The turbine generator is a General Electric Company (GE) TC4F-43" LSB, tandem compound, 4 flow exhaust unit with moisture separation and reheat between the high pressure (HP) and low pressure (LP) sections. The unit operates at 1800 rpm and is rated at a gross generator output of 1,017,000 kW with all feedwater heaters in service, 02-01 at the nominal plant exhaust pressure of 2.13/2.92 inches Hg (absolute) and zero makeup.

Steam conditions at the turbine inlet are 980 psia and 1193.5 BTU/lb. Normal and 02-01 upset conditions are tabulated on the system diagram, Figure 10.3-2.

The turbine generator design capacity is 1,039,489 kW (Ref. Fig. 10.1-3). The turbine 02-01 generator is expected to operate in the base load mode for the majority of its design life.

Normal load swings are limited to 5% per minute which is the rate of change permitted by the Nuclear Steam Supply System (NSSS). A step load change of 10% of full power rating can be accommodated without use of the Turbine Bypass System.

10.

2.2 DESCRIPTION

10.2.2.1 General RN The turbine consists of 3 casings: a double flow HP section followed by 2 double flow 02-022 LP casings. The last stage turbine wheels have 43 inch buckets. Mechanical moisture separation and reheat are provided between HP and LP sections.

The heat cycle provides for extraction at 6 pressure stages:

1. One (1) on the high pressure turbine casing (heater No. 1).
2. One (1) on the moisture separator (heater No. 2).
3. Four (4) on each of the 2 LP turbine casings (heaters No. 3 through 6).

The generator operates at 1800 rpm. It is a 3 phase, 60 Hz unit, rated 1,137,680 kVA at 22,000 volts, 0.905 pf and 60 psig hydrogen pressure. A shaft driven alternator exciter, rated at 2940 kVA @ 0.95 power factor (pf) provides the power necessary for field RN 05-038 excitation. Section 10.2.2.4 presents a discussion of the Generator Gas System.

10.2-1 Reformatted November 2011

10.2.2.2 Turbine Generator Control An Electrohydraulic Control System (EHC) (using electronic computing devices and high pressure, fire resistant fluid) actuates and controls the steam valves. This system is completely separated from the bearing oil supply.

The original EHC analog control cabinet and turbine-generator skid interfaces underwent a significant upgrade during RF-19 to replace obsolete equipment and to enhance overall system reliability. The upgrade consists of a "triple modular redundant" (TMR) digital control system, which utilizes three separate and independent controller processor modules and associated redundant input/output. EHC control logic algorithms utilize 2-of-3 (typical) software implemented fault tolerance (SIFT) voting techniques to optimize input/output signal data integrity and diagnostic trending.

Primary

controllers perform primary system control and trip protection functions (including primary overspeed protection). Emergency

controllers perform emergency (backup) overspeed protection function. and

controller protection functions which result in a Turbine Trip condition (as described below and per Figure 7.2-1, Sheet 15) interface with downstream Trip Manifold Assembly (TMA) electromechanical and hydraulic devices, located in the Turbine front standard. The TMA is comprised of two independent trains of three sets of Electronic Trip Device (ETD) solenoids/pilot-actuated dump valves, of which 2-of-3 in either train must change position to trip the turbine. A trip condition results in pressure relief of the emergency trip system (ETS) header, which in turn causes turbine steam RN 11-015 valves closure due to the loss of ETS hydraulic fluid pressure. During normal operation, reactor power is controlled (using the Reactor Control System, as described in Section 7.7.1) to match turbine load as measured by turbine first stage pressure. The desired turbine steady-state load is established manually by the operator through inputs into EHC. EHC control logic algorithms establish/maintain the allowable turbine speed and turbine load conditions, ensure the required positioning of all turbine steam valves, and facilitate other loading/unloading evolutions (e.g., shell/chest warming, runbacks). These algorithms perform programmed control functions based upon comparison of: actual turbine-related operating parameters monitored by EHC (e.g., valve positions, system pressures); desired operator input settings; and pre-programmed system state point limits (e.g., control valve steam flow-to-valve lift position characterizations [per steam flow to turbine load demand correlations], runback conditions, overspeed regulation, other system limitations). Table 10.2-0 provides a listing of signals that will shut down the turbine. Figure 7.2-1, Sheet 15 functionally shows EHC and turbine system interfaces which perform turbine trip-related functions. Receipt of 2-of-3 actuations via either Primary Trip Relays (PTRs) or

Emergency Trip Relays (ETRs), in either train of its or

controllers, will result in the corresponding change of state of its downstream TMA EHC interface devices (i.e., de-energized ETD solenoids and tripped-open ETD 10.2-2 Reformatted November 2011 pilot-actuated dump valves associated with the actuated train). The outcome of either trains 2-of-3 dump valve actuation is loss of ETS hydraulic fluid, closure of Turbine Stop RN and Control Valves, and a Turbine Trip condition. This 2-of-3 Turbine Trip actuation can 11-015 also result from a complete loss of both non-safety related power supply feeders to the EHC control system cabinet (including the loss of a dedicated EHC battery-backed uninterruptible power supply, in the alternate feeder circuit). 10.2.2.3 Turbine Generator Overspeed Protection The turbines rotational speed is sensed by a total of six passive magnetic-type probes used in conjunction with a multi-toothed wheel on the turbine shaft. Three of these speed probes (in the controllers) provide input signals to speed control and primary trip protection algorithms. The remaining three speed probes (in the

controllers) provide input signals directly to emergency trip protection algorithms. Steam valves associated with turbine generator overspeed protection are shown by Figure 10.3-2. Control details for the main stop valves (MSV) are shown by Figure 10.2-2. Control details for the control valves are shown by Figure 10.2-3a. Control details for the combined intermediate valves (CIV), which are the intermediate stop valve (ISV) and intercept valve (IV), are shown by Figure 10.2-3b. The ISV and IV are 2, independent, separately actuated valves in the same valve body, called the CIV. Overspeed protection mechanisms and the hydraulic trip system are shown by Figure 10.2-4. ETD components (as described in Section 10.2.2.2) receive high pressure (1600 psig nominal) hydraulic fluid from the EHC power unit, and regulate the ETS header pressure condition. ETS pressure is high when the hydraulic trip system is reset, and RN low (at drain pressure) when the system is tripped. The condition of the ETS header 11-015 depends upon the state of 2-of-3 ETD solenoids/dump valves. During a turbine generator overspeed occurrence, the EHC control system receives and/or

speed sensor input signals which exceed the pre-defined Primary and/or Emergency speed setpoint levels. Turbine trip logic actuation will occur when 2-of-3 speed signals or 2-of-3

speed signals exceed their respective speed setpoint. (Note that turbine trip actuation will also occur in the event of postulated speed sensor failures, including the and

speed difference fault trip and zero speed mismatch trips functionally shown on Figure 8.3-8.) Overspeed-related turbine trip logic actuation will cause ETD solenoids to de-energize and ETD dump valves to de-pressurize the ETS hydraulic trip header (identical to other turbine trip conditions, as described in Section 10.2.2.2).

1. The disc dump valves of the MSV, CV, IV, and ISVs are opened causing rapid closure of the steam valves due to spring and steam force.
2. The ETS pressure transmitters maintain the tripped condition within the EHC control system.
10.2-3 Reformatted November 2011
3. The extraction relay dump valve isolates the air supply to and vents air from the RN air cylinders of the turbine extraction nonreturn valves. Spring assist on the air 11-015 cylinder aids in positive closure of the nonreturn valves.
Frequent inservice testing of the overspeed trip mechanisms and steam valves ensures the reliability of the overspeed protection systems. All steam valves, except the nonreturn valves, located inside the condenser in the low pressure feedwater heater extraction piping, are capable of online testing. This system is designed to be fail safe, i.e., a malfunction of the system will trip close all turbine steam source valves, limiting turbine overspeed. A high or moderate energy 02-01 piping failure at the turbine, which would cause a loss of power (electric or hydraulic) to the overspeed protection system due to severance of electrical cable or hydraulic lines, would cause all turbine steam source valves to close. The turbine trip logic also includes fail safe features which limit turbine overspeed. The 02-01 trip logic verifies that at least 1 of the 2 low pressure steam source valves (i.e., intermediate stop valve or intercept valve) in each line to the turbine has closed and that all high pressure main turbine stop valves have closed before load is disconnected from the main generator. In the event of a pipe rupture, with manual turbine trip, load would not be disconnected from the main generator unless all turbine steam source valves, excluding extraction valves, were closed. The extraction valves are nonreturn (check) valves and, therefore, do not require external signals to close. The connection from the low pressure turbine to the condenser is under vacuum during operation. In the event of failure of this connection, air would initially be drawn into the condenser and backpressure on the turbine would increase to the point where the turbine would trip due to the high backpressure. Venting of air into the condenser is a method normally used to quickly slow a turbine following a trip. Some steam may be released while the turbine is being tripped. A turbine trip will initiate a reactor trip. The reactor trip from turbine trip will be 02-01 automatically blocked by P-9 (power level less than 50% rated thermal power) and on increasing power reinstated automatically by P-9. Since the turbine overspeed protection system is of a fail safe design and no credit is taken for reactor trip due to turbine trip in any accident analysis, protection from pipe rupture is neither required nor provided. A failure analysis of the turbine generator overspeed protection system is presented by Table 10.2-2. 10.2.2.4 Generator Gas System The bulk hydrogen and carbon dioxide storage facilities are located in the yard area south of the Turbine Building (see Figure 1.2-1). The hydrogen and carbon dioxide storage and distribution systems are schematically illustrated by Figure 10.2-5. 10.2-4 Reformatted November 2011 The hydrogen storage facility consists of 6 storage tanks, each pressurized to a nominal 02-01 pressure of 2300 psig. Hydrogen pressure is reduced to the generator manufacturers control panel supply pressure in 2 stages. Liquid carbon dioxide is stored in a refrigerated storage tank and is vaporized in the Turbine Building as required for generator purging. The Generator Gas System is equipped with an inservice gas analyzer. This analyzer actuates an alarm upon detection of low (<90%) hydrogen purity. Safety features associated with the Generator Gas System include the following:
1. Remote, outdoor, bulk hydrogen storage and pressure reduction facilities are provided. Hydrogen supply piping from the storage facility to the Turbine Building is under low pressure and is also buried.
2. The inservice generator gas analyzer actuates an alarm to warn of low hydrogen purity in advance of formation of an explosive mixture. A generator differential fan pressure gage provides an independent check of hydrogen purity.
3. The Generator Gas System is operated by experienced personnel.
4. Generator gases are vented to atmosphere independent of other plant vents.
5. Operating procedures require complete purging of the generator before and after maintenance. Hydrogen is purged from the generator by carbon dioxide before it is opened. When maintenance is completed, the generator is again purged with carbon dioxide to remove the air prior to refilling with hydrogen.
6. The generator gas analyzer is periodically calibrated to assure accuracy.
7. System valves are periodically checked for indication of leakage to assure system leak tightness.
8. Physical separation of the Generator Gas System from safety related equipment required for safe plant shutdown provides additional safety.
10.2.3 TURBINE MISSILES The LP turbine built up rotors consisting of wheels shrunk-on a central shaft have been replaced by single piece monoblock rotors in spring, 1996. The monoblock turbine rotor design eliminates the brittle fracture failure mode and the probability for a wheel burst and missile generation at normal operating speeds. Furthermore, the 2011 installation of the digital EHC control system provides significant redundancy and reliability enhancements over the original overspeed protection. The improvements to rotors and RN controls (relative to the original plant design) provide for a further reduction in the 11-015 probability of turbine missile generation due to an overspeed protection system failure. 10.2-5 Reformatted November 2011 A compilation report [4] contains various missile probability and reliability analyses performed by the turbine manufacturer, which encompass the current system RN configuration details (of the monoblock rotors and the digital control system retrofit).11-015 These analyses document the following summary of pertinent results:
  • The maximum attainable main turbine shaft speed is 214% - 217% of normal running speed at the worst possible operating conditions. At this point, the driving forces in the steam are counteracted by the drag forces and the rotor train can no longer accelerate.
  • A complete failure of the Main Turbine Control System is required to achieve the maximum attainable overspeed. The annual probability of a complete control failure is in the range 10-8.
  • The LP monoblock overspeed capability based on material properties and rotor 02-01 design is 221% for LPA and 222% for LPB.
02-01
1. Turbine Design The turbine assembly was designed to withstand normal conditions and anticipated transients, including those resulting in turbine trip, without loss of structural integrity. The design of the turbine assembly satisfied the following criteria:
a. Turbine shaft bearings were designed to retain structural integrity under normal operating loads and anticipated transients, including those leading to turbine trips.
b. The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20% overspeed were controlled in the design and operation so as to cause no distress to the unit during operation.
c. The maximum tangential stress in rotors resulting from centrifugal forces, interference fit and thermal gradients does not exceed 0.75 of the yield strength of the materials at 115% of rated speed.
2. Inservice Inspection The inservice inspection program for the turbine assembly will include the following:
a. Disassembly of the turbine at approximately 10 year intervals, during plant shutdown, and complete inspection of all normally inaccessible parts, such as couplings, coupling bolts, turbine shafts, low pressure turbine buckets, low pressure wheels, and high pressure rotors.
b. Visual, surface, and volumetric examinations, as indicated below:
10.2-6 Reformatted November 2011 (1) A thorough volumetric examination of all low pressure wheels and high pressure rotors, including areas immediately adjacent to keyways and bores, will be conducted. This examination is predicated on the development of suitable remote inspection equipment. (2) Visual examination of all accessible surfaces of rotors and wheels. (3) Visual and surface examination of all low pressure buckets. (4) Surface examination (100%) of couplings and coupling bolts. The inservice inspection of main steam and reheat valves will include the following:
a. Dismantle at least 1 main steam stop valve, 1 main steam control valve, 1 reheat stop valve, and 1 reheat intercept valve at approximately 3-1/3 year intervals during refueling or maintenance shutdowns, and conduct a visual and surface examination of valve seats, discs, and stems. If unacceptable flaws or excessive corrosion are found in a valve, all valves of that type will be inspected. Valve bushings will be inspected and cleaned, and bore diameters will be checked for proper clearance.
b. Main steam stop and control, reheat stop and intercept valves will be exercised at least once during a 3 month operating interval, by closing each valve and observing, by the valve position indicator, that it moves smoothly to a fully closed position. This observation will be made by actually watching the RN valve motion.11-015 10.2.4 EVALUATION Turbine rotor missiles will not be generated with the rotor burst capability exceeding the 02-01 overspeed potential. Therefore, the possibility of missiles being generated by a wheel burst due to stress corrosion cracking and causing damage to critical plant components, RN is no longer present, and there no longer exists any wheel disc integrity concern.11-015 Reference [4] provides a detailed safety evaluation of steam valve arrangement and trip RN 11-015 devices, turbine extraction line overspeed trip protection, and operating and testing of overspeed protection systems.
10.

2.5 REFERENCES

1. Deleted by RN 11-015.
2. Deleted by RN 11-015.
3. Deleted by RN 11-015. RN 11-015
4. V. C. Summer Nuclear Station, Main Turbine Missile Probability and Reliability Reports, VCSNS Technical Report TR03880-002, dated July 12, 2011.

10.2-7 Reformatted November 2011

TABLE 10.2-0 TURBINE SHUTDOWN SIGNALS

1. Train A EHC external trips, from any one of the following conditions:
  • Generator electrical fault.
  • LP Heater 5A, 5B, 6A, and/or 6B high-high levels (10 second time delay).
2. Train B EHC external trips, from any one of the following conditions:
3. Manual turbine trip pushbuttons (2 of 2 at MCB, or 2 of 2 at Front Standard).
4. Main shaft oil pump discharge pressure low (2 of 3), and turbine speed greater than 1350 rpm.
5. Lube oil bearing header pressure low (2 of 3). RN 11-015
6. EHC hydraulic header pressure low (2 of 3).
7. Speed signal mismatch trips, in Primary () and/or Emergency (

) controllers, from any one of the following conditions:

  • zero speed mismatch fault (2 of 3 Primary speed sensors indicate zero speed condition while

    Emergency sensors indicate greater than 15%

of rated speed).

  • zero speed mismatch fault (2 of 3 Emergency

    speed sensors indicate zero speed condition while Primary sensors indicate greater than 15% of rated speed).

  • and

    speed difference fault (difference greater than 5%).

  • excessive acceleration or deceleration rate change (2 of 3 speed sensors).

  • excessive acceleration or deceleration rate change (2 of 3

    speed sensors).

8. Primary ( controllers) overspeed trip (109.5% of rated speed).
9. Emergency (

controllers) overspeed trip (110% of rated speed).

10.2-8 Reformatted November 2011

TABLE 10.2-0 (Continued)

TURBINE SHUTDOWN SIGNALS

10. Exhaust vacuum (absolute) pressure high (2 of 3 in either [LP A or LP B] hood), and turbine speed greater than 150 rpm.
11. Exhaust hood high temperature (2 of 3 in either [LP A or LP B] hood).
12. Loss of stator cooling trip (due to failed runback).

RN

13. Moisture separator reheater level high (15 second time delay) (2 of 3 in either A or 11-015 B MSR).
14. Thrust bearing excessive wear detection (from 2 of 3 axial bearing position sensors).
15. Shaft bearing high vibration (10 second time delay); manual operator action required if automatic trip disabled.
16. Train A or Train B Off-line ETD Test tripped condition (2 of 3 electronic trip devices

[ETDs] under test are de-energized [tripped]).

10.2-9 Reformatted November 2011

TABLE 10.2-1 TURBINE GENERATOR OVERSPEED PROTECTION SYSTEM Overspeed Trip Mechanism Set Speed Action Speed Governor (Normal) 1836 to 1872 RPM Complete closure of intercept valves at 102% of (102% to 104%) rated speed; complete closure of control valves at 104% of rated speed. Loss of two speed signals actuates the hydraulic trip system.

RN Primary Overspeed Trip 1971 RPM Actuates the hydraulic trip system.11-015 (109.5%)

Emergency Overspeed Trip 1980 RPM Actuates the hydraulic trip system.

(110%)

10.2-10 Reformatted November 2011

TABLE 10.2-2 TURBINE OVERSPEED PROTECTION SYSTEM FAILURE ANALYSIS Component Malfunction Comment Steam Valve One valve fails to close on Each steam line contains paired steam (MSV, CV, IV, ISV) overspeed trip valves installed in series. Thus, failure of one RN 11-015 valve (e.g., CV1) to close does not defeat its paired valve (e.g., MSV1). No impact to overspeed function exists.

Turbine Extraction One valve fails to close The overspeed potential of the feedwater Nonreturn Valve heating system is small. The total uncontrolled energy can contribute no more than 1.5% to the running speed of the turbine generator.

Primary Overspeed Trip One Train of protection logic Two Trains of logic are installed. Thus, Actuation Logic fails to trip at Primary Overspeed failure of one Train will not defeat the other setpoint Train. Furthermore, backup protection is provided by Emergency

Overspeed Trip Actuation Logic. Emergency

Overspeed Trip One Train of

protection logic Two Trains of

logic are installed. Thus, RN Actuation Logic fails to trip at its Overspeed failure of one Train will not defeat the other 11-015 setpoint Train. Electronic Trip Device (ETD) One Train of 2-of-3 ETD Trip manifold assembly consists of two trains solenoid/dump valve components of 2-of-3 ETD solenoid/dump valve fail to trip components. Either ETD train will trip the turbine. Hydraulic Trip System Piping Piping fails causing All steam valves close as in overspeed trip. depressurization 10.2-11 Reformatted November 2011 TABLE 10.2-2 (Continued) TURBINE OVERSPEED PROTECTION SYSTEM FAILURE ANALYSIS Component Malfunction Comment Primary AC Power Supply Feeder Loss of primary power supply No impact to overspeed protection function (failure or other unavailability) to exists. EHC control system - Alternate AC feeder will maintain EHC control system power, to assure actuation logic function. - Complete loss of power will RN 11-015 de-energize/dump ETD components. Alternate AC Power Supply Feeder Loss of alternate power supply No impact to overspeed protection function (failure or other unavailability) to exists. EHC control system - If available, primary feeder available will maintain EHC control system power and actuation logic function. - If primary feeder is not available, a battery-backed UPS (in alternate feeder circuit) will permit timely manual turbine trip and post-trip monitoring. - Complete loss of power will de-energize/dump ETD components. 10.2-12 Reformatted November 2011 Figure 10.2-1 Deleted per RN 01-042 Amendment 95-04 November 1995 FSAR FIGURE REFERENCE FIGURE 10.2-2 DRAWING 1MS-27-247 FSAR FIGURE REFERENCE FIGURE 10.2-3a DRAWING 1MS-27-248 FSAR FIGURE REFERENCE FIGURE 10.2-3B DRAWING 1MS-27-249 FSAR FIGURE REFERENCE FIGURE 10.2-4 DRAWING 1MS-27-250 FSAR FIGURE REFERENCE FIGURE 10.2-5 DRAWING D-302-301 10.3 MAIN STEAM SUPPLY SYSTEM The Main Steam Supply System conveys main steam from the steam generators to the turbine generator and, through branch lines, to the following: feedwater pump drive turbines, emergency feedwater pump drive turbine, moisture separator reheaters, auxiliary steam system, deaerating feedwater heater, and steam dumps to the condenser and atmosphere. 10.3.1 DESIGN BASES 10.3.1.1 Codes and Standards The Main Steam Supply System is designed in conformance with the following codes and standards:

1. Steam generator secondary sides, piping and valves, between the steam generators and main steam isolation valves, including the main steam isolation valves, main steam safety valves, and power relief valves, are classified as Safety Class 2a and are designed in accordance with the ASME Code,Section III, Class 2.
2. Steam piping and components in the lines to the emergency feedwater pump drive turbine are classified as Safety Class 2b and are designed in accordance with the ASME Code,Section III, Class 3.
The emergency feedwater pump drive turbine exhaust piping is classified as safety class 2b and is designed in accordance with the ASME Code,Section III, Class 3 except for hydrotesting and code stamping.
3. Main steam piping in the Intermediate Building between the main steam isolation valves and the Turbine Building wall is non-nuclear safety class. However, this piping excluding branch lines, satisfies the requirements except for stamping, of the ASME Code,Section III, Code Class 2. This provides greater assurance of design and fabrication integrity, thus, reducing risk of postulated pipe rupture in this area. This piping is identified as "Note 1" piping on Figures 10.3-1 and 10.3-2.
Originally the main and branch lines were designated as "Note 1" piping to reduce the number of postulated pipe rupture locations by the use of a code stress analysis to choose intermediate breaks. In the final pipe rupture analysis of the branch lines, stress analysis was not used and intermediate breaks were postulated at each fitting (see Section 3.6.2.5.1). Therefore, it was no longer necessary to provide code piping and the "Note 1" designation for these branch lines was deleted.
4. Piping other than that noted in 1, 2 and 3, above, is non-nuclear safety class and is designed in accordance with ANSI B31.1[1].
10.3-1 Reformatted Per Amendment 02-01 \5. Cast steel valves, except those noted in 1, 2 and 3, above, are non-nuclear safety class and are designed in accordance with ANSI B16.5[2].
6. Main Steam Supply System drains are designed using "Recommended Practices for the Protection of Water Damage to Steam Turbines Used for Electric Power Generation, Part II,"[3] as a guide.
7. The Main Steam Supply System is designed to permit inservice inspection as required by the ASME Code,Section XI.
8. The Main Steam Supply System is designed with the capability to dump steam to the condenser and/or the atmosphere as discussed in Section 10.4.4.
10.3.1.2 Heat Balance The Main Steam Supply System is designed to deliver 11,734,149 lb/hr of steam to the turbine control valves and 1,123,964 lb/hr to the moisture separator reheater for a total 02-01 of 12,858,113 lb/hr. (See GE Heat balance 170x595-21, Rev. 1). 10.3.1.3 Design Conditions The system is designed to withstand the same conditions as are the steam generator secondary sides. Design pressure is 1185 psig; design temperature is 600°F. Design pressures and temperatures for piping, valves, and pressure retaining components are tabulated on Figures 10.3-1 through 10.3-4. 10.3.1.4 Environmental Conditions Environmental conditions considered in the design of the Main Steam Supply System are presented in Table 10.3-1. 02-01 The emergency and faulted conditions are based on the Main Steam Line Break and Loss of Coolant Accidents. Components within the Reactor Building are also subjected to a spray of borated water and sodium hydroxide as described in Section 6.2.2.2.1. 10.3-2 Reformatted Per Amendment 02-01 10.

3.2 DESCRIPTION

10.3.2.1 General The Main Steam Supply System consists of 3 steam generators, 3 flow restrictors, 15 safety valves, 3 steam generator power relief valves, 3 main steam isolation valves, 8 steam dump valves to the condenser, 3 atmospheric steam dump valves and other required valves, steam traps, instrumentation, controls, and associated piping. See Figures 10.3-1 through 10.3-4.

The Main Steam Supply System conveys saturated steam from the 3 steam generators to the turbine generator.

One (1) line from each of the 3 steam generators conveys main steam to a header located in the Intermediate Building. From the header a total of 4 lines proceed to the turbine stop valves. Steam flow to the high pressure turbine is regulated by the turbine control valves.

Moisture separator reheater units are located immediately beside the turbine between the high pressure and low pressure elements. Heating tube bundles within each moisture separator reheater, supplied with steam from the Main Steam Supply System, superheat high pressure turbine exhaust steam approximately 136°F before it enters the low pressure turbine elements.

Main steam is also supplied to the following:

1. Feedwater pump drive turbines for startup and runout.
2. Auxiliary Steam System for the liquid waste evaporator as required during normal operation and during plant shutdown until the auxiliary boiler is operational.
3. Extraction Steam System for pegging and sparging the deaerator.
4. Emergency feedwater pump drive turbine during emergency and normal plant shutdown to supply minimum feedwater requirements.

The Main Steam Supply System was originally designed to follow a full load rejection, defined as a reduction from 100% of rated turbine generator load to plant auxiliary load, without reactor trip through actuation of the steam dump to the condenser and atmosphere. With the transition to longer fuel cycles and less negative moderator 02-01 temperature coefficients at the beginning of the fuel cycle, a full load rejection can no longer be sustained without a reactor trip for all times in core life and all allowable values of full power, average coolant temperatures within the Reactor Coolant System.

10.3-3 Reformatted Per Amendment 02-01

Steam dump valves permit unit operation at turbine loads lower than the minimum power setting (15% reactor power) of the Nuclear Steam Supply System (NSSS) automatic control. In addition, the steam dump valves permit reduction of turbine generator load at a rate greater than the 5% per minute maximum rate of load reduction for the NSSS.

Steam generator power relief valves provide a means for plant cooldown by controlled steam discharge to the atmosphere should the condenser not be available. These valves pass a total of 18.76% of the rated maximum steam flow (at full load pressure).

One (1) valve is provided in each generator line, upstream of the main steam isolation valves.

10.3.2.2 Main Steam System Piping Each line from the steam generators is 32 inch nominal OD, 1.15 inch minimum wall, carbon steel pipe. The piping inside the Reactor and Intermediate Buildings is routed and restrained to minimize the possibility of a single line failure affecting the other piping. In the area where the safety valves are located, the pipe OD is increased and the nominal wall thickness is 1.90 inches to provide extra strength. The 3 lines from the steam generators are manifolded into a 32 inch nominal OD, 1.15 inch minimum wall, carbon steel header.

From the header, steam flows through four(4) 30 inch nominal OD, 1.125 inch nominal wall, carbon steel lines to the turbine generator. Steam also flows from the header through a 24 inch OD, schedule 80, carbon steel pipe to the moisture separator reheater and feedwater pump drive turbines.

A 4 inch OD, schedule 80, carbon steel pipe supplies steam from each of 2 steam generator main steam lines to the emergency feedwater pump drive turbine. Steam from only one steam generator is needed for pump operation; 2 sources are provided for required redundancy.

Steam generators and flow restrictors are discussed in detail in Section 5.5.

10.3-4 Reformatted Per Amendment 02-01

10.3.2.3 Main Steam Isolation Valves Each of the 3 main steam lines proceeding from the steam generators to the main steam header is equipped with a quick closing main steam isolation valve capable of tight closure, regardless of flow direction. The main steam isolation valves are of the articulated poppet, wye type design. These nominal 32 inch valves have a capacity of 4,277,315 lb/hr steam flow with an approximately 2.26 psi maximum calculated pressure drop across the fully open valve. These valves are designed for 1284 psig at 600°F. The valves are actuated by an air cylinder operator (air to open; spring to close).

Closure time is adjustable. Maximum closure time is 7 seconds after receipt of a closure signal. Main steam isolation valve closure signals are as follows:

1. High containment pressure.
2. High steam flow with coincident lo-lo average primary coolant temperature.
3. Low steam pressure.
4. Manual.

These valves are located in the Intermediate Building downstream of the main safety valves.

The quick closing main steam isolation valves prevent reverse flow of steam. If a steam line rupture occurs between an isolation valve and a steam generator, the affected steam generator continues to blow down, while the isolation valves are automatically closed to prevent blowdown from the unaffected steam generators. Should an isolation valve not close, flow from the Main Steam System downstream of the main isolation valves is limited by either normally closed valves or by valves that are automatically closed by interlocks from the NSSS system or from the turbine generator system as tabulated in Table 10.3-2. This small steam flow does not impact the results of the main steam line break analysis in Section 15.4-2.

If a main steam line rupture occurs downstream of an isolation valve, all 3 isolation valves are automatically closed, stopping main steam flow. Closure of the isolation valves terminates the sudden large release of energy in the escaping steam, thereby preventing rapid cooldown of the Reactor Coolant System. Closure of the isolation valves also ensures a supply of steam for the 100% capacity, turbine driven emergency feedwater pump.

The maximum permissible main steam isolation valve leakage in the direction of normal flow is in accordance with the recommendations of MSS SP-61[4]. In the direction of reverse flow, leakage is less than 1% of normal steam flow through the main steam isolation valve.

10.3-5 Reformatted Per Amendment 02-01

10.3.2.4 Main Steam Safety Valves Main steam safety valves are located in each main steam line outside the Reactor Building, upstream of the main steam isolation valves to protect the steam generators against overpressure. These valves are designed, fabricated and stamped in accordance with the ASME Code,Section III. The safety valve setpoints are given in Table 10.3-1a. The safety valves are sized to pass the steam flow resulting from complete load rejection or shutoff of main steam flow without reactor trip. The maximum steam flow through each individual valve is limited to 970,000 lb/hr at steam generator design conditions, in accordance with Nuclear Steam Supply System criteria.

In the event that a single main steam safety valve sticks in the full open position, uncontrolled blowdown from the affected steam generator is restricted within limits compatible with maintenance of reactor fuel integrity and integrity of the reactor internals.

10.3.3 EVALUATION The Main Steam Supply System design limits the effects of a main steam line rupture.

Seamless pipe is used inside the Reactor Building and for the spool piece of the penetration terminal end outside the Reactor Building. This minimizes the probability and consequences of postulated pipe rupture. Rupture of any main steam line, malfunction of any single isolation valve, or any consequential damage does not cause uncontrolled flow from more than 1 steam generator, nor does it result in containment pressure exceeding the design value.

The effects of pipe whip are considered in the layout of the system. Safety-related equipment is protected from the effects of pipe whip by restraints, physical separation, and/or barriers, if required. Pipe rupture is discussed in detail in Section 3.6, seismic design is discussed in Section 3.7.

10.3.4 INSPECTION AND TESTING REQUIREMENTS Inspection and testing requirements for the Main Steam Supply System can be divided into 2 parts: preoperational testing and inservice testing and inspection.

1. Preoperational Testing Preoperational testing of the Main Steam Supply System includes:
a. Cold hydrostatic testing.
b. Hot functional testing, including test of the functional capability of system valves.
c. Preservice inspection to establish baseline data for subsequent inservice inspection, as required by the ASME Code,Section XI.

10.3-6 Reformatted Per Amendment 02-01

2. Inservice Testing and Inspection Inservice testing and inspection of the Main Steam Supply System includes:
a. Main steam isolation valve testing as follows:

(1) The main steam isolation valves are capable of being tested during RN 03-034 normal plant operation to demonstrate their ability to respond to a "test close" signal. Upon receipt of a "test close" signal, the main steam isolation valve being tested moves to a 90 to 95% open (5 to 10%

closed) position. Upon removal of the "test close" signal, the valve returns to the 100% open position. In the event that a close signal is received during this test, such a signal overrides the test signal and the isolation valve closes completely within the specified closing time. This RN testing is no longer performed based on NUREG 1482, "Guidelines for 03-034 Inservice Testing at Nuclear Power Plants," Section 4.2.4 recommendation.

(2) Testing for complete main steam isolation valve closure is performed under shutdown conditions and verifies the ability of the valves to fully close within the specified closure time.

b. Inservice inspection requirements, in accordance with the ASME Code,Section XI, apply to all Class 2 and Class 3 main steam piping from the steam generators to the point where the main steam piping enters the Turbine Building.

Weld examinations are performed in accordance with the ASME Code,Section XI.

Inservice inspection of other Main Steam Supply System components within this boundary is discussed in Section 5.7. System components not within this boundary are not subject to inservice inspection.

10.3-7 Reformatted Per Amendment 02-01

10.3.5 WATER CHEMISTRY Secondary side water chemistry "all volatile treatment" (AVT) for corrosion control consists of the following:

1. Addition of an amine or mixture of amines for pH control.
2. Addition of an oxygen scavenger to minimize dissolved oxygen concentration.
3. Continuous steam generator secondary side blowdown to limit concentrations of dissolved and suspended solids.
4. A Condensate Cleanup System, consisting of filter/demineralizers, operated during 98-01 startup to approximately 50% flow and as required during condenser leakage and if needed, during shutdown.
5. Boric acid may be added to mitigate denting of steam generator tubes.
6. Ammonium Chloride may be added for molar ratio control.
7. Other chemicals may be added based on EPRI, NSSS supplier or SGOG guidelines and evaluation by SCE&G.

Secondary side water chemistry specifications are in accordance with the recommendations of EPRI. Recommendations of the NSSS supplier and/or the Steam Generator Owners Group (SGOG), may also be applied. 98-01 Samples of condensate, feedwater, steam, steam generator blowdown, and demineralized makeup water are available for use in monitoring and controlling secondary side water chemistry. Sampling equipment is located in the water treatment building and in the nuclear sampling room of the Control Building. Sampling equipment consists of pH, conductivity, cation conductivity, hydrazine, sodium, and dissolved oxygen analyzers for monitoring the appropriate samples at reduced temperature and pressure.

Steam generator blowdown samples are routed to the nuclear sampling room, as are other potentially radioactive samples (see Section 9.3.2). Samples from other secondary side sample points are routed to the sampling panel at the Water Treatment Building.

Grab samples are taken from secondary side sample points at regular intervals and are subjected to laboratory analyses to ensure that the analyzers are functioning properly and that secondary side water chemistry is within specification.

10.3-8 Reformatted Per Amendment 02-01

Steam generator water chemistry is controlled through sampling, steam generator secondary side blowdown, and chemical addition. During normal operation, amine injection for control of secondary side pH and oxygen scavenger for dissolved oxygen control may be regulated automatically or manually. Under transient conditions, amine 98-01 and oxygen scavenger injections are manually regulated as required by grab sample analytical results. Amine and oxygen scavenger injection equipment is located in the Intermediate Building.

There are 3 possible mechanisms for hydrogen production in secondary side water.

These mechanisms are as follows:

1. Corrosion.
2. Decomposition of hydrazine.
3. Leakage and/or diffusion from the primary side.

Hydrogen production rates will be inconsequential and any buildup in secondary side water will not be a safety hazard.

The secondary water chemistry control program will include a comprehensive monitoring program. The aim of this program is the minimization of overall system corrosion. Special emphasis will be placed on the inhibition of steam generator tube degradation. In general, the program will be based on recommendations and criteria supplied by EPRI. Recommendations from the NSSS vendor and/or the SGOG may 98-01 also be incorporated. This program consists of procedures covering those items contained in Section 6.8 of the Technical Specifications.

10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3.6.1 Fracture Toughness Where specified, test methods and acceptance criteria for fracture toughness are in compliance with the ASME Code,Section III, Article NC-2300. Charpy V-notch tests are specified for ferritic materials used in the following Class 2 components of the feedwater system:

1. Feedwater isolation valves.
2. Feedwater check valves.
3. Feedwater system Reactor Building penetration assemblies.
4. Feedwater piping.

10.3-9 Reformatted Per Amendment 02-01

Tests are specified for these feedwater system components because nominal pipe size exceeds 6 inches, material section thickness exceeds 5/8 inch and minimum service temperature can be as low as 50°F inside containment and 40°F outside containment.

Fracture toughness testing (impact testing) for ferritic materials used in the Main Steam System piping whose nominal pipe size exceeds 6 inches and material section thickness exceeds 5/8 inch was performed at a temperature of 120°F since minimum service temperature is approximately 327°F at 100 psia. This is the lowest temperature at which the steam generators are used to remove heat from the Reactor Coolant System. Testing was performed at 32°F on the main steam penetration process pipe.

The Residual Heat Removal System is used at lower temperatures and pressures. The ASME Code,Section III does not specifically require impact testing of materials used in the Main Steam Supply System. The Code stipulates that the design specification must state whether or not impact testing is required. In consideration of the high minimum service temperature for the Main Steam Supply System, impact testing is not specified.

Fracture toughness testing (impact testing) is not required for ferritic Class 2 and Class 3 components of the Emergency Feedwater System, since pipe, fittings, pumps, and valves in this system have a nominal pipe size less than 6 inches. Articles NC-2311(b) and ND-2311(b) of the ASME Code,Section III exempt these materials from impact testing requirements.

10.3.6.2 Materials Selection and Fabrication 10.3.6.2.1 Materials Not Included in Appendix I to Section III of the ASME Code Materials used are included in Appendix I to Section III of the ASME Code. Each line from the steam generators to the containment penetration assembly, inside the Reactor Building, is fabricated from SA-106, Grade C, seamless, carbon steel pipe material.

The first straight piece of pipe attached to the containment penetration assembly outside the Reactor Building is also of this material. The main steam lines from this point to the Turbine Building wall, including piping in the penetration rooms and Intermediate Building, are fabricated from SA-155, KC-70, Class 1 welded, carbon steel pipe material.

Main steam piping within the Turbine Building is fabricated from A-155, KC-70, welded, carbon steel pipe material.

10.3.6.2.2 Austenitic Stainless Steel Components No austenitic stainless steel components are used.

10.3.6.2.3 Cleaning and Handling of Class 2 and 3 Components Cleaning and handling of components is performed in accordance with Regulatory Guide 1.37 (see Appendix 3A) and ANSI N45.2.1[5].

10.3-10 Reformatted Per Amendment 02-01

10.3.6.2.4 Preheat Temperatures Compliance with Regulatory Guide 1.50 is discussed in Appendix 3A.

10.3.6.2.5 Welding Procedures Compliance with Regulatory Guide 1.71 is discussed in Appendix 3A.

10.

3.7 REFERENCES

1. American National Standards Institute, "Power Piping Code," ANSI B31.1.0, 1967, 02-01 with Addenda through Summer, 1972.
2. American National Standards Institute, "Steel Pipe Flanges, Flanged Valves, and Fittings," ANSI B16.5, 1968.
3. American Society of Mechanical Engineers, "Recommended Practices for the Protection of Water Damage to Steam Turbines Used for Electric Power Generation, Part II," TWDPS-1, April, 1973.
4. Manufacturers Standardization Society of the Valve and Fitting Industry, "Hydrostatic Testing of Steel Valves," MSS SP-61, 1961.
5. American National Standards Institute, "Cleaning of Fluid Systems and Associated Components for Nuclear Power Plants," ANSI N45.2.1, 1973.

10.3-11 Reformatted Per Amendment 02-01

TABLE 10.3-1 ENVIRONMENTAL CONDITIONS CONSIDERED IN MAIN STEAM SUPPLY SYSTEM DESIGN Condition Upset II, Normal and Emergency, 02-01 Upset I and Faulted Piping Inside Reactor Building - Most Severe Conditions (Emergency and Upset)

Ambient Temperature, °F 50 to 120 380, max.

02-01 Ambient Pressure, psia 14.7 68.2, max.

Relative Humidity, %, max. 100 100 Total Radiation, rad 2.5x107 1.9x108 RN 03-038 Piping in Penetration Rooms Ambient Temperature, °F 65 to 121 445, max.

Ambient Pressure, psia 14.7 20.3, max. 02-01 Relative Humidity, %, max. 90 100 Total Radiation, rad 2.4x106 1.6x107 RN 03-008 Piping in Intermediate Building Ambient Temperature, °F 65 to 131 398, max.

02-01 Ambient Pressure, psia 14.7 17.8, max.

Relative Humidity, %, max. 90 100 Total Radiation, rad 1.5x106 1.6x107 RN 03-008 10.3-12 Reformatted Per Amendment 02-01

TABLE 10.3-1a MAIN STEAM SAFETY VALVE SETPOINTS Main Steam Line Valve Setpoint (psig)

A 2806A-MS 1176 2806B-MS 1190 2806C-MS 1205 2806D-MS 1220 2806E-MS 1235 B 2806F-MS 1176 2806G-MS 1190 2806H-MS 1205 2806I-MS 1220 2806J-MS 1235 C 2806K-MS 1176 2806L-MS 1190 2806M-MS 1205 2806N-MS 1220 2806P-MS 1235 10.3-13 Reformatted Per Amendment 02-01

TABLE 10.3-2 STEAM GENERATOR FOR BLOWDOWN RATE No. of Max. Flow Valve Identical (all paths Size, Design Closure Power Air Flow Path Paths combined) Type in. Quality Code Time Actuation Closure Signal Quality Quality Atmospheric 3 2,910,000 Globe 8 QR B31.1.0 3 Air Normally closed, see 1E (Assoc) NNS Dump lb/hr FSAR Section 10.4.4 for and Non-1E control, fails closed Condenser 8 7,760,000 Globe 8 QR B31.1.0 3 Air Normally closed, see 1E (Assoc) NNS 02-01 Dump lb/hr FSAR Section 10.4.4 for and Non-1E control, fails closed Steam Dump 4 1,052 lb/hr* Thermodynamic 1 NNS N/A N/A Self N/A N/A N/A Drains (Trap) Steam Trap Steam Dump 4 93,272 Globe 1-1/2 NNS B31.1.0 5 Air Normally closed - fails Non-1E NNS Drains lb/hr* open RN (Bypass)04-018 Turbine 3 5,265 lb/hr* Globe 3/8 NNS B31.1.0 N/A Manual N/A 2 of 3 valves N/A N/A Cycle normally closed Sampling Main Steam 6 2,364 lb/hr* Thermodynamic 1 NNS N/A N/A Self N/A N/A N/A Drains / Steam Trap 02-01 Upstream MSIV (Trap)

Main Steam 6 42,336 lb/hr Globe 1-1/2 NNS B31.1.0 5 Air Normally closed - opens Non-1E NNS Drains / on hi drain pot level Upstream switch signal MSIV (Bypass)

Main Steam 8 2,628 lb/hr* Thermodynamic 1 NNS N/A N/A Self N/A N/A N/A Drains / Steam Trap 98-01 Downstream MSIV (Trap)

Main Steam 4 11,722,000 Turbine Stop 30 QR B31.1.0 0.15 Hydraulic Normally closed post QR N/A RN to Turbine lb/hr Valve accident 04-018 Stop Valve 10.3-14 Reformatted Per Amendment 02-01

TABLE 10.3-2 (Continued)

STEAM GENERATOR FOR BLOWDOWN RATE No. of Max. Flow Valve Identical (all paths Size, Design Closure Power Air Flow Path Paths combined) Type in. Quality Code Time Actuation Closure Signal Quality Quality Main Steam 8 124,623 Globe 1-1/2 NNS B31.1.0 5 Air Normally closed - opens Non-1E NNS Drains / lb/hr on hi-hi drain pot level Downstream switch signal MSIV (Bypass)

Gland Steam 1 32,000 Gate 4 NNS B31.1.0 30 Motor Manual remote closure - Non-1E NNS lb/hr* normally open 02-01 Pegging 1 160,000 Globe 8 NNS B31.1.0 54 Air Normally closed, fails Non-1E NNS Steam lb/hr closed. Remains closed for a FW isolation. (Modulating control from PT-2231)

Sparging 1 16,000 lb/hr Globe 2 NNS B31.1.0 6 Air Normally closed, fails Non-1E NNS Steam closed. Remains closed for a FW isolation. (Modulating control from PC-2232)

MS to FW 3 144,300 Turbine Control 4 NNS B31.1.0 1 Hydraulic FW Pump Turbine Trip Non-1E N/A RN Pump lb/hr* Valve 04-018 MS to FW 3 789 lb/hr* Thermodynamic 1 NNS N/A N/A Self N/A N/A N/A Pump Drains Steam Trap (Trap)

MS to FW 3 266,820 Globe 1-1/2 NNS B31.1.0 N/A Manual N/A - Normally closed N/A N/A 02-01 Pump Drains lb/hr (Bypass)

MS to Aux. 1 22,400 lb/hr Globe 2 NNS B31.1.0 6.1 Air Normally closed with Non-1E NNS Steam steam from extraction.

MS to Aux. 1 22,400 lb/hr Globe 1 NNS B31.1.0 N/A Manual N/A - Normally closed N/A N/A Steam 98-01 (Bypass)

  • Paths that would normally be open following a Main Steam Line Break accident.

10.3-15 Reformatted Per Amendment 02-01

TABLE 10.3-2 (Continued)

STEAM GENERATOR FOR BLOWDOWN RATE No. of Max. Flow Valve Identical (all paths Size, Design Closure Power Air Flow Path Paths combined) Type in. Quality Code Time Actuation Closure Signal Quality Quality MS to Aux. 1 263 lb/hr* Thermodynamic 1 NNS N/A N/A Self N/A N/A N/A Steam Drains Steam Trap (Trap)

MS to Aux. 1 13,860 lb/hr Globe 3/4 NNS B31.1.0 N/A Manual N/A - Normally closed N/A N/A Steam Drains (Bypass)

Reheat 1 1,189,540 Gate 24 NNS B31.1.0 100 Motor Normally open. Closes Non-1E N/A 02-01 Steam lb/hr on low pressure signal from PS-5635, following turbine trip.

Reheat 1 148,000 Gate 4 NNS B31.1.0 30 Motor Normally open. Non-1E N/A Steam lb/hr Interlocked to close with (Bypass) Reheat Steam Valve.

MS Stop 4 94,752 lb/hr Globe 1 NNS B31.1.0 N/A Motor Open for startup, Non-1E N/A Valve

Drain FW Turbine 3 88,776 lb/hr Globe 1 1/2 NNS B31.1.0 30 Motor Open for startup, Non-1E N/A HP Stop

Drain EFW Pump 2 7,146 Globe 3/4 NNS B31.1.0 N/A Manual Normally open. Non-1E N/A Turbine Stop lb/hr*

Valve Drain

  • Paths that would normally be open following a Main Steam Line Break accident.

10.3-16 Reformatted Per Amendment 02-01

FSAR FIGURE REFERENCE FIGURE 10.3-1 DRAWING D-302-011

FSAR FIGURE REFERENCE FIGURE 10.3-2 DRAWING D-302-012

FSAR FIGURE REFERENCE FIGURE 10.3-3 DRAWING D-302-014

FSAR FIGURE REFERENCE FIGURE 10.3-4 DRAWING D-302-031

10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 MAIN CONDENSER The main condenser acts as a heat sink for the 2 low pressure turbine exhausts, limiting the back pressure and thus increasing the amount of available work from the turbines.

The main condenser also serves as a collection point for main steam dump flow, low pressure heater drains, and other miscellaneous flows, as well as, being the makeup point for the secondary cycle. It deaerates and provides storage capacity for the condensate system.

The auxiliary condensers are heat sinks for their individual feed pump turbines.

Condensate from these condensers is returned to the main condenser.

10.4.1.1 Design Bases The main condenser is of the dual shell, dual pressure type (a high pressure shell and a low pressure shell). The high pressure shell is designed to operate at ~2.91 inches, HgA. The low pressure shell is designed to operate at ~2.13 inches, HgA with a design cooling water inlet temperature of 77F (circulating water temperature).

The low pressure shell features a false bottom plate which separates the low pressure condensing zone of the shell from a high pressure storage zone. The low pressure zone is connected to the high pressure zone by a downcomer. Condensate flows from the low pressure zone at a temperature of ~103.23F to the high pressure zone by gravity.

Condensate from the high pressure zone of the low pressure shell flows by gravity to the high pressure shell where it is reheated to 115.04°F by mixing with high pressure shell RN hotwell condensate. The condensate is reheated to the saturation temperature of the 98-99 high pressure shell at the design point. The condensate pumps take suction from the high pressure shell. The design temperature of condensate out of the high pressure shell is ~ 115.04°F. Normal maximum operating pressure of the main condenser is limited to approximately 5 inches, HgA, and 175°F at the turbine exhaust to any shell.

Condenser design capacities are listed in Table 10.4-1. Radioactivity concentrations in the condenser are expected to be approximately equivalent to the concentrations given in Table 11.1-5 for steam. Radioiodine concentrations in the condenser should be slightly lower because of a main condenser/air ejector partition factor of 0.15 for volatile iodine species.

Noncondensable gases are removed by the vacuum pumps described in Section 10.4.2.

Design air inleakage rates are 40 scfm for normal main condenser operation and 15 RN 98-99 scfm, total, for normal auxiliary condenser operation.

The main condenser will receive approximately 6.93 x 106 lb/hr of main steam from the Turbine Bypass System. This flow is bypassed to the condenser as required following a large load rejection, turbine trip, or other similar occurrence.

10.4-1 Reformatted April 2021

Main steam pressure is reduced to approximately 100 psig by the turbine bypass system at the condenser main steam dump inlet header. The steam is then dispersed by the main condenser through an internal spray pipe which directs the steam flow to a stainless steel baffle. This internal arrangement and the relatively low pressure (100 psig) protects the tubes and other components from impingement damage failure.

The condenser hotwell is capable of maintaining a normal water level corresponding to a retention time of at least 2 minutes (approximately 39,200 gallons).

Each condenser shell is provided with a compartmented hotwell and leak detection trays.

A tray is located inside the hotwell adjacent to the tubesheet of each waterbox. The compartmented hotwells and leak detection trays are continuously sampled to provide early detection of tube leakage. Design of the compartmented hotwells and leak detection trays permits obtaining local samples to facilitate locating of tube leaks if necessary.

The combination of good quality (lake) cooling water and stainless steel tubes reduces corrosion and erosion of condenser tubes. An Amertap cleaning system is also provided for use in maintaining condenser tube cleanliness.

10.4.1.2 System Description The main condenser is of the dual shell, dual pressure type with a rubber expansion joint in each neck. Circulating water is arranged to pass through the 2 sections in series.

Condenser leakage is monitored by installed condensate monitoring instrumentation with an associated alarm in the control room. Heaters 5A and 6A are installed in the low pressure shell; heaters 5B and 6B are installed in the high pressure shell.

During normal operation the main condenser receives the following flows:

1. Main turbine exhaust steam.

RN

2. Auxiliary condenser condensate and vents.99-020
3. Low pressure heater drains.
4. Steam and water associated with the Turbine Gland Sealing System.
5. Condensate makeup. RN 06-041
6. Auxiliary condenser air removal (Low Pressure Condenser).

10.4-2 Reformatted April 2021

Possible additional flows during startup, shutdown or under transient conditions include:

1. Condensate pump and steam packing condenser minimum flow recirculation. RN 02-022
2. Startup vents.
3. Moisture separator/reheater drains.
4. Turbine bypass flow through the Main Steam Dump System.

10.4.1.3 Safety Evaluation Disassociated hydrogen and other noncondensible gases are removed by the mechanical vacuum pumps to the atmosphere. These noncondensible gases may be routed to the Auxiliary Building Ventilation System charcoal filters if radiation levels in excess of established limits exist in the vacuum pump discharge. In the event 1 vacuum pump fails, another is available on standby. Thus, hydrogen buildup does not occur during operation of the condenser.

The influence of the main condenser on the Reactor Coolant System is reduced by the decoupling effect of the deaerator and steam generator water inventories. Therefore, control functions associated with the main condenser do not directly influence the operation of the Reactor Coolant System.

If the condenser pressure should start to rise, exhaust hood sprays are activated by a turbine exhaust hood temperature signal. Normal operation of the main condenser and its associated control functions do not affect the Reactor Coolant System. The only main condenser control function indirectly affecting the Reactor Coolant System is the loss of condenser vacuum which results in turbine trip. A turbine trip due to loss of condenser vacuum results in programmed steam dump to the atmosphere and reactor shutdown.

Provisions for protection of safety-related equipment from flooding as a result of condenser failure are discussed in Section 7.6.

10.4.1.4 Tests and Inspections The condenser is subjected to a shell side hydrostatic test in the field. The pressure is limited to the static head of water at the turbine flange.

Condenser tubes are subjected to eddy current testing to ensure leak tight operation.

The tubes are also subjected to periodic hydro cleaning to remove any scale, silt, or biological material which may inhibit heat transfer.

10.4-3 Reformatted April 2021

10.4.1.5 Instrumentation The high pressure and low pressure condenser shells are equipped with level controllers for sensing of condenser water level. These level controllers provide signals to control valves which control the supply of condensate to the condensate storage tank and normal or emergency condensate flow to the condensate system. At low-low hotwell level, these level controllers open the demineralized water makeup valve to the low pressure hotwell. Monitoring of condenser water level is accomplished through level transmitters which provide signals to level indicators on the main control board in the control room. Each condenser shell has 1 pressure switch and 1 pressure transmitter to provide tripping and interlock functions upon loss of vacuum. If either of the pressure switches sense loss of vacuum, the turbine generator is tripped. The pressure transmitters operate bistables which interlock the turbine bypass system to prevent steam dump to the condenser upon loss of vacuum (see Section 10.4.4). Condenser vacuum is indicated and low vacuum is alarmed in the control room.

Condenser instrumentation is shown schematically on Figures 10.4-8 and 10.4-9.

10.4.2 CONDENSER AIR REMOVAL SYSTEM The Condenser Air Removal System maintains main and auxiliary condenser vacuum by removing noncondensible gases, including dissociated hydrogen and oxygen from the main and auxiliary condensers.

10.4.2.1 Design Bases The non-nuclear safety class Condenser Air Removal System is designed to establish main and auxiliary condenser vacuum during plant startup and to maintain vacuum during normal operation. Mechanical vacuum pumps remove noncondensible gases from the main condensers and the auxiliary condensers via the main condensers. Under RN 98-098 normal conditions, discharge is through the Auxiliary Building Ventilation System charcoal filters. Provision is made for discharge of the noncondensibles to atmosphere.

Mechanical vacuum pumps are designed for the capacities listed in Table 10.4-1 in RN accordance with Heat Exchange Institute Standards[4]. Piping and valves are designed 01-017 in accordance with ANSI B31.1[1] and B16.5[2], respectively.

10.4.2.2 System Description Two (2) subsystems comprise the condenser air removal system: the main condenser air removal subsystem and the Auxiliary Condenser Air Removal Subsystem. Figure 10.4-1 provides the system diagram.

Each of the 2 main condenser shells is evacuated by an individual, 100% capacity, mechanical vacuum pump. A third pump is provided for backup. These pumps are used both to establish vacuum during plant startup (hogging) and to maintain vacuum during operation (holding).

10.4-4 Reformatted April 2021

The auxiliary condensers are piped to and normally aligned to the LP main condenser shell to maintain vacuum. Additionally, there are 2 mechanical vacuum pumps provided as back up for the auxiliary condensers. One (1) mechanical vacuum pump can be used to maintain vacuum in the three auxiliary condensers. A second pump is provided for backup.

All vacuum pumps can be operated during startup to speed the hogging operation.

Cooling water for the mechanical vacuum pumps is supplied from the Turbine Building RN 98-098 Closed Cycle Cooling System. Seal water is provided by the condensate system.

Both subsystems discharge through the Auxiliary Building Ventilation System charcoal filters through a common line under normal conditions. Condenser discharge radiation monitor, RM-A9, is set to provide an alarm at approximately twice normal operating RN background. The high alarm is also normally set at approximately 2 times background.02-057 Provision is made for obtaining local samples for analysis and evaluation.

10.4.2.3 Safety Evaluation The Condenser Air Removal System is not required to operate under emergency conditions nor is it necessary to achieve safe plant shutdown. Each subsystem is provided with a backup mechanical vacuum pump. Thus failure of an operating pump is not detrimental to continued plant operation.

Under normal conditions, the Condenser Air Removal System has no effect upon the Reactor Coolant System and radioactive leakage is negligible. However, should primary to secondary reactor coolant leakage occur, the flowpath through the Auxiliary Building charcoal filters limits the release of radioactivity to the environment. Anticipated release rates during normal operation are presented in Section 11.3.6.

10.4.2.4 Tests and Inspections The Condenser Air Removal System is operated continuously during normal plant operation. Therefore, periodic testing is not required. System operation is verified prior to initial plant startup by preoperational and startup testing. During subsequent plant startups, system operation is verified by observation during hogging operations. System components are readily accessible for visual inspection under normal plant conditions.

10.4.2.5 Instrumentation

1. Main Condenser Air Removal Local pressure and air flow indication is provided to monitor vacuum pump RN 96-044 performance. Lube oil pressure and discharge air temperature switches are provided for startup and shutdown interlocks. Alarms are sounded in the control room to alert the operator to vacuum pump trip, vacuum pump lube oil pump trip, low oil pressure, high off gas air temperature, and high off gas radiation.

10.4-5 Reformatted April 2021

2. Auxiliary Condenser Air Removal RN Local pressure and air flow indication is provided to monitor vacuum pump 98-098 performance. Lube oil pressure and discharge air temperature switches are provided for startup and shutdown interlocks. Alarms are sounded in the Control Room to alert the operator to vacuum pump trip and high lube oil temperature.

10.4.3 TURBINE GLAND SEALING SYSTEM 10.4.3.1 Design Bases Main turbine and feedwater pump turbine shaft seals are of the injection/labyrinth/leakoff type. These seals are designed to prevent air leakage into and/or steam leakage out of the turbine casings.

The Turbine Gland Sealing System is not safety-related. Piping and valves associated with the system are designed in accordance with ANSI B.31.1[1] and ANSI B16.5[2],

respectively.

10.4.3.2 System Description Sealing steam is normally supplied to the Turbine Gland Sealing System from the Main Steam Supply System under all load conditions. Steam for turbine gland sealing may be provided by the auxiliary boiler through the Auxiliary Steam System. The sealing steam passes inward through the seals toward the turbines to a leakoff which is piped to the condenser. Gland sealing steam also passes though the seal toward the outside where it enters the vent annulus. The vent annulus is maintained at a slight vacuum by the RN steam packing condenser.02-022 A small amount of air is drawn into the vent annulus and this air, together with the RN sealing steam, goes to the steam packing condenser. In the steam packing exhauster,02-022 the steam is condensed and the remaining saturated air is discharged to the atmosphere by a motor driven blower.

The turbine gland seal exhaust blower is part of the steam packing exhauster which is located in the Turbine Building at elevation 439. Saturated air from this blower is discharged through a 12 inch pipe to the turbine building roof near the Intermediate Building wall. The saturated air is discharged to atmosphere approximately 8 feet above the roof (elevation 522).

This discharge is not monitored for radiation. Radiation monitor RM-A9, which monitors the Main Condenser Air Removal System discharge, actuates an alarm in the event of primary to secondary leakage.

The LP turbine seals operate against vacuum at all times.

Pressure in the steam seal header is automatically controlled by steam seal regulating valves.

10.4-6 Reformatted April 2021

10.4.3.3 Safety Evaluation As long as a steam generator tube leak does not occur, the steam supplied to the Turbine Gland Sealing System is nonradioactive. A steam generator tube leak may result in small amounts of radioactive process steam leakage from the steam packing RN condenser. Such steam generator tube leakage would be detected by the Steam 02-022 Generator Blowdown System radiation monitor (RM-L3) or the condenser exhaust radiation monitor (RM-A9). See Sections 10.4.8 and 11.4.

Suitable manual regulator bypass valves are provided for use under emergency conditions. Relief valves are included to protect the system from over pressurization.

10.4.3.4 Tests and Inspections No special tests or inspections are required.

10.4.3.5 Instrumentation Steam seal header pressure is automatically controlled by a steam seal feed valve and a steam packing unloading valve. Controls for system operation, such as pressure indicators, switches, transmitters, and controllers are mounted on a local panel and the main control board. Additionally, a local level alarm switch and temperature indicator are provided.

10.4.4 TURBINE BYPASS SYSTEM 10.4.4.1 Design Bases The Turbine Bypass System is capable of bypassing main steam to the main condenser and/or to the atmosphere. This provides an artificial steam load for the steam generators so that differences between reactor output and turbine generator load can be absorbed without imposing undesirable transients upon the nuclear steam supply system.

System design permits the accommodation of large load reductions without reactor trip during most times in core life. The system also permits a gradual, orderly cooldown of the reactor to the point where the Residual Heat Removal System can assume the cooling function. The Turbine Bypass System is designed to operate in conjunction with the turbine generator, when available, or without the turbine generator if required. When including the power relief valves, it has sufficient capacity to pass ~ 93.6% of main steam flow at full load temperature and pressure. Capacities of individual valves in the Turbine Bypass System are presented in Section 10.4.4.2. The capacity of any 1 valve in the system does not exceed 970,000 lb/hr at 1,200 psia when fully open.

10.4-7 Reformatted April 2021

The Turbine Bypass System was originally designed to accommodate a full load rejection, defined as a reduction from 100% of rated turbine generator load to plant auxiliary load without a reactor trip. The transition to 18 months cycles, to less negative moderator temperature coefficients at the beginning of the fuel cycle, and to a full power Tavg operating window of 572F to 587.4F has, however, reduced this capability. Best estimate analyses indicated that a full load rejection is possible at all times in core life when operating with a full power Tavg of 587.4F. However, at a full power Tavg of 572F, full load rejection capability is feasible only for times in core burnup when the full power moderator temperature coefficient that is more negative than -18pcm/F.

Therefore, full load rejection capability cannot be guaranteed for all values of full power Tavg and for all time in core life. Generally, margin to trip improves with core burnup due to the more negative moderator temperature coefficient.

Step load changes of up to 10% can be accommodated by the reactor control system in RN 01-007 automatic mode without a reactor trip or actuation of the turbine bypass system.

System valves, piping and related equipment are designed and fabricated to satisfy the requirements of the following codes and standards and are non-nuclear safety class, non-Seismic Category 1, except as noted below:

1. Power relief valves are designed and fabricated to satisfy the ASME Code,Section III, Class 2[5], and are classified Safety Class 2a, Seismic Category 1. RN 01-017
2. Atmospheric and condenser dump valves are designed and fabricated to satisfy RN ANSI B16.5[2].01-017
3. Vent diffusers are designed and fabricated to satisfy the ASME Code, RN 01-017 Section VIII[6].

RN

4. Inline diffusers are designed and fabricated to satisfy ANSI B31.1[1].01-017
5. Piping is designed and fabricated to satisfy ANSI B31.1[1] and associated standards RN 01-017 for fittings, flanges, etc.

Additionally, the Turbine Bypass System is designed to satisfy Occupational Safety and Health Act (OSHA) requirements concerning noise levels during operation.

10.4.4.2 System Description The Turbine Bypass System is shown schematically by Figure 10.3-1. The system is comprised of the following components:

10.4-8 Reformatted April 2021

1. Condenser Dump Valve/Diffuser Combinations Eight condenser dump valved/diffuser combinations are provided and described in Table 10.3-2. The valve/diffuser combinations have an average rated/calculated capacity of ~ 6.74% of the main steam flow at full load pressure and temperature, thereby providing a bypass capacity to the condenser of ~ 53.95% of rated main steam flow. Each valve is provided with an inline diffuser mounted downstream of the valve. This combination produces reduced noise levels compared to levels generated by a valve without the diffusers. The system configuration separates the valve and diffuser, permitting location of the valve to allow easy access for maintenance. The diffusers are mounted in pairs in large, straight headers leading directly to the main condenser. Thus, problems associated with routing large diameter, hot piping are minimized.
2. Atmospheric Dump Valve/Diffuser Combinations Three atmospheric dump valve/diffuser combinations are provided and described in Table 10.3-2. The valve/diffuser combinations have an average rated/calculated capacity of ~ 6.95% of the main steam flow at full load pressure and temperature, thereby providing a bypass capacity to the atmosphere of ~ 20.85% of rated main steam flow. Each valve is provided with a diffuser mounted downstream of the valve. The system configuration separates the valve and diffuser, permitting location of the valve to allow easy access for maintenance. The diffusers are mounted on the intermediate building roof and discharge directly to the atmosphere.
3. Power Relief Valve/Diffuser Combinations Three power relief valve/diffuser combinations are provided. The power relief valves are similar to the atmospheric dump valves previously described, except for the design codes applied. The valve/diffuser combinations have an average rated capacity of ~ 6.25% of the main steam flow at full load pressure and temperature, thereby providing a bypass capacity to the atmosphere of ~ 18.76% of rated main steam flow. These valves serve a dual purpose. They operate in conjunction with the atmospheric dump valves to provide additional steam dump capacity to the atmosphere and they also serve as power operated relief valves for the steam generator secondary side.

The power relief valves are Safety Class 2a and are located outside the Reactor Building, upstream of the main steam isolation valves in Safety Class 2a main steam piping. Piping downstream of the power relief valves, between the valves and diffusers is non-nuclear safety class.

10.4-9 Reformatted April 2021

Operability testing of the valves was performed in accordance with the recommendations RN 01-017 of Regulatory Guide 1.48 [11] as discussed in Appendix 3A. Electrical components (solenoid valves and position indicator limit switches) mounted on the valves are RN qualified to satisfy IEEE-382-1972.[10] 01-017

4. Piping and Other Valves System piping is provided to convey the steam to the condenser and to the Intermediate Building roof, where it may be discharged to the atmosphere. Manual isolation valves are provided for all control valves in the system to permit maintenance without shutting down.

Turbine Bypass System control functions and control interactions with other plant controls and systems are discussed in detail in Section 7.7.1. A detailed analysis of system design adequacy is presented in Section 7.7.2.

10.4.4.3 Safety Evaluation The Turbine Bypass System is not required for plant control following an accident and is not a safety related system. Failure of any single control valve to a wide open position results in uncontrolled secondary side blowdown that is within limits compatible with maintenance of reactor fuel integrity and integrity of the reactor internals.

The capacity of the power relief valves is in addition to that required by the ASME Code,Section III [5] for overpressure protection of the steam generators. Steam generator RN 01-017 overpressure protection is provided by the main steam safety valves, discussed in Section 10.3.

Failure of the Turbine Bypass System to operate does not preclude operation of any essential systems since this system does not interface with any essential systems.

Postulated failure of Turbine Bypass System high energy piping will not adversely affect or preclude operation of any safety- related systems or components located close to the Turbine Bypass System. Postulated pipe rupture of high energy lines in the Turbine Bypass System is analyzed as discussed in Section 3.6.

10.4.4.4 Tests and Inspections The Turbine Bypass System is tested prior to commercial operation. Proper system response to simulated temperature and pressure inputs is verified during preoperational testing. During hot functional testing, each valve is stroked open and closed to verify operation. After entering service, periodic testing is performed to assure availability.

The power relief valves, which are Safety Class 2a, are tested and inspected in accordance with the applicable ASME Code, prescribed under 10CFR50.55a. This RN 04-012 includes preservice and inservice inspection and test. Section 5.7 discusses a comprehensive program of compliance with the ASME Code,Section XI relative to inservice inspection.

10.4-10 Reformatted April 2021

10.4.4.5 Instrumentation Applications Instrumentation and controls specifically related to the Turbine Bypass System are shown by Figures 10.3-1, and 10.4-3 through 10.4-4b. Setpoints are listed in Table 10.4-2. They are provided to permit monitoring of system performance and to permit manual valve operation if required.

10.4.5 CIRCULATING WATER SYSTEM The Circulating Water System removes thermal energy from the main and auxiliary condensers and dissipates this energy to Monticello Reservoir.

10.4.5.1 Design Basis The principal performance requirement for the Circulating Water System is that it provide cooling water to the main and auxiliary condensers. The system is capable of pumping ~

5.34 x 105 gpm of circulating water through the plant. This provides a heat transfer RN 01-113 capability to the environment of 6.675 x 109 BTU/hr, with a nominal system temperature rise of 25F. This capability is adequate to satisfy system requirements for all normal and upset plant conditions, including turbine trip from full load. The system is not required to function under plant emergency or faulted conditions.

The following equipment is cooled by the Circulating Water System:

1. Main condenser - 2 shells.
2. Auxiliary condensers - 3 shells.
3. Circulating water motor bearing coolers are supplied only as backup cooling, RN 08-001 (Normal Cooling Water Supply is from the Filtered Water System).

Circulating water is also used to wash the traveling screens and as a backup for circulating water pump motor bearings and jockey pump bearing lubrication.

Design parameters for major system components are presented in Table 10.4-3. The design pressure and temperature requirements for piping, valves, and pressure retaining RN parts are tabulated in the lower left margin of Figure 10.4-5. The upset condition 01-113 tabulated is the shutoff head of the circulating water pumps. This condition occurs less than 1% of the time.

Circulating Water System piping and valves are designed in accordance with applicable industry codes and standards.

RN Condensers are designed in accordance with Heat Exchange Institute Standards. [4] 01-017 Pumps are designed in accordance with Hydraulic Institute Standards. [9] RN 01-017 10.4-11 Reformatted April 2021

10.4.5.2 System Description Circulating Water System water requirements are supplied by three 33-1/3% capacity vertical wet pit pumps, located in the circulating water intake structure. The discharges from these pumps are headered into a main supply line to the plant. Two (2) or three (3) RN 98-073 pumps are used during normal operation at reduced or full load.

The circulating water pumps can be controlled from the main control room or locally. Six (6) traveling water screens and two 100% capacity screen wash pumps with a strainer provide screened water to the pumps.

A circulating water jockey pump is included in the system to fill the circulating water RN 98-185 system during startup.

The main condensers are supplied with cooling water through branches from the main circulating supply line. These branches are equipped with motor operated butterfly valves and expansion joints at the condenser waterbox inlet and discharge.

The auxiliary condensers, also supplied directly from the main circulating water line, are three (3) ~ 50% capacity units equipped with motor operated butterfly valves at the inlet and with manual butterfly valves at the discharge. Expansion joints are provided at the inlet and discharge.

The main and auxiliary condenser piping is equipped with automatic tube cleaning equipment of the sponge ball type.

10.4.5.3 Safety Evaluation The Circulating Water System is independent of the emergency cooling facilities. It is not essential for safe operation and shutdown of the Nuclear Steam Supply System nor is it required to operate under accident conditions. Therefore, the system is non-nuclear safety class, non-Seismic Category 1.

A failure in the circulating water transport system inside the Turbine Building would be detected by a high water level alarm in the main condenser cleaning pit. As a result of RN effluent radiation monitor response capabilities the sump pumps located in this pit are 01-051 limited to a combined maximum capacity of 2000 gpm. A leak exceeding the capacity of these pumps would activate an alarm when the water level in the main condenser cleaning pit approached elevation 390. The main condenser cleaning pit is located within the Amertap strainer pit.

A continued rise of water into the Amertap strainer pit to elevation 400 actuates 2 groups of 3 level switches. The actuation of any 2 switches within either group trips the circulating water pumps and initiates pump discharge valve and high pressure condenser discharge valve closure. Another alarm signals tripping of the pumps and closure of the pump and condenser discharge valves.

10.4-12 Reformatted April 2021

The lowest design pressure for any component in the Main Circulating Water System is 50 psig. Design data and system data are shown on Figure 10.4-5. To reduce the RN 01-051 possibility of water hammer, slow closing, motor operated butterfly valves are used for condenser isolation.

A postulated complete failure of the condenser inlet expansion joint, which would result in an estimated flow rate of 780 ft3 /sec, would actuate the condenser cleaning pit alarm in less than 5 seconds. The rise of water to elevation 400 and resultant actuation of the alarm and pump trip would require approximately 46 seconds.

At initiation of pump trip, the pump discharge valves and high pressure condenser discharge valves begin to close. These valves require approximately 120 seconds and 90 seconds, respectively, to reach the fully closed position.

Pump coastdown time is extremely short and, for all practical purposes, is considered to be negligible.

The total time required to stop circulating water flow from the instant of failure would be approximately 2 min - 50 sec. Water levels versus time for a postulated expansion joint failure are presented in Table 10.4-3a.

A completely failed expansion joint would cause flooding of the Turbine Building basement (see Figure 1.2-16) up to elevation 413.5. No essential systems or components are located in the Turbine Building. The lowest penetration of the Control Building or Intermediate Building walls, that could cause flooding from the Turbine RN Building, is at elevation 427, considerably above the flood elevation of 413.5.01-051 The system may be operated with less than 3 circulating water pumps in operation. RN 98-073 10.4.5.4 Tests and Inspection Testing of the Circulating Water System is limited to that normally provided for non-safety related systems and includes:

1. Hot functional testing.
2. Normal, operational checking, and routine maintenance of the system.

10.4.5.5 Instrumentation System instrumentation is shown schematically on Figure 10.4-5. The following instrumentation is provided to permit operator evaluation of major equipment performance and to provide a performance record:

1. Pressure indicators, switches, and test connections.
2. Level switches.

10.4-13 Reformatted April 2021

3. Temperature indicators and test connections.

10.4.6 CONDENSATE CLEANUP SYSTEM The Condensate Cleanup System is provided to aid in maintaining feedwater and steam generator water chemistry within specifications during all modes of plant operation and as required during condenser leakage. Figure 10.4-7a schematically illustrates the system.

10.4.6.1 Design Bases

1. The system is not safety related. Failure or malfunction of any system component will not affect the ability of the plant to achieve or maintain shutdown conditions.
2. The system is designed for cleaning up to approximately half of the maximum condensate flow.
3. System effluent purity will be within the limits provided in the Condensate System Design Basis Document as follows:

RN 00-01 Total suspended solids, max. ppb 10 Sodium, max., ppb 1 Chloride. max., ppb 1

4. The system will be used when condensate polishing is required to maintain chemistry specifications.
5. Wastes from the system will be sent to the backwash receiving tank. Disposal from the tank will be dependent upon results of grab sample analysis.

10.4.6.2 System Description The purpose of the Condensate Polishing System (CPS) is to minimize the time for plant startup. During plant operation, the Steam Generator Blowdown System is in service for system cleanup. However, the CPS will be used (assuming no SG leaks) to better maintain prescribed chemistry parameters in the condensate and feedwater cycle.

The CPS consists of 3 vessels in the condensate cycle. Two (2) vessels will be in service at a time with the third as a spare. The total flow through them will be a maximum of 8822 gpm (4411 each vessel). This is approximately 1/2 of the total condensate flow needed for full load capability of the V. C. Summer Nuclear Station, Unit 1.

10.4-14 Reformatted April 2021

The condensate polishers will be placed in service during plant startup for chemical cleaning of the condensate and feedwater cycles. There is a recirculation mode that will be used as a prestart cleanup of a major portion of the condensate and feedwater systems. This prestart cleanup will recirculate water using the condensate and feedwater booster pumps to the closed feed water isolation valves and back to the hotwell.

On unit startup, the polishers can be on line via the condensate pumps until the plant RN attains approximately 50% full load capacity.06-041 During shutdown of the unit, the CPS could be placed in service when the plant load is approximately 50% if system chemistry indicates a need for cleanup.

If the condenser develops a leak, which will be detected by the Condenser Leak Detection System, the leak location will be determined and that half of the condenser will be taken out of service for repairs. At this time, the unit will be at a load of about 50%

and the condensate polishers can be placed in service to assist in removing chemical impurities introduced by the detected leak.

If a primary to secondary leak occurs, it will be detected by the steam generator leak detection system and the CPS will be isolated. It is not intended to operate the CPS if a SG leak occurs. In the event that the condensate polishers are used in the presence of a steam generator tube leak, all applicable Health Physics measures and precautions will be observed.

Depleted resins are backflushed to a backwash receiving tank from which samples will be taken and analyzed prior to release. The results of gamma isotopic analyses are then utilized via established station procedures and administrative controls to determine if a release is possible. If a release is acceptable, the normally disconnected spool piece is installed and the depleted resins are discharged to the settling pond through RML-11.

RML-11 will alarm on the local control panel and stop the backwash transfer pumps to prevent a release if its setpoint is exceeded.

If a release is not acceptable and the resin must be handled as solid radwaste, the contents of the backwash receiving tank are discharged to a DOT approved low level radwaste container. Using a preinstalled filter arrangement and the dewatering equipment shown in Figure 10.4-7a, excess water is removed from the powdex resin according to the Process Control Program for the packaging of low level radioactive waste. The resin may be dewatered to DOT requirements and shipped to a licensed low level radwaste burial facility. The dewatered resin may also be transported around to the Auxiliary Building truck bay entrance and solidified using the inplant solidification equipment.

10.4-15 Reformatted April 2021

The anticipated operational information is as follows:

1. Flow rate each vessel: condensate flow rate = 4411 gpm backwash flow = 375 gpm RN 99-031
2. Backwash frequency: 3 backwashes per 24 hr startup
3. Backwash holdup tank: 12,000 gallon capacity
4. Average backwash rate: 18 backwashes per year
5. Provisions exist for sampling condensate and resin backwash.

10.4.6.3 Safety Evaluation The Condensate Cleanup System is not safety related and is not required to ensure any of the following:

1. The integrity of the reactor coolant pressure boundary.
2. The capability to shut down the reactor and maintain it in a safety shutdown condition.
3. The ability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures in excess of established limits.

Dissolved and suspended solid impurities within the condensate and feedwater circuits are not expected to contribute to plant activity levels. Any radioactive contamination that might occur in the Main Steam/Condensate System is actually reduced during the condensate cleanup process.

Scheduled, infrequent operation of the condensate polishers minimizes the possibility of producing potentially radioactive waste.

10.4.6.4 Tests and Inspections Prior to system startup, the service vessels are hydrostatically pressure tested and flushed clean. All components and instruments are checked for operational status.

During plant operation, instruments are routinely calibrated with known standards for accurate monitoring of pH, dissolved oxygen, sodium and conductivity. Continual surveillance and prescribed inspections of system components are standard operating procedures.

10.4-16 Reformatted April 2021

To assure protection of plant personnel and the environment during suspected primary to secondary steam generator leakage the following precautions should be taken:

1. Increased radiation survey frequency in the condenser polisher area.
2. Grab sample analysis prior to backwash receiving tank discharge will be extended to include tritium and isotopic -y analysis.

10.4.6.5 Instrumentation Application Manually initiated, automatic backwash sequence controls are provided for use in replacing exhausted powdered resins. Resin trap strainers in the effluent stream have differential pressure switches to actuate alarms upon detection of high pressure drop.

An automatic bypass valve around the demineralizer system opens upon detection of excessive differential pressure. Instrumentation also indicates high differential pressure across a demineralizer vessel. The demineralizer is then manually removed from service and replaced by the standby vessel. Instrumentation is also provided to monitor effluent for sodium, pH, dissolved oxygen, and conductivity.

10.4.7 CONDENSATE AND FEEDWATER SYSTEMS 10.4.7.1 Condensate System The Condensate System pumps condensed turbine exhaust steam from the main condenser hotwell through the low pressure feedwater heaters to maintain deaerator storage tank level for anticipated operating conditions. It also serves as a source of cooling water for the steam packing condenser and the steam generator blowdown heat exchanger, and provides sealing water for various vacuum valves and the feedwater pump seals.

10.4.7.1.1 Design Bases Design conditions for system piping, valves, and pressure retaining parts are tabulated in the lower left margin of Figures 10.4-8 and 10.4-9. At the discharge of the condensate RN pumps, the upset condition bounds the discharge pressure of the condensate pumps00-091 under minimum recirculation. This condition is expected to occur less than 1% of the time.

Condensate pumps are designed in accordance with the requirements of the Hydraulic Institute Standards.[9] The original pump design point was selected to satisfy the RN 01-017 requirements of the turbine thermal cycle (at pre-uprate conditions) at the valve wide open condition, plus a wear margin.

For post-uprate operation, the design of the pumps was evaluated against predicted required flow plus an allowance for transients.

10.4-17 Reformatted April 2021

RN 06-041 Low pressure feedwater heaters, deaerator, and deaerator storage tank are designed, fabricated, inspected, tested, and stamped in accordance with the ASME Code,Section VIII, Division 1.[6] Thermal performance is governed by the Heat Exchange Institute RN 01-017 Standards [7].

The Condensate System, except for the condensate storage tank, is non-nuclear safety class. The condensate storage tank is Safety Class 2b, Seismic Category 1, since it is the primary inventory source for the Emergency Feedwater System.

The condensate storage tank is designed, fabricated, inspected, tested and stamped in RN accordance with the ASME Code,Section III.[5] During normal operation the condensate 01-017 storage tank water level is not permitted to fall below a level corresponding to a usable volume of 160,054 gallons (see section 9.2.6.1). Makeup to the condensate storage RN 98-149 tank is demineralized water, admitted through the condenser and condensate storage subsystem. See Section 9.2.6 for a description of condensate storage facilities.

Under transient conditions, the deaerator storage tank serves as an additional source of water for the Feedwater System, providing adequate net positive suction head (NPSH) for the feedwater booster pumps.

System piping and valves are designed in accordance with ANSI B31.1[1] and ANSI B16.5[2], respectively.

Design parameters of major components in the Condensate System are listed on Table 10.4-4.

10.4.7.1.2 System Description The Condensate System contains three (3) 50% capacity motor driven condensate pumps, a 50% capacity powdered resin filter/demineralizer cleanup system (see Section 10.4.6), 3 stages of closed low pressure feedwater heaters, associated piping, valves, and instrumentation. The 2 lowest stages of feedwater heaters are located in the condenser neck.

Equipment interfacing with, but not part of, the Condensate System includes the steam packing condenser and steam generator blowdown heat exchangers.

Condensate is pumped from the hotwell storage area, located below the main high pressure condenser, by 2 normally operating condensate pumps through the steam packing condenser. The condenser then passes through two 50% capacity, parallel strings of low pressure heaters to the deaerator and deaerator storage tank.

10.4-18 Reformatted April 2021

Condensate pumps are of the 4 stage, vertical can, centrifugal type, and are electric motor-driven. Condensate flow is controlled by the deaerator level control valves which follow the difference between feedwater and condensate flow, trimmed by deaerator level. The pumps are protected from a low flow condition by individual recirculation valves back to the main condenser.

RN 06-041 The steam packing condenser is a shell and U-tube type heat exchanger. Condensate passes through the tube side. A manual bypass is provided for maintenance.

Low pressure feedwater heaters are shell and U-tube heat exchangers with 2 heating zones: A condensing zone and an integral drain cooling zone. The three (3) 50%

capacity feedwater heaters in each string are bypassed and isolated as a group when necessary. A bypass line is provided for use when 1 heater string is out of service.

Turbine load must be adjusted according to the manufacturers instructions when a feedwater heater string is isolated.

The deaerator is of the horizontal, direct contact, tray type. The preheated condensate drops onto the stainless steel trays where it is scrubbed by rising steam. Condensate then passes from the trays to the deaerator storage tank which has a capacity of 75,000 gallons.

Condensate is also supplied to the suction of the exhaust hood spray pumps. These pumps provide hood spray, gland sealing for various valves in vacuum service and seal water for vacuum pumps and feedwater pump seals. A small amount of condensate is used as the coolant for the steam generator blowdown heat exchangers.

10.4.7.1.3 Safety Evaluation Three (3) 50% capacity condensate pumps are provided. Two (2) of these pumps are normally operated. The third is in standby. Upon the trip of an operating pump, which is RN 01-049 annunciated in the control room, the standby pump is started by the operator. No detrimental effect upon the Reactor Coolant System is realized.

System makeup is provided directly from the condensate storage tank to the low pressure condenser shell. Makeup to the condensate storage tank is accomplished by injection of demineralized water to the low pressure condenser shell and thence through the Condensate System to the condensate storage tank.

10.4-19 Reformatted April 2021

Sentinel type, tube side relief valves are provided for all closed feedwater heaters. A feedwater heater tube rupture causes high level alarms in the Control Room and initiates automatic valve operation where appropriate. A high-high level alarm on condenser neck heaters initiates turbine trip if the condition exists more than 10 seconds.

Pressure, temperature, or flow deviations due to a malfunction in the Condensate RN 01-049 System is not immediately felt by the Reactor Coolant System due to the capacity of the deaerator storage tank and the Feedwater System. The deaerator storage tank allows corrective action, an orderly runback to a compatible load, or shutdown. RN 01-049 10.4.7.1.4 Tests and Inspections Tests of the Condensate System are limited to that normally provided for non-safety related systems and includes:

RN

1. Hot functional testing. (Historical)98-098
2. Normal, operational checking and routine maintenance of the system.

The closed, low pressure feedwater heaters were subjected to both shell and tube side RN hydrostatic tests at 150% of the respective design pressures. The shell sides were also 01-041 tested for vacuum. Alterations to the shells to obtain higher maximum allowable working pressures call for leak tests at system operating conditions.

10.4.7.1.5 Instrumentation Applications Instrumentation provided for the Condensate System is shown on Figures 10.4-8 and 10.4-11. This instrumentation is provided to permit operator evaluation of major equipment performance and to provide a record of equipment performance.

Instrumentation includes the following:

1. Pressure indicators, switches, and test connections.
2. Flow indicators, recorders, switches and test connections.
3. Level indicators, recorders, controllers and switches.
4. Temperature indicators, controllers, switches and test connections.

10.4.7.2 Feedwater System The Feedwater System is designed to pump feedwater from the deaerator storage tank through 2 stages of high pressure heaters to the steam generators. Thus, heated, deaerated water required to maintain steam generator water level is provided during normal operation, after startup, and before shutdown.

10.4-20 Reformatted April 2021

10.4.7.2.1 Design Bases Design conditions for system piping, valves, and pressure retaining parts are tabulated in the lower left margin of Figures 10.4-10 through 10.4-12. RN 01-017 Feedwater System piping and valve components from and including the feedwater check RN valves to the steam generators are Safety Class 2a, Seismic Category 1 and are in 98-098 accordance with ASME Code,Section III [5], Class 2 requirements. System components upstream of the feedwater check valves in the Intermediate Building, excluding branch lines 2 inches and less, are Quality Related safety class (QR), Seismic Category 1 and RN 01-059 satisfy ASME Code,Section III [5], Code Class 2 requirements; however, are not code stamped. This piping is identified as Note 1 piping on Figure 10.4-12. Feedwater piping in the Turbine Building is designed in accordance with ANSI B31.1 [1]; valves conform to ANSI B16.5. [2]

The feedwater booster pumps and feedwater pumps are designed in accordance with RN the requirements of the Hydraulic Institute Standards.[9] Original design points for these 01-017 pumps were selected to satisfy the requirements of the turbine thermal cycle. At the "valve wide open" condition (pre-uprate power), plus a wear margin.

High pressure feedwater heaters are designed, fabricated, inspected, tested, and RN stamped in accordance with the ASME Code,Section VIII, Division 1.[6] Thermal 01-017 performance of these feedwater heaters is governed by Heat Exchange Institute Standards.[7] RN 01-017 At less than approximately 3% plant load, the Emergency Feedwater System (see Section 10.4.9) is used to maintain steam generator water level. The Main Feedwater System is designed to overlap the Emergency Feedwater System down to the no load conditions but the Emergency Feedwater System is normally used for conditions such as startup and shutdown.

RN 00-008 10.4-21 Reformatted April 2021

10.4.7.2.2 System Description The Feedwater System is divided into nuclear safety class and non-nuclear safety class portions. The nuclear safety class portion, downstream of and including the containment isolation valves, is schematically shown on Figure 10.4-12. Feedwater System parameters are listed on Table 10.4-5.

The non-nuclear safety class portion of the Feedwater System includes four 33-1/3%

capacity, constant speed, motor driven, feedwater booster pumps; three 50% capacity, variable speed, turbine driven, feedwater pumps; 2 stages of high pressure heaters; valves, instrumentation, controls; and associated piping. The feedwater booster pumps take suction from the deaerator storage tank and discharge to the feedwater pump suction. The feedwater pumps discharge through 2 strings of high pressure heaters into a single 30 inch diameter header which distributes the feedwater to 3 feedwater flow control valves and/or 3 feedwater bypass control valves. A recirculation line runs from the termination of the 30 inch diameter header near the feedwater flow control valves to the deaerator. This line is equipped with block valves and a pressure breakdown orifice RN and is used during startup to permit warming of the Feedwater system to and including 06-006 the 30 inch diameter header.

Feedwater flows from the feedwater flow control valves through individual lines and the feedwater isolation valves to the three steam generators.

The feedwater booster pumps are horizontal, split case, single stage and centrifugal pumps. They are motor driven at a constant speed of 1780 rpm. Minimum recirculation flow is bypassed to the deaerator storage tank, as required. Normally, 2 feedwater booster pumps operate at low load; three or four at intermediate or full load. Feedwater booster pumps provide the necessary flow and suction pressure for the feedwater pumps.

Steam is supplied to the deaerator storage tank through a sparger during initial stages of Feedwater System warmup. This is followed by admission of pegging steam to the deaerator to complete Feedwater System warmup.

The feedwater pumps are horizontal, split case, single stage, double suction, and diffuser pumps. The speed of the variable speed turbine drive is varied and the feedwater flow control valves adjusted to maintain water levels in each steam generator.

In general, 2 feedwater pumps are operated at low or intermediate loads. Three (3) feedwater pumps are operated at full load. Feedwater pumps are protected by minimum flow, recirculation lines to the deaerator storage tank.

High pressure feedwater heaters are shell and U-tube type heat exchangers with 2 heating zones: a condensing zone and an integral drain cooling zone. The two 50%

capacity feedwater heaters in each string are manually bypassed and isolated as a group to remove the string from service if necessary. Turbine load must be adjusted according to the manufacturers instructions when a feedwater heater string is isolated.

10.4-22 Reformatted April 2021

10.4.7.2.3 Safety Evaluation

1. General If it becomes necessary to remove a feedwater booster pump or feedwater pump from service due to malfunction or failure or for maintenance, plant loads are reduced in accordance with a predetermined operating scheme. When the normal operating schemes are followed, the Feedwater System provides satisfactory service under plant operating conditions.

Reactor runback is minimized and reactor trip is avoided following loss of any 1 feedwater or feedwater booster pump from the normal operating scheme. It is possible to operate the Feedwater System beyond the normal operating scheme for short periods of time. Following the loss of any 1 operating feedwater booster pump or feedwater pumps, a power reduction may be necessary to prevent reactor trip due to low water level in the steam generators. Reactor trip is prevented when maximum pumping scheme capability satisfies or exceeds feedwater flow requirements at the time a pump is lost from service. The feedwater pumps and drive turbines may be operated at runout capacity temporarily, but extended off-design point operating results in drive turbine efficiency loss. The feedwater booster pumps may be operated up to their horsepower limits for extended periods of time without detrimental effects.

If a feedwater piping break should occur in the Intermediate Building, alarm and control devices act to prevent flooding of safety-related equipment on the floors.

Section 7.6 outlines the details of provisions for leak detection. Pipe break is discussed in Sections 3.6 and 15.4.2. As noted in Section 10.4.7.2.1, feedwater piping in the Intermediate Building, excluding branch lines, satisfies the requirements, except for stamping, of the ASME Code,Section III [5], Code Class 2, RN to provide greater assurance of piping system integrity and to minimize the potential 01-017 for postulated pipe rupture.

The feedwater isolation valves are designed to close within 5 seconds after receipt of a closure signal to provide containment isolation in the event of a feedwater line break either inside or outside the Reactor Building. These valves have relief valves RN installed to prevent pressure locking due to thermal expansion of fluid trapped 18-042 between the double-disc gate following closure. These valves are designed with safety related air accumulators and fail as is upon loss of control air and to close RN 09-013 upon loss of channel A electric power. Valve status is indicated by lights on the main control board and is monitored by the plant computer. Any of the following signals initiate closure:

a. Feedwater isolation signal (channel A only, see Table 6.2-54 signal D for initiating conditions).
b. High-high Intermediate Building sump level switches energized (see Section 7.6 for initiating conditions, channel A only).

RN 00-082 10.4-23 Reformatted April 2021

c. Intentionally left blank by RN 00-082 in Amendment 02-01.

RN

d. Intentionally left blank by Amendment 96-03.96-017
e. Intentionally left blank by RN 00-082 in Amendment 02-01. RN 00-082
f. Manual switch train A in the control room. RN 09-013 The recommendations of the NSSS vendor are followed in routing of feedwater piping to minimize flow instabilities in the Feedwater System.

Standard industry safety precautions are observed in the handling of feedwater chemicals.

Table 10.4-6 presents a Feedwater System failure analysis. 02-01 10.4.7.2.4 Tests and Inspections

1. Operability Test for Containment Isolation Valves The containment isolation valves are subjected to periodic operability tests in RN accordance with the applicable ASME Code, prescribed under 10CFR50.55a.04-012 There are 3 containment isolation valves in this system: three (3) on the main feedwater line. These valves are tested for operability by complete closure and opening during plant shutdown.
2. System Tests Major equipment is periodically inspected to ensure proper conditions and operation. Additional testing includes:
a. Hydrostatic testing of safety class system piping and equipment following construction and prior to placing the system in service.
b. Hot functional testing subsequent to cold hydrostatic testing.
c. Normal, operational checking, and routine maintenance of the system.

RN 00-008 10.4-24 Reformatted April 2021

Inservice inspection of safety class portions of the system is performed in accordance with the ASME Code, Section XI[8], requirements.

10.4.7.2.5 Instrumentation Applications Instrumentation for the Feedwater System is shown schematically by Figures 10.4-10 through 10.4-12. The following instrumentation is supplied for the non-nuclear safety class portion of the system to permit operator evaluation of major equipment performance and to provide a performance record:

1. Pressure indicators, switches, and test connections.
2. Flow indicators, controllers, and test connections.
3. Level switches.
4. Temperature indicators and test connections.

In the nuclear safety class portion of the system, instrumentation to permit monitoring of the temperature of feedwater entering the steam generators is provided. Instrumentation associated with the development of control signals for the containment isolation valves is provided in Section 7.3 and Table 6.2-54.

10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4.8.1 Design Bases 10.4.8.1.1 General The Steam Generator Blowdown System continuously purges the steam generators of concentrated impurities, thereby maintaining secondary side steam generator water chemistry. The Nuclear Blowdown Processing System is used to process cooled steam generator blowdown fluid and return decontaminated water to the secondary cycle. The steam generator wet layup system skid provides forced circulation of the steam generator secondary side water inventory during cold shutdown conditions.

Steam generator blowdown fluid can be directed to any 1 of the following:

1. Nuclear Blowdown Processing System.
2. Circulating water discharge.
3. Alum sludge lagoon.

10.4-25 Reformatted April 2021

Steam generator blowdown fluid is normally directed to the Nuclear Blowdown Processing System or the circulating water discharge. During plant startup, steam generator blowdown fluid may be directed to the alum sludge lagoon for reduction of suspended solids content prior to discharge. Radiation monitoring controls divert steam generator blowdown fluid to the Nuclear Blowdown Processing System upon detection of radioactivity in the fluid, thus limiting release of radioactivity to the environment.

The ATWS (Anticipated Transient Without Scram) Mitigation System Actuation Circuitry (AMSAC) isolates steam generator blowdown when 2 of 3 steam generators are at 98-01 low-low level.

During cold shutdown and refueling, the steam generator wet layup system skid may be attached between the blowdown and Emergency Feedwater Systems. The skid circulates water through the steam generators to provide improved mixing and less severe concentration gradients to mitigate steam generator fouling and corrosion.

10.4.8.1.2 Thermal Blowdown fluid from each steam generator is directed to a separate heat exchanger for heat recovery. A portion of the condensate flow serves as the cooling fluid in these heat exchangers. The heat exchangers are designed to cool the steam generator blowdown fluid to 120°F.

10.4.8.1.3 Secondary Side Contaminants Impurities associated with the secondary cycle include:

1. Dissolved amines and an oxygen scavenger, introduced for control of feedwater pH and oxygen.
2. Ammonium chloride for molar ration control if required.

RN 95-040

3. Boric acid for mitigation of steam generator tube denting if required.
4. Impurities associated with condenser leakage.
5. Ingress from the demineralized water system and/or the water treatment plant.

10.4.8.1.4 Primary Side Contaminants Impurities associated with the Reactor Coolant System may enter the steam generator secondary side should steam generator tube leakage occur. Such impurities include radioactive and nonradioactive particulate and dissolved material.

10.4-26 Reformatted April 2021

10.4.8.1.5 Operating Parameters

1. Total Blowdown Flow
a. Minimum flow - 30 gpm.
b. Normal flow - as required to maintain secondary side water chemistry.
c. Design flow - 1.0% of main steam flow (nominally 250 gpm).
d. Cold shutdown on steam generator wet layup system - 100 gpm (nominal RN 95-040 flow).
2. Water Chemistry of Steam Generator Blowdown Fluid Blowdown flow from each steam generator aids in maintaining secondary side water chemistry specifications. The controlling parameters include pH, cation RN 95-040 conductivity, sodium, chloride and sulfate.
3. Steam Generator Tube Leakage For purposes of radioactive release determinations, a primary to secondary leakage rate of 100 lb/day and 0.12% failed fuel is used. The leakage rate is derived from NUREG-0017[3].

For the design of equipment, a primary to secondary leakage rate of 0.1 gpm (1195 lb/day) under standard conditions is assumed. Major contaminants considered include boron and lithium with primary coolant concentrations of 1000 ppm and 2 ppm, respectively.

10.4.8.1.6 Codes and Standards The Steam Generator Blowdown System is non-nuclear safety class and quality related class, except for that portion inside the Reactor Building and up to the containment RN isolation valve which is Safety Class 2a, Seismic Category 1. Safety class and quality 04-026 related class piping is designed in accordance with the ASME Code,Section III [5], Class

2. Non-nuclear safety class piping is designed in accordance with ANSI B31.1[1].

Equipment classification is presented in Table 3.2-1.

10.4.8.2 System Description The Steam Generator Blowdown System is illustrated by Figure 10.4-13. Individually regulated blowdown from each steam generator is cooled and reduced in pressure prior to combination with other blowdown streams. The total blowdown is then processed through the Nuclear Blowdown Processing System or is routed into the circulating water discharge and thence to Monticello Reservoir.

10.4-27 Reformatted April 2021

The Nuclear Blowdown Processing System is illustrated by Figures 10.4-14 and 10.4-15.

Should blowdown activity exceed preset levels, the blowdown flow is automatically diverted to the nuclear blowdown holdup tank. One (1) of 2 nuclear blowdown holdup tank pumps then takes suction from the holdup tank and delivers the fluid through a filter, 2 demineralizers in series, and a post filter from which it returns to the secondary cycle through the main condenser (an alternate path being to the penstocks of the Fairfield Pumped Storage Facility [see Figure 10.4-17] during operation of that facility in the generation mode).

The Nuclear Blowdown Processing System includes a sluicing pump and spent resin storage tank for transfer and storage of exhausted demineralizer resin. Processing of solid waste is accomplished by the Solid Waste Disposal System (see Section 11.5).

10.4.8.2.1 Component Description The general arrangement of system equipment is shown by Figures 1.2-5 and 1.2-6.

Design parameters for major components are presented in Table 10.4-7. Major components of the Steam Generator Blowdown System include:

1. Radiation Monitors Radiation monitoring equipment is located to sample continuously the total Steam Generator Blowdown and Nuclear Blowdown Processing System demineralizer effluent. Section 11.4 describes radiation monitoring equipment in detail.
2. Steam Generator Blowdown System Heat Exchangers Each of the 3 Steam Generator Blowdown System heat exchangers consist of 2 shell and tube vessels in series, designed to cool the steam generator blowdown fluid with condensate.
3. Nuclear Blowdown Holdup Tank The nuclear blowdown holdup tank retains potentially radioactive steam generator RN blowdown fluid for processing.98-081
4. Nuclear Blowdown Monitor Tank The nuclear blowdown monitor tank is similar in design to the nuclear blowdown holdup tank. This tank provides additional holdup capacity, if required, as well as the capability for periodic effluent sampling.
5. Nuclear Blowdown Holdup Tank Pumps Two (2) 100% capacity, centrifugal, nuclear blowdown holdup tank pumps are provided. These pumps take suction from the nuclear blowdown holdup tank and discharge through the filter, demineralizers, and post filter.

10.4-28 Reformatted April 2021

6. Nuclear Blowdown Monitor Tank Pump A single, canned motor pump is provided. This pump takes suction from the nuclear blowdown monitor tank and discharges to the nuclear blowdown holdup tank or recirculates the monitor tank contents through the post filter.
7. Nuclear Blowdown Demineralizer Inlet Filter This inlet filter removes particulate matter from the holdup tank fluid upstream of the demineralizers, thus protecting against resin fouling and premature capacity loss.

The filter is a disposable cartridge type. Pressure drop indication and an alarm are provided to alert the operator that filter media replacement is required. Since the filter is potentially radioactive, shielding is provided for personnel protection.

Radiological controls to reduce personnel exposure are implemented during spent filter cartridge removal and transportation to the drumming station.

8. Nuclear Blowdown Demineralizer Discharge Filter This post filter traps and retains degraded or crushed resin particles which may pass through the demineralizers during normal operation. Design of this filter and radiation protection considerations are similar to those for the nuclear blowdown inlet filter.
9. Nuclear Blowdown Sluice Filter The sluice filter is located on the discharge side of the resin sluice pump. Its function is similar to that described for the nuclear blowdown demineralizer discharge filter.
10. Nuclear Blowdown Demineralizers Four (4) ion exchange vessels, arranged for 2 step demineralization with 100%

standby capacity, are provided. This arrangement assures the capability for continuous removal of radionuclides as well as high effluent purity. Operation of each demineralizer is on a nonregenerable basis. Resin is removed and replaced as dictated by chemical analysis or radioactivity measurements.

11. Nuclear Blowdown Spent Resin Storage Tank The nuclear blowdown spent resin storage tank is provided to permit recycling of resin sluice water, storage of spent demineralizer resin, and transfer of spent resin to the drumming station.
12. Nuclear Blowdown Resin Sluice Pump The nuclear blowdown resin sluice pump is used to loosen resin in and transfer resin from nuclear blowdown demineralizers.

10.4-29 Reformatted April 2021

13. Steam Generator Wet Layup System Skid The Steam Generator Wet Layup System Skid consists of a pump, two 100% filters in parallel, valves, connectors, flexible hoses, and a skid-mounted motor control center. When used, during cold shutdown conditions, the pump suction is connected by flexible hose to the blowdown system and the discharge is similarly connected to the Emergency Feedwater System.

10.4.8.2.2 System Operation System operations are divided into three categories, as follows:

1. Normal Operation During normal plant operation, steam generator blowdown is continuous to maintain secondary side steam generator water chemistry within the limits recommended by the Nuclear Steam Supply System (NSSS) vendor. Blowdown is normally directed to the Nuclear Blowdown Processing System or to the circulating water discharge after passing through the steam generator blowdown heat exchangers.

The combined blowdown from the 3 steam generators is continuously sampled and analyzed for radioactivity. Should the activity level reach a pre-established setpoint, the discharge paths are automatically isolated and the total blowdown flow is automatically diverted to the nuclear blowdown holdup tank.

Low specific activity effluent resulting predominately from continuous steam generator blowdown sampling may be processed from the nuclear blowdown holdup tank to the main condenser or Turbine Building sump. When high radiation setpoint is reached for RM-L3 or RM-L10 and steam generator blowdown has been diverted to the holdup tank, the process pathway to the Turbine Building sump is terminated. The contents of the nuclear blowdown holdup tank are periodically analyzed for radioactivity and chemical contamination.

10.4-30 Reformatted April 2021

2. Special or Infrequent Operation As discussed in 1, above, blowdown radioactivity levels in excess of a pre-established setpoint (as sensed by RM-L3 and RM-L10) result in automatic diversion of blowdown flow to the nuclear blowdown holdup tank. Under such conditions, samples from each steam generator blowdown stream are analyzed to determine the source of the radioactivity. Once the source has been determined, the blowdown from the affected steam generator may be processed separately while blowdown from the remaining steam generators may continue to be discharged. If the faulty steam generator cannot be satisfactorily isolated, total blowdown flow continues to be directed to the nuclear blowdown holdup tank.

A nuclear blowdown holdup tank pump starts at a preset holdup tank level to deliver tank contents to the inlet filter, demineralizers, post filter and thence to the main condenser. Detection of abnormally high activity by RM-L7 downstream of the post filter results in automatic termination of flow to the condenser or through the alternate path to the penstocks of the Fairfield Pump Storage Facility. This flow is then directed to the nuclear blowdown monitor tank.

3. Startup During plant startup and subsequent restarts, steam generator blowdown, up to the design flow rate, is used for removal of accumulated deposits from the steam generators and to bring steam generator water chemistry within recommended limits. The cooled steam generator blowdown fluid may be discharged through the circulating water discharge to Monticello Reservoir.

During these operations, however, the steam generator blowdown fluid may contain high concentrations of corrosion products in the form of iron oxides. Should the concentrations of these impurities exceed acceptable limits, the blowdown fluid is routed to the alum sludge lagoon through the clarifier blowdown sump for reduction of suspended solids content prior to discharge.

4. Cold Shutdown and Refueling During cold shutdown and refueling the steam generator wet layup system skid may be attached, by flexible hoses, between the blowdown system and the Emergency Feedwater System. The skid takes suction from blowdown and returns water to the steam generators via the turbine-driven emergency feedwater pump header.

The Steam Generator Wet Layup System may be used only during modes 5 and 6.

It must be isolated and disconnected before entering mode 4.

The blowdown and Emergency Feedwater System valves may be used to direct wet layup recirculation to any of the three steam generators, allowing one or more to be maintained in layup with one or more others open for maintenance.

10.4-31 Reformatted April 2021

Operation of the steam generator wet layup skid equipment is local and manual.

10.4.8.2.3 Radiological Considerations Annual release quantities and expected doses to individuals at or beyond the site boundary are discussed in Section 11.2. Since heat exchangers are installed in the RN system to provide for cooling the blowdown fluid and to prevent flashing, negligible 98-081 gaseous release is expected to result from this system. Process and effluent monitoring and sampling are discussed in Section 11.4.

10.4.8.3 Safety Evaluation Steam generator blowdown flow is automatically terminated under the following conditions:

1. Receipt of a containment isolation signal.
2. Activation of the Emergency Feedwater System.

For 1, above, a containment isolation signal (S signal) is received which closes the steam generator blowdown containment isolation valves. For 2, above, a signal indicating emergency feedwater pump start is received resulting in closure of the steam generator blowdown containment isolation valves. The closure of valves resulting from 2, above, may be manually overridden, provided that plant and personnel safety requirements have been satisfied.

The Steam Generator Blowdown System is non-nuclear safety class and quality related RN 04-026 class, except for that portion of the system inside the Reactor Building and up to the containment isolation valve, and is not required to function under accident conditions.

Termination of steam generator blowdown may be accomplished manually. If the Nuclear Blowdown Processing System is operating at the time steam generator RN blowdown is terminated, the nuclear blowdown holdup tank level controller stops the 01-082 pump when holdup tank level reaches the low level setpoint. Thus, the system is isolated.

Section 10.3.5 provides more detail concerning secondary side water chemistry.

Safety considerations directly associated with the steam generators are discussed in Section 5.5.2.

Since radioactive materials are concentrated in filters and demineralizers, radiation shielding is provided to protect personnel from these potential hazards.

10.4-32 Reformatted April 2021

10.4.8.4 Tests and Inspections Steam generator tests and inspections are discussed in Section 5.5.2. No special maintenance is required for Steam Generator Blowdown System components.

Equipment and piping is periodically subjected to visual examination for evidence of leakage, corrosion, proper support bolting, wear points, and electrical arcing or burning.

Active components, including manual valves and controls are operated periodically to ensure availability when required.

10.4.8.5 Instrumentation Applications The following instrumentation is shown schematically on Figures 10.4-13 through 10.4-15 and is provided to permit the operator to evaluate major equipment performance and to provide a performance record:

1. Pressure indicators, transmitters, and switches.
2. Flow indicators, controllers, recorders, switches, and transmitters.
3. Level indicators, transmitters, controllers, and switches.
4. Temperature indicators, controllers, and switches.
5. Conductivity analyzers, indicators, and switches.
6. Analyzers, indicators, and switches for pH.
7. Engineered safety features monitor lights, located on the main control board, for the containment isolation valves (see Section 7.5 for detailed description).
8. Radiation monitors.

10.4.8.5.1 Temperature Control Steam generator blowdown temperature reduction is controlled by regulating the cooling water flow through the heat exchangers. The blowdown temperature is controlled below saturation to preclude flashing.

Temperature protection is provided for the demineralizers by a temperature switch located on the discharge header of the blowdown holdup tank transfer pumps. At high temperature, an alarm is actuated and the demineralizer inlet valves are automatically closed.

Additional temperature switches actuate alarms upon detection of high blowdown heat exchanger effluent temperature.

10.4-33 Reformatted April 2021

10.4.8.5.2 Flow Control The hydraulic design of the blowdown piping provides for minimal pressure drop up to the blowdown control valves, downstream of the respective heat exchangers. Each blowdown control valve is designed to regulate blowdown flow and thus maintains a relatively constant downstream pressure of approximately 40 psig.

Flow indicating transmitters provide electronic inputs for high and low blowdown flow and blowdown flow control valve closure upon detection of high flow and to a controller to regulate blowdown pressure control valves: Electronic hand controllers are provided to permit adjustment of individual blowdown flows through the respective flow control valves.

10.4.8.5.3 Level Control The blowdown holdup tank level transmitter provides an electronic input for high and low level alarms, dual level pump actuation and low level pump trip. RN 01-082 The monitor tank level transmitter provides an electronic input for high and low level alarms, low level pump trip, and low level closure of the tank discharge valve.

The spent resin storage tank level transmitter provides an electronic input for high and low level alarms and low level pump trip.

10.4.9 EMERGENCY FEEDWATER SYSTEM 10.4.9.1 Design Bases The Emergency Feedwater System is required to deliver sufficient feedwater to the steam generators for cooldown upon loss of the normal feedwater supply and during a 98-01 ATWS (Anticipated Transient Without Scram) event. The Emergency Feedwater System is used, additionally, to supply feedwater to the steam generators during startup, shutdown, and layup operations. Emergency feedwater pump starting is automatic. The Emergency Feedwater System operates in conjunction with the Turbine Bypass System, if available, or the main steam power relief valves and safety valves, to remove thermal energy from the steam generators.

The system is designed to automatically deliver feedwater, at a minimum total flow of 380 gpm, to at least 2 steam generators pressurized to 1211 psig. There is sufficient RN redundancy to establish this flow while sustaining a single active failure in the system in 98-053 the short term or a single active or passive failure in the long term. The Emergency Feedwater System operates until the Residual Heat Removal (RHR) System can be placed in operation. The RHR system is started when reactor coolant pressure and temperature are approximately 400 psig and less than 350°F, respectively.

Corresponding steam generator shell side pressure is approximately 125 psia. This pressure and temperature condition represents the lower limit of Emergency Feedwater System functional requirements as long as the reactor coolant pumps are operating.

10.4-34 Reformatted April 2021

When forced circulation from the reactor coolant pumps is not available, Emergency Feedwater System operation is required down to a main steam pressure of 100 psia.

This corresponds to a reactor coolant cold leg temperature of 325°F and a hot leg temperature of 350°F. The primary coolant temperature differential is required in order to maintain a density gradient to drive natural circulation of primary coolant, in the absence of reactor coolant pump operation.

Sufficient feedwater is available under emergency conditions to bring the plant to a safe shutdown condition. Assuming prior plant operation at engineered safety design rating (ESDR) of 2900 MWt in the core, the minimum required usable volume for the condensate storage tank is 158,570 gallons based on maintaining the plant at hot standby conditions for 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. This volume also satisfies the minimum required volume to cool down the plant to hot shutdown conditions assuming the plant is maintained at hot standby for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and then cooled down to hot shutdown in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The condensate storage tank is a Safety Class 2b tank. The Service Water System provides an additional safety class backup source of emergency feedwater. Both service water loops can supply the Emergency Feedwater System if required.

System components are classified Safety Class 2a or 2b, except as noted on the system diagram, Figure 10.4-16. Pressure retaining components are designed, fabricated, tested and inspected in accordance with the ASME Code,Section III [5], Classes 2 and 3 RN 01-017 as applicable. Normal operating and design conditions are tabulated on Figure 10.4-16.

Design upset condition is considered to be the shutoff head of the pumps and is expected to occur less than 1% of the time.

Any two emergency feedwater pumps operating together are designed to deliver a total of 380 gpm of feedwater distributed between 2 steam intact generators at pressures of RN 1211 psig, while also feeding the faulted steam generator which has flow passively 12-030 limited by the cavitating venturi in the faulted loop. Any one emergency feedwater pump is designed to deliver 400 gpm total to all three steam generators at a pressure of 1211 psig during the non-faulted event. Pump suction is from the Safety Class 2b condensate RN storage tank, or, if this source is not available, from the Service Water System. Although 98-053 the condensate storage tank is used for normal plant makeup, a reserve is maintained for emergency feedwater purposes. (See Section 9.2.6.1).

This reserve is 160,054 gallons, based on the physical configuration of the tank from the RN 98-149 bottom of the condensate to condenser nozzle to the top of the emergency feedwater suction nozzle. The actual usable amount of this reserve, however, is dependent on the instrument setpoints of the automatic switchover controls to the backup Service Water supply.

The design, with automatic switchover to Service Water occurring prior to full utilization of the dedicated inventory, satisfies safe shutdown requirements. It is considered that full utilization of the dedicated inventory of condensate quality water is highly desirable from a commercial risk viewpoint, but is not absolutely required for safe shutdown as long as a redundant safety class alternate source is available.

10.4-35 Reformatted April 2021

The Emergency Feedwater System is required for plant startup. Fill and maintenance of steam generator water level is accomplished by manual control of feedwater flow rates from the Control Room. The flow rate to each steam generator is individually adjusted as required in response to the Control Room steam generator water level indication.

After normal steam generator water level is reached, flow rates are adjusted as required.

A sampling connection is supplied on the electric motor driven emergency feedwater pump recirculation lines for oxygen level tests.

After reactor criticality is achieved, a limited amount of steam may be withdrawn from the steam generators for steam line warmup and other startup steam uses. The amount of steam that may be withdrawn is limited to the ability of the emergency feedwater pumps to maintain steam generator water level. Electric motor driven emergency feedwater RN pump head/flow characteristics result in flow rates of up to approximately 255 gpm per 12-030 steam generator at hot standby conditions. Based on a nominal steam generator blowdown rate of 50 gpm per steam generator, (equivalent cold volume) approximately 307,488 lb/hr of steam may be withdrawn from the steam generators with 2 motor driven RN 12-030 pumps operating. This corresponds to a nominal 3% plant load condition. The Main Feedwater System must be operated at loads which exceed the capacity of the Emergency Feedwater System.

If a loss of steam generator water level incident occurs during startup, after the reactor becomes critical, Emergency Feedwater System controls operate automatically. This action enhances proper system operation for plant shutdown.

Seismic and quality group classifications for components in this system are discussed in detail in Section 3.2. Environmental conditions are discussed in Section 3.11.

10.4.9.2 System Description The Emergency Feedwater System includes 2 electric motor driven emergency feedwater pumps, 1 turbine driven emergency feedwater pump, the condensate storage RN tank, necessary piping, valves, instrumentation, and controls. The Emergency 12-030 Feedwater System is essential to safety. The system is designed such that no single failure prevents delivery of the minimum feedwater flow to at least 2 steam generators while passively limiting flow to a postulated secondary side line break by virtue of cavitating venturis installed in the piping to each of the three steam generators (one cavitating venturi per steam generator). Pump and turbine bearings are cooled by the pumped emergency feedwater, thereby making pump operation independent of plant cooling systems. The quick start, steam turbine driven emergency feedwater pump is RN supplied with steam from the Main Steam System and is designed to operate without air 12-030 or electrical power. Both motor driven emergency feedwater pumps are provided with a mechanical-type, automatic recirculation control valves (ARC), which provides for pump protection for low flows and maximizes flow to the steam generators by automatically closing the recirculation line once the pumps minimum flow requirement is met.

Conversely, the turbine driven pump utilizes a fixed-restriction minimum-flow system, which provides for continuous recirculation and overall system diversity; this fixed 10.4-36 Reformatted April 2021

recirculation flow design feature is made possible due to the performance margins inherent in the turbine driven pump.

Each pump motor is supplied from a separate, independent Class 1E electric system bus. Complete physical separation is followed throughout for control and instrumentation systems. The required instrumentation and control are powered from separate and independent vital buses.

The steam supply to the turbine driven emergency feedwater pump consists of connections to the safety class sections of 2 main steam lines upstream of the main steam isolation valves. Two (2) connections are provided to obtain redundancy of supply in the event of a main steam line break. Each connection is provided with a remote manual motor operated gate valve and a check valve for positive isolation in the event of a main steam break. In the common line to the pump turbine, a normally closed, fail open steam inlet valve is provided. This valve has slow opening characteristics to minimize shock to the turbine during automatic startup. This line then connects to a turbine trip and throttle valve which is part of the turbine package. The turbine discharge steam exhausts to atmosphere through a roof vent. Vent piping is safety-related since, if it were blocked, pump turbine operation would be affected.

The emergency feedwater pumps take suction from the condensate storage tank. There is an outlet valve and an outlet bypass valve in parallel at the EFW suction outlet in the RN tank. These valves are 10 inch manual valves feeding the 10 inch header and are 98-089 locked open to prevent undesired isolation of the EFW system from its primary supply of water. Each pump draws from a common header through a locked open isolation valve and a check valve. The redundant backup source of supply is the Service Water System. The A service water loop can supply the A electric motor drive emergency feedwater pump and the turbine driven emergency feedwater pump. The B service water loop can also supply the turbine drive emergency feedwater pump and the B electric motor driven emergency feedwater pump. Suction lines to each pump from each service water loop have normally closed remote manual, motor operated isolation valves.

These valves are automatically opened on low pressure in the emergency feedwater pump suction header from the condensate storage tank. The plant can operate indefinitely, if required, without normal feedwater. The Emergency Feedwater System can take suction from the Service Water System for an indefinite period of time.

There are 2 emergency feedwater headers supplying each steam generator, 1 header from the electric motor driven emergency feedwater pumps and one header from the turbine driven emergency feedwater pump. These headers join downstream of the flow RN 12-030 control valves into one line for each steam generator. Each of the three parallel lines proceed through, a flow-limiting cavitating venturi, a containment isolation valve and a containment penetration to its respective steam generator. The containment isolation valve for each line is an air-piston assisted, hinged check valve that allows forward passage of emergency feedwater flow but closes to prevent reverse flow.

Each emergency feedwater pump discharge is provided with a check valve and locally operated isolation valve. These valves prevent backflow through an emergency 10.4-37 Reformatted April 2021

feedwater pump and permit maintenance of a pump and/or check valve. Two (2) sets of normally open isolation valves and normally open, pneumatically operated, flow control valves, designed to fail open upon loss of control signal or air, are provided on each line to each steam generator. One (1) set control flow from the electric motor driven emergency feedwater pumps; the other, flow from the turbine driven emergency feedwater pump. Remote manual control of the flow control valves from the control room and CREP is provided, as well as provision for local manual operation. Safety class air accumulators are provided for the pneumatically operated valves. These accumulators have sufficient capacity to permit remote valve closure for isolation of a secondary system break. The air operated nonreturn valve functions as a containment isolation valve to prevent back flow in the event of a pipe break on the pump side of the valve.

A connection is provided for steam generator wet layup during cold shutdown conditions, using the steam generator wet layup skid of the blowdown system. (Section 10.4.8)

The EF system also has an automatic detection and isolation system in the event of an EF system pipe break between the automatic isolation valves and the cativating venturis. RN 12-030 10.4.9.3 Safety Evaluation Normal Emergency Feedwater System conditions encompass the automatic, startup, operating, shutdown and testing modes. During the automatic mode, the system is aligned and set for automatic startup upon receipt of a signal. During the other modes 1 or 2 emergency feedwater pumps may be operating.

During normal plant operation the Emergency Feedwater System is idle. Controls for the system are set for automatic operation to allow for quick system start if necessary. The electric motor driven emergency feedwater pumps start automatically upon receipt of any of the following signals:

1. Two (2) out of 3 low-low steam generator level signals from any 1 of the 3 steam generators.
2. Trip of all 3 main feedwater pumps.
3. Engineered safety features loading sequence (under voltage on 1E bus and/or safety injection signal).
4. The ATWS (Anticipated Transient Without Scram) Mitigation System Actuation 98-01 Circuitry (AMSAC) starts the motor driven pumps on low-low level in 2 out of 3 steam generators.

The turbine driven emergency feedwater pump starts automatically upon receipt of any of the following signals:

1. Two (2) out of 3 low-low steam generator level signals from any 2 steam generators.

10.4-38 Reformatted April 2021

2. Under voltage on diesel buses.
3. The ATWS (Anticipated Transient Without Scram) Mitigation System Actuation RN 98-55 Circuitry (AMSAC) starts the turbine driven pump on low-low level in 2 out of 3 steam generators.

The turbine driven emergency feedwater pump and the parts of the system necessary for its operation are designed to operate under loss of electrical power and loss of compressed air conditions. Flow control valves fail in the open position and are normally open. Root valves in the main steam branch lines to the emergency feedwater pump drive turbine are left open during normal plant operations. When either root valve is closed, it is annunciated in the control room.

The essential controls, valve operators, and other supporting systems associated with the turbine driven emergency feedwater pump are independent from a-c power. The lube oil cooler receives cooling water from the pump discharge.

Subsequent to a start signal, the Emergency Feedwater System, automatically delivers no less than a total flow of 380 gpm to both intact steam generators assuming a secondary line break. For non-faulted conditions no less than a total of 400 gpm to all three steam generators can be supplied. In the event that a secondary break results in a depressurized steam generator, the Emergency Feedwater System automatically (passively) limits the flow to the affected steam generator via cavitating venturis, thus resulting in more flow to the intact steam generators and less to the faulted steam RN generator. Also, since flow is immediately limited to the faulted steam generator, less12-030 mass and energy will be produced by the faulted steam generator before operator action is required to manually isolate the faulted steam generator. Thus, the cavitating venturis RN ensure sufficient flow is directed to the intact steam generators and limits flow to the 96-67 faulted steam generator to ensure the design pressure of containment is not exceeded.

Following an automatic startup signal, the operator adjusts flow rates to maintain steam generator water level while the plant is shut down or held at the hot standby condition.

The following operator actions are required to limit generation of mass and energy from the faulted steam generator following a secondary side break:

After 10 minutes:

RN 98-55

1. Determine which steam generator is faulted.
2. Manually terminate emergency feedwater flow on the line associated with the break from the control room if possible by closing both parallel flow-control valves leading to the faulted steam generator.
3. Adjust flow rates to maintain intact steam generator water levels.
4. Monitor condensate storage tank water level and provide makeup, if available, or shift alignment to the service water supply before the condensate storage tank inventory is expended.

10.4-39 Reformatted April 2021

Within the next 20 minutes:

1. Close any flow control valve supplying a faulted steam generator if it failed to close RN after the first 10 minutes, from the control room or locally.96-067 RN
2. Close at least one additional isolation valve in series with each of the two, closed,12-030 parallel flow-control valves leading to the faulted steam generator to reduce the possibility of emergency feedwater leak-by.

During the 30 minute period, flow to the affected steam generator is limited by the cavitating venturi, if one or both isolation valves failed to close from the control room.

It is important to note that to ensure acceptable results from the feedwater line break event (FSAR Section 15.4.2.2), the manual actions described above are not required; RN the above described actions are only concerned with containment pressure-and- 12-030 temperature analysis and for determination of environmental conditions due to steam line breaks outside of containment.

The operator in the Control Room is provided with position indication for the six RN emergency feedwater isolation valves. In addition, isolation valve status is included in 12-030 the ESF monitoring equipment on the main control board.

A summary failure analysis of the Emergency Feedwater System is presented by Table RN 10.4-8 for a secondary pipe break with a simultaneous loss of non-class 1E electrical 98-053 power. A more detailed failure analysis, covering deterministic and probabilistic 12-030 considerations, is documented in design calculations maintained by the PRA group.

02-01 Failure to automatically isolate emergency feedwater to the affected SG is an important consideration within two secondary pipe break analyses. For secondary side pipe breaks inside containment (FSAR Section 6.2), operator action at 30 minutes is credited to isolate emergency feedwater to the affected SG. Local or remote operator action within 30 minutes is required to prevent overpressurizing the containment. Secondly, for RN secondary side pipe breaks outside containment (FSAR Section 3.11.2.2.2.2), credit is98-053 taken for operator action at 10 minutes to isolate emergency feedwater to the affected SG. Since the harsh environment will limit local manual actions, operator action from the control room is required for secondary pipe breaks outside containment to preserve environment conditions for equipment qualification.

Operator action is required within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the secondary side line break to visually inspect Emergency Feedwater System piping for passive failure.

02-01 If a pipe break should occur in the Intermediate Building, alarm and control devices act to prevent flooding at safety-related equipment on the floors. Section 7.6.5.1.2 outlines the details of the provisions for leak detection.

The Emergency Feedwater System is used to bring the plant to a sufficiently cold condition to permit Residual Heat Removal (RHR) System operation. The plant can 10.4-40 Reformatted April 2021

operate indefinitely, if required, without normal feedwater. The Emergency Feedwater System can take suction from the Service Water System for an indefinite period.

Table 10.4-8 presents an Emergency Feedwater System failure analysis which addresses the consequences of various single active failures within the system in conjunction with a secondary side pipe break and a simultaneous loss of non-Class 1E RN 98-053 electrical power. These conditions are considered to establish the limiting conditions for Emergency Feedwater System design. In addition, the emergency feedwater piping has been laid out to minimize water hammer occurrences induced by the piping system.

10.4.9.4 Inspection and Testing Requirements Inservice functional testing is performed by manual startup of the emergency feedwater pumps. Pumps and valves may be tested while the plant is in operation.

The actuation circuitry of the service water-to-emergency feedwater cross connect valves is periodically tested during normal power operations. Stroke testing of these RN 11-022 motor-operated valves is performed during cold shutdown to preclude contamination of the steam generators.

To avoid injection of cold water into the steam generators during normal plant operation, the flow control valves associated with the pump under test (motor driven or turbine driven) are closed during the test.

Periodic system and component checks and inspections are performed as specified by RN 04-012 the applicable ASME Code, prescribed under 10CFR50.55a.

10.4.9.5 Instrumentation Requirements Emergency Feedwater System instrumentation provides the necessary inputs for control, operation, and performance/status monitoring of the system.

Those devices (indicators, switches, alarms, computer monitoring, etc.) available to the operator in the Control Room are shown schematically on Figure 10.4-16. In addition, indicators and/or controls are also located on the control room evacuation panel, local panels, and near the components.

10.4.9.5.1 Pressure Measurement

1. Pressure Transmitters Pressure transmitters are provided in the common feed line to each steam generator for control room indication.

In addition to the above pressure transmitters, 4 pressure transmitters are provided in the emergency feedwater pump suction header from the condensate storage tank. The output from these transmitters is arranged in a 2 out of 4 logic to automatically open the cross connect valves to the Service Water System 10.4-41 Reformatted April 2021

(XVG-1037A-EF, XVG-1037B-EF, XVG-1001A-EF, XVG-1001B-EF, XVG-1002-EF, XVG-1008-EF) on low emergency feedwater pump suction header pressure.

2. Pressure Switches Pressure switches located in the suction line to each pump provide contacts for a low pressure alarm.
3. Pressure Indicators Pressure indicators are provided to monitor the availability of a water supply for each pump and to meet the inservice testing requirements for the pumps.

10.4.9.5.2 Level Measurement Level Transmitters Redundant level transmitters located on the condensate storage tank provide signals for low level alarms, computer inputs, and Control Room indicators (for post accident monitoring). In addition, the transmitters provide nonredundant signals for level indication at the panel supplied with the cycle makeup treatment plant and the control room evacuation panel.

10.4.9.5.3 Flow Measurement Flow transmitters provide signals for alarms and redundant safety grade flow indication in the Control Room. Flow transmitters also provide signals for computer input, and for interlocks which automatically close the emergency feedwater flow control valves in case RN of a break in the emergency feedwater system between the flow control valves and the 12-030 cavitating venturis. The emergency feedwater control valves are manually controlled from the Control Room or the control room evacuation panel for startup, shutdown and testing modes. Whenever an emergency feedwater control valve is in manual control and receives a signal indicative of an accident condition, the valve is automatically tripped open. During normal power operation, the emergency feedwater control valves are in the open position ready for automatic start of the emergency feedwater pumps.

The control valves will remain open until throttled or closed by the operator or automatically closed by a high flow signal indicative of a break in the emergency feedwater system between the flow control valves and the cavitating venturis. Closure of the 2 emergency feedwater control valves terminates emergency feedwater flow only RN into the faulted steam generator loop. Due to the passive flow limitation of the cavitating 12-030 venturis, the emergency feedwater control valves will not automatically close due to a faulted steam generator and will rely on operator action to isolate the faulted loop within 10 minutes.

For each emergency feedwater control valve (FV-3531, FV-3541, FV-3551, FV-3536, FV-3546, FV-3556), position indicating design provisions include the following:

10.4-42 Reformatted April 2021

1. Visual indication in the main control room by means of an ESF monitor light that will be "bright" when the valve is not open. Section 7.5.4 provides a more detailed explanation of the operation of the ESF monitor lights. An alarm will be annunciated via a common monitor light alarm if an emergency feedwater control valve is not open. This grouping highlights a valve not properly lined up. This light is energized from an ESF monitor light supply different from the valve control power and actuated by a valve limit switch. In addition to this visual position information, there are also red (open) and green (closed) position indicating lights at the control switch for each valve. These lights are actuated by valve limit switches and are powered by valve control power.
2. Audible and visual alarm annunciator points will be activated whenever an emergency feedwater control valve control switch is not in the auto position. The alarm activated by the control switch will be recycled by a timer at approximately 60 minute intervals to remind the operator of the improper valve line up. Both the alarm reflash annunciator point and the timer will be energized separately from the valve control power.

10.4.9.5.4 Speed Measurement A speed transducer, supplied with the turbine driven emergency feedwater pump turbine, provides signals for Control Room indication.

10.4.9.5.5 Special Instrumentation The main control board ESF monitor lights (see Section 7.5 for a more detailed explanation) provide an easily recognizable indication of the status of essential components and equipment. Included among the monitor lights for this system are status (position) indication of the flow control valves, the motor driven pumps, and the valve that admits steam to the turbine driven emergency feedwater pump.

An alarm is actuated if either control switch for the valve that admits steam to the turbine RN driven emergency feedwater pump is in the close position. The alarms ensure proper 98-083 control switch alignment for normal operations. Switch covers are provided for these switches to prevent inadvertent operator action.

The emergency feedwater flow to each steam generator and condensate storage tank level are part of the post accident monitoring instrumentation (see Section 7.5 for a more detailed explanation).

10.4-43 Reformatted April 2021

10.4.9.5.6 Qualifications Sections 3.10, 3.11, and 7.1 outline the qualifications and diversity of the instrumentation utilized in this system.

10.4.10 TURBINE BUILDING CLOSED CYCLE COOLING WATER SYSTEM The Turbine Building Closed Cycle Cooling Water System provides cooling water to components associated with the steam and power conversion system. The energy is dissipated to the atmosphere by a wet surface industrial cooling water.

10.4.10.1 Design Basis The Turbine Building Closed Cycle Cooling Water System supplies non-nuclear safety class cooling water to the following components:

1. Turbine oil coolers
2. Hydrogen coolers
3. Exciter air cooler
4. Stator coolers
5. Main condenser vacuum pump coolers
6. Auxiliary condenser vacuum pump coolers
7. Instrument/service air compressors
8. Non-nuclear sample coolers
9. Non-nuclear sample chiller
10. Feedwater pump and turbine oil coolers
11. Feedwater booster pump mechanical seals and oil coolers
12. EHC oil coolers RN
13. Isophase bus duct coolers01-113
14. Condensate pump seal coolers RN
15. Condensate demineralizer system air compressor 10-018 Major design parameters for the cooling water system pumps and the cooling tower are presented in Table 10.4-9.

10.4-44 Reformatted April 2021

System piping and valves are designed in accordance with the applicable ANSI industry standards B31.1 [1] and B16.5 [2] respectively. Hydrogen coolers, stator coolers, exciter RN air cooler, and turbine oil coolers are designed in accordance with the ASME Code,01-017 Section VIII [6], Division 1. Pumps are designed in accordance with Hydraulic Institute Standards.[9] The system is sized to ensure adequate heat removal based on 95° F nominal cooling tower water outlet temperature.

10.4.10.2 System Description The Turbine Building Closed Cycle Cooling Water System components include a wet surface industrial cooling tower, two 100% capacity tower spray pumps, 4 cooling tower RN fans, two 100% capacity closed cycle cooling pumps, two 100% capacity closed cycle 10-018 cooling booster pumps, various equipment coolers, and a head tank. Chemical injection and blowdown are provided to maintain the quality of the spray water.

Under normal operation, 1 of the 2 cooling water pumps circulates treated water through the cooling tower coils transferring the heat removed from the various components to the spray water and then to the atmosphere by evaporation of the spray water in the air stream produced by cooling tower fans. The dispersant and anti-fouling chemicals added to the cooling tower raw water are sufficiently diluted to ensure negligible effect on the environment. Cooling tower effluents, including salt drift and chemical discharges, will have negligible effect on plant structures and systems.

In the event of loss of the operating closed cycle pump while a-c power is available, the non-operating closed cycle pump starts automatically on detection of a pressure drop in the pump header. RN 10-018 The head tank located at the highest point in the system provides makeup and storage for thermal volume changes.

10.4-45 Reformatted April 2021

10.4.10.3 Safety Evaluation The Turbine Building Closed Cycle Cooling Water System is independent of the plant emergency cooling facilities. This system is not required for reactor protection nor for safe shutdown of the nuclear portion of the plant and is therefore classified as non-nuclear safety class, non-Seismic Category 1. Failure or malfunction of any system component will not affect the ability of the plant to achieve or maintain shutdown conditions.

A postulated failure in the Turbine Building Closed Cycle Cooling Water System inside the Turbine Building is bounded by the postulated failure of an expansion joint in the Circulating Water System piping as discussed in Section 10.4.5.3. Failure of the Turbine Building Closed Cycle Cooling Water System, having a limited volume of water which could be released into the turbine building, results in a lower flood level than the postulated event where circulating water is released through an expansion joint failure until the pump isolation valve closed.

The case of postulated missiles resulting from a broken cooling tower fiberglass fan blade is enveloped by the tornado missile spectrum applicable to the design of Seismic Category 1 structures.

10.4.10.4 Tests and Inspection Testing of the Turbine Building Closed Cycle Cooling Water System is limited to that normally provided for non-safety related systems and includes:

1. Hot functional testing.
2. Normal, operational checking and routine maintenance of the system.

10.4.10.5 Instrumentation System instrumentation to permit operator evaluation of equipment performance and to provide a performance record includes:

1. Pressure indicators, switches and test connections.
2. Flow indicators.
3. Level switches.
4. Temperature indicators and test connections.
5. Distributed Control System (DCS) for controlling and monitoring including operator interface.

10.4-46 Reformatted April 2021

10.4.11 REFERENCES

1. American National Standards Institute, "Power Piping," ANSI B31.1, 1967, Addenda through 1972.
2. American National Standards Institute, "Steel Pipe Flanges, flanged Valves and Fittings," ANSI B16.5, 1968.
3. U. S. Nuclear Regulatory Commission, "Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Pressurized Water Reactors,"

NUREG-0017, April, 1976.

4. Heat Exchange Institute, "Standards for Steam Surface Condensers," Sixth Edition, 1970.
5. ASME Boiler and Pressure Vessel Code,Section III.
6. ASME Boiler and Pressure Vessel Code,Section VIII, Division 1.
7. Heat Exchange Institute, "Standard for Closed Feedwater Heaters," Second Edition, 1974.

RN

8. ASME Boiler and Pressure Vessel Code,Section XI.01-017
9. Hydraulic Institute Standards, for Centrifugal, Rotary, and Reciprocating Pumps.
10. IEEE - Standard 382-1972, "Type Test of Class 1 Electric Valve Operators."
11. Regulatory Guide 1.48, Rev. 0, "Design Limits and Leading Combinations for Seismic Category 1 Fluid System Components."
12. GAI Report No. 2203, "Emergency Feedwater System Reliability Assessment."

10.4-47 Reformatted April 2021

TABLE 10.4-1 CONDENSER DESIGN CAPACITIES Low Pressure Shell High Pressure Shell Size, ft2 300,000 300,000 Shell Side Steam In, lbs/hr 3.43 x 106 3.43 x 106 U Service BTU/hr-ft2-F 539.1 559.1 Cleanliness factor, % 90 90 Saturation Temperature, F 103.22 114.02 Log Mean Temperature Difference, F 19.52 18.33 Operating Pressure, in HgA 2.13 2.91 RN Oxygen Guarantee in Hotwell,* cc/liter 0.005 01-029 Total Calculated Duty, BTU/hr ~ 6,232 x 106 Tube Side Circulating Water Flow, gpm ~ 520,000 ~ 520,000 Water In, F 77 89.1 Water Out, F 89.1 101 Number of Passes One One Pressure Drop, ft of water ~ 12.7 ~ 12.4 Velocity, ft/sec ~ 8.030 ~ 8.030

  • At turbine loads >50%. RN 01-029 10.4-48 Reformatted April 2021

TABLE 10.4-1 (Continued)

CONDENSER DESIGN CAPACITIES Auxiliary Condensers Each Shell Quantity 3 Size ft2 5,122 Shell Side (each condenser)

Steam In, lb/hr 64,839 U Service BTU/hr-ft2-F 456 Cleanliness Factor, % 90 Saturation Temperature, F 118.00 RN Log Mean Temperature Difference, F 26.96 01-113 Operating Pressure, in HgA 3.2 Tube Side (each condenser)

Circulating Water Flow, gpm 5,000 Water In, F 77 Water Out, F 101.4 Number of Passes 3 Pressure Drop, ft of water 12.6 Velocity, ft/sec 6.4 at 60F Main Condenser Vacuum Pumps Capacity, Free Dry Air, lb/hr (scfm) 90 (20), each pump Capacity, Associated Vapor, lb/hr 198, each pump Total Capacity, Air-Vapor Mixture, lb/hr 288, each pump Auxiliary Condenser Vacuum Pumps Capacity, Free Dry Air, lb/hr (scfm) 67.5 (15), each pump Capacity, Associated Vapor, lb/hr 147.5, each pump Total Capacity, Air-Vapor Mixture, lb/hr 215.0, each pump 10.4-49 Reformatted April 2021

TABLE 10.4-2 TURBINE BYPASS VALVE SETPOINTS Applicable Reference Valves Condition Device Setpoint FSAR Figure RN All Lo-Lo Tavg SSPS (K631) 552F 10.4-4b 01-113 Condenser Condenser PY/3006A 5 HgA 10.4-4b Dumps Only Pressure Condenser Condenser PY/3016A 5 HgA 10.4-4b Dumps Only Pressure RN All Turbine Impulse PB447A 10% of load 10.4-4b 01-029 Chamber Pressure All Turbine Impulse PB447B 50% of load 10.4-4b Chamber Pressure Condenser Hi Tavg Load TB408F Hi 1-5.7F 10.4-4b Dumps Only Rejection Steam Hi 2-16.9F Dump Atmospheric Hi Tavg Load TB408P Hi 3-22.4F 10.4-4b RN Relief and Rejection Steam Hi 4-28F 01-029 Power Relief Dump Only Condenser Hi Tavg Turbine Trip TB408J Hi 1-7.6F 10.4-4b Dumps Only Steam Dump Hi 2-30.4F Power Relief Pressure Controller PC ** 1107 psia 10.4-4a Valves Only Power Relief Pressure Control TY-408R1 77.7 to 10.4-4a RN Valves Only TY-408R2 100% (1)04-003 Power Relief Pressure Bistable PB *** 1148 psia inc.; 10.4-4a Valves Only reset at 1105 psia, dec.

Atmospheric Pressure Control TY-408Q1 57.7 to 10.4-4a Relief Valves TY-408Q2 77.7% (1) RN Only 04-003 Condenser Pressure Control TY-408N1 0 to 14.4% (1) 10.4-4a Cooldown TY-408N2 Valves Only 10.4-50 Reformatted April 2021

TABLE 10.4-2 (Continued)

TURBINE BYPASS VALVE SETPOINTS Applicable Reference Valves Condition Device Setpoint FSAR Figure Condenser Pressure Control TY-408P1 14.4 to 10.4-4a RN Dump Valves TY-408P2 57.7% (1)04-003 Only TY-408P3 IFV-2097-MB Valve Open Permit PY/3006B or 4.5 HgA 10.4-4a RN 01-029 and PY/3016B IFV-2117-MB Only (1) Operating bandwidth based on valve limitations. Percent of steam dump capacity RN

(~ 93.6% of rated steam flow), as outlined on Figure 7.2-1, Sheet 10.04-003 10.4-51 Reformatted April 2021

TABLE 10.4-3 CIRCULATING WATER SYSTEM DESIGN PARAMETERS Traveling Screens Quantity 6 Type Through flow Screen Material 304 Stainless steel Screen Mesh Opening, in 3/8 Design Water Velocity, fps 0.75 (approach)

RN Capacity, gpm 95,000 @ 1.32 fps01-054 120,000 @ 1.67 fps Circulating Water Pumps Quantity 3 Type Vertical, wet pit Total Dynamic Head, ft 40.5 Capacity, gpm ~178,000 RN 08-001 Speed (XPP0006A/B/C), rpm (297/294/294)

Shutoff Head, ft 89 Horsepower 2250 Circulating Water Jockey Pump Quantity 1 Type Vertical, wet pit Total Dynamic Head, ft 38 Capacity, gpm 5000 Speed, rpm 690 Shutoff head, ft 50 Horsepower 75 10.4-52 Reformatted April 2021

TABLE 10.4-3 (Continued)

CIRCULATING WATER SYSTEM DESIGN PARAMETERS Lube Water Booster Pump Quantity 1 Type Vertical RN 01-054 Total Dynamic Head, ft 150 Capacity, gpm 50 Speed, rpm 3500 Shutoff Head, ft 170 Horsepower 7.5 Screen Wash Pumps Quantity 2 Type Horizontal Total Dynamic Head, ft 250 Capacity, gpm 2000 Speed, rpm 1750 Shutoff Head, ft 280 Horsepower 200 10.4-53 Reformatted April 2021

TABLE 10.4-3a WATER LEVEL VERSUS TIME FOR A POSTULATED CIRCULATING WATER SYSTEM EXPANSION JOINT FAILURE Elevation (ft) Time (sec) Event 390 0-5 Alarm in main condenser cleaning pit 400 46 Second alarm, trip of circulating water pumps 412 102 Amertap strainer pit over-flows to turbine building floor 413 147 -

413.5 170 Circulating water pumps discharge valves close fully, flow stops NOTE: Prior to pump discharge valve closure, water rise in the Turbine Building is approximately 16 in/min.

10.4-54 Reformatted April 2021

TABLE 10.4-4 CONDENSATE SYSTEM EQUIPMENT PARAMETERS Condensate Pumps Quantity 3 Design capacity, gpm 9635 Design Total Dynamic Head, ft 605 Efficiency at Design Condition % 82 NPSH Required at Design Point, ft 18 Design Speed, rpm 1187 Shutoff Head, ft 775 Minimum Flow, gpm 1000 Motor Rated Horsepower, HP 2000 Normal Operating Point Conditions Total Dynamic Head, ft 630 RN Flow, gpm 9177 01-029 Horsepower, BHP 1800 Deaerator Quantity 1 Condensate, lb/hr 8,837,684 Temperature, F 300.3 Extraction Steam Flow, lb/hr 255,110 Pressure (at inlet), psia 107.9 Enthalpy, BTU/lb 1228.3 High Pressure Heater Drain, lb/hr 3,752,012 10.4-55 Reformatted April 2021

TABLE 10.4-4 (Continued)

CONDENSATE SYSTEM EQUIPMENT PARAMETERS Capacity of Deaerator Storage Tank at Normal Water Level 75,000 (5 ft above tank center line), gal 02 Content Guarantee, cm3/liter 0.005 Vented Steam Flow 300 (Predicted), lb/hr Design Pressure, psig Full vacuum - 116 Operating Pressure, psia 107.9 Feedwater Heaters Heater 4 Heaters 5 & 6 Quantity 2 2/2 Feedwater, lb/hr 4,418,842 (each) 4,418,842 (each)

Extraction Steam, lb/hr (each) 333,171 267,781/169,903 Drain, lb/hr Flow (from) each 333,171 608,974/887,700 Steam Pressure at Inlet, psia 71.5 21.8/5.87 RN Feedwater Inlet, F 227.5 164.1/115.1 01-113 Feedwater Outlet, F 300.3 227.5/164.1 Steam In, F 324.4 237.1/172.7 Drains Out, F 240.5 174.1/125.1 Drain Cooler approach, F 13 10/10 Terminal Difference, F 4.0 5/5 Total Heat Transferred, BTU/hr 326,994,308 281,480,235/

216,081,374 RN 06-041 10.4-56 Reformatted April 2021

TABLE 10.4-5 FEEDWATER SYSTEM EQUIPMENT PARAMETERS Feedwater Booster Pumps Quantity 4 Configuration Horizontal, single stage, double suction, horizontal split, dual volute casing Operating* NPSH Required, ft 28 Operating* Total Dynamic Head, ft 565 Operating* Capacity, gpm 7200 RN Design NPSH Required, ft 29 01-029 Design Total Dynamic Head, ft 555 Design Capacity, gpm 7556 Design Shaft Horsepower Required, BHp 1150 Speed, rpm 1780 Feedwater Pumps Quantity 3 Configuration Horizontal, single state, double suction, diffuser type Operating* Capacity, gpm 9600 (each pump)

Operating* Total Dynamic Head, ft 2365 Operating* Speed, rpm 4550 Operating* Efficiency, % 87.5 RN 01-029 Design Capacity, gpm 10,075 (each Pump)

Design Total Dynamic Head, ft 2585 Design Speed, rpm 4800 Maximum Shut Off Head, ft 4225 ( 6% at runout)

  • At 100% Rated Power w/1% Blowdown 02-01 10.4-57 Reformatted April 2021

TABLE 10.4-5 (Continued)

FEEDWATER SYSTEM EQUIPMENT PARAMETERS Feedwater Heaters Heaters 1A & 1B Heaters 2A & 2B Quantity 2 2 Type Horizontal, U-tube, closed, with internal drains cooler Feedwater (In), lbs/hr; BTU/lb 6,429,057; 351.0 6,429,057; 308.1 Steam, lbs/hr; BTU/lb 444,740; 1143.7 869,334; 586.0 Drains to Heater lbs/hr; BTU/lb 552,045; 531.4 1,006,672;362.5 RN Steam Pressure at Inlet, psia 408.1 205.6 01-029 Feedwater Inlet, F 376.1 335.1 Feedwater Outlet, F 441.0 376.1 Steam Inlet, F 456.6 393.0 Drains Out, F 388.1 347.6 Drain Cooler approach, F 12 12.5 Terminal Difference, F 5.6 8.0 Total Heat Transferred, BTU/hr 448,748,179 275,806,545 10.4-58 Reformatted April 2021

TABLE 10.4-6 FEEDWATER SYSTEM FAILURE ANALYSIS Component Malfunction Comment Feedwater Booster Pump 1. Trip of one operating pump from No effect.

normal operating scheme.

2. Trip of one operating pump from Limited power reduction in accordance beyond normal operating with operating procedures.

scheme.

Feedwater Pump 1. Trip of one operating pump from Remaining feedwater pump(s) run out, no normal operating scheme. effect on NSSS.

2. Trip of one operating pump from Reactor trip or runback in accordance beyond normal operating with operating procedures.

scheme.

Feedwater Flow Control Valve Valve fails closed. Reactor trip.

Feedwater Isolation Valve Valve fails closed. Reactor trip.

Feedwater Piping Postulated pipe rupture. See Section 10.4.7.2.3.

10.4-59 Reformatted April 2021

TABLE 10.4-7 STEAM GENERATOR BLOWDOWN SYSTEM COMPONENT DESIGN PARAMETERS Steam Generator Blowdown Heat Exchangers Quantity 3 Type Shell and tube Shell Side Tube Side Fluid Condensate Blowdown 02-01 Design Pressure, psig 250 1185 Design Temperature, F 400 650 Inlet Temperature, F 106 557 Outlet Temperature, F 338 120 02-01 Flow, lb/hr 79,450 40,700 Material SA-515-70 SA-249-304 Effective Heat Transfer Area, ft2 2082 Heat Duty, BTU/hr 18.5 x 106 Nuclear Blowdown Holdup Tank Quantity 1 Capacity, gal 13,000 Design Pressure Atmospheric Design Temperature, F 150 Materials Lined carbon steel 99-01 Nuclear Blowdown Monitor Tank Quantity 1 02-01 Capacity, gal 5,000 Design Pressure Atmospheric Design Temperature, F 150 Material Type 304 stainless steel 99-01 10.4-60 Reformatted April 2021

TABLE 10.4-7 (Continued)

STEAM GENERATOR BLOWDOWN SYSTEM COMPONENT DESIGN PARAMETERS Nuclear Blowdown Holdup Tank Pumps Quantity 2 Type Canned motor, centrifugal Capacity, gpm 300 (Includes 50 gpm of recirc flow) 02-01 Total Developed Head, ft 325 Material Wetted parts - type 316 stainless steel Nuclear Blowdown Monitor Tank Pump Quantity 1 Type Canned motor, centrifugal Capacity, gpm 250 Total Developed Head, ft 250 Material Wetted parts - type 316 stainless steel 02-01 Nuclear Blowdown Demineralizer Inlet Filter Quantity 1 Design Flow, gpm 250 Design Pressure, psig 150 Design Temperature,F 150 Pressure Drop Clean, psi 5 Dirty, psi 20 Particulate Retention, microns absolute 20 RN 05-008 Vessel Material Type 304 stainless steel 10.4-61 Reformatted April 2021

TABLE 10.4-7 (Continued)

STEAM GENERATOR BLOWDOWN SYSTEM COMPONENT DESIGN PARAMETERS Nuclear Blowdown Demineralizers Primary Polishing Quantity 2 2 Resin Capacity, ft3 150 90 Design Flow, gpm 250 250 Design Pressure, psig 150 150 Design Temperature, F 140 140 Material Type 304 stainless steel Resin Type Anion and/or cation exchange resins as required Nuclear Blowdown Spent Resin Storage Tank Quantity 1 Capacity, ft3 600 Design Pressure, psig 150 Design Temperature, F 140 Material Type 304 stainless steel Nuclear Blowdown Resin Sluice Pump Quantity 1 Type Canned motor, centrifugal Capacity, gpm 150 Total Developed Head, ft 230 Material Wetted parts - type 304 stainless steel 10.4-62 Reformatted April 2021

TABLE 10.4-8 EMERGENCY FEEDWATER SYSTEM FAILURE ANALYSIS FOR 98-053 SECONDARY SIDE BREAK WITH LOSS OF NON-1E ELECTRICAL POWER Component Malfunction Comment Any Emergency Feedwater Pump Fails to start The two remaining emergency feedwater 02-01 pumps feed all three steam generators with the two unaffected steam generators receiving required flow. Flow is passively limited to the faulted SG steam generator by the cavitating venturi for 10 minutes (until operator action is credited). 1, 2 RN Motor Driven Pump ARC Valve Fails to automatically isolate pump All three emergency feedwater pumps12-030 recirculation path feed all three steam generators with the two unaffected steam generators receiving required flow. Flow is passively limited to the faulted SG steam generator by the cavitating venturi for 10 minutes (until operator action is credited). 1, 2 98-053 98-053 10.4-63 Reformatted April 2021

TABLE 10.4-8 (Continued)

EMERGENCY FEEDWATER SYSTEM FAILURE ANALYSIS FOR 98-053 SECONDARY SIDE BREAK WITH LOSS OF NON-1E ELECTRICAL POWER Component Malfunction Comment Electrical Channel A Failure (total loss) Channel B motor driven emergency (instrumentation and power) feedwater pumps and the Turbine Driven pump feed all three steam generators with the two unaffected steam generators RN receiving required flow. Flow is passively 12-030 limited to the faulted SG steam generator by the cavitating venturi for 10 minutes (until operator action is credited). 1, 2 98-053 Electrical Channel B Failure (total loss) Channel A motor driven emergency (instrumentation and power) feedwater pump and the Turbine Driven pump feed all three steam generators with the two unaffected steam generators RN 12-030 receiving required flow. Flow is passively limited to the faulted SG steam generator by the cavitating venturi for 10 minutes (until operator action is credited). 1, 2 98-053 Notes:

1 The pressure and temperature analyses for secondary side pipe breaks inside containment credit operator action at 30 minutes to isolate emergency feedwater to the affected SG and thus allow for operator action outside of the control room.

Action is required to prevent overpressurizing the containment. 9 2 The pressure and temperature analyses for secondary side pipe breaks outside containment credit operator action at 10 minutes to isolate emergency feedwater to the affected SG since the harsh environment will limit local manual actions.

Action is required to prevent environment conditions for equipment qualifications.

10.4-64 Reformatted April 2021

TABLE 10.4-9 TURBINE BUILDING CLOSED CYCLE COOLING WATER SYSTEM DESIGN PARAMETERS Turbine Building Closed Cycle Cooling Water System Pumps Quantity 2 Type Horizontal Total Dynamic Head, ft 165 02-01 Capacity, gpm 8750 Speed, rpm 1170 Motor Horsepower 600 02-01 Turbine Building Closed Cycle Cooling Water System Cooling Tower Quantity 1 Type Wet Surface Air Cooler Number of Cells 2 Number of Cooling Coils 8 Number of Fan Assemblies 4 Cooling Coil Water Flow, gpm 8800 Entering Coil Water Temperature, F 107.8 Leaving Coil Water Temperature, F 94 Design Heat Load, Btu/Hr 60,720,000 02-01 Cooling Tower Spray Pumps Quantity 2 Type Vertical Turbine Manufacturer Goulds Total Dynamic Head, ft 46 Capacity, GPM 8500 Speed, RPM 880 Minimum Flow, GPM 2000 Shut-off Head, ft 75 Horsepower 125 10.4-65 Reformatted April 2021

FSAR FIGURE REFERENCE FIGURE 10.4-1 DRAWING D-302-131

Figures 10.4-2, 10.4-2a, and 10.4-2b Deleted per Amendment 96-03 Amendment 96-03 September 1996

FSAR FIGURE REFERENCE FIGURE 10.4-3 DRAWING SS-808-011

FSAR FIGURE REFERENCE FIGURE 10.4-4, Sheet 1 DRAWING SS-808-031

FSAR FIGURE REFERENCE FIGURE 10.4-4, Sheet 2 DRAWING SS-808-031

FSAR FIGURE REFERENCE FIGURE 10.4-4, Sheet 3 DRAWING SS-808-031

14 13 12 11 10 9 8 7 6 5 4 3 2 1

  1. VALVE OPEN PERMIT N/A VALVE OPEN PERMIT PB-3006B/3016B N/A TYPICAL (SEE TABLE 1) CONT. FROM GE RELAY 63X13 A # TABLE BELOW A XCP-6114 N/A PB-3006B/3016B S *****

N/A STEAM DUMP TYPICAL (SEE TABLE 2)

PRESSURE PRESSURE PRESSURE PRESSURE GE RELAY 63X13 POWER RELIEF VALVE E C D B A CONTROLLER CONTROL W BI-STABLE CONTROL W SELECTOR SWITCH (MAINTAINED)

PC ** PC *** PB **** AUTO PWR REL TY ***

TABLE 2 SEE NOTE 3 COMPUTER PRESSURE I/P VALVE VALVE INPUT A B C D E CONTROL CONVERTER FUNCTION

  • B **** *** ** B C D B A CONDENSER I Y1801D IFV-2096-MB 4 18 44 29 58 TY-408N IFY-2096-MB A.S. COOLDOWN P

CONDENSER Y1802D IFV-2097-MB 9 23 45 30 59 TY-408P IFY-2097-MB DUMP CONDENSER THIS PORTION NOT SAFETY RELATED Y1802D IFV-2106-MB 10 24 46 21 60 TY-408P IFY-2106-MB DUMP CONDENSER Y1802D IFV-2107-MB 11 26 47 32 61 TY-408P IFY-2107-MB DUMP CONDENSER Y1801D IFV-2116-MB 5 15 43 33 57 TY-408P IFY-2116-MB COOLDOWN CONDENSER L Y1802D IFV-2117-MB 12 25 48 34 62 TY-408P IFY-2117-MB S 20C S 20D S 20B S 20A DUMP POSI- 0 CONDENSER C A.S. 0 DUMP Y1802D IFV-2126-MB 13 27 49 35 83 TY-408P IFY-2126-MB C S TIONER 0 0 0 CONDENSER Y1802D IFV-2127-MB 14 28 50 36 64 TY-408P IFY-2127-MB DUMP B VENT VENT VENT SEE NOTE 2 I

AS P

A I FAIL CLOSED CHANNEL AS P S S S S S S 20A 20B 20C 20D 20-2 20C 20D 20-1 20B 20A MAIN STEAM XA XB X X 0 0 0 0 VENT 0 0 DUMP VALVE XA XB X X CONT. FROM XA XB X X D IFV-*-MB TABLE ABOVE D XA XB X X VENT VENT OPEN MID CLOSE XA XB X X XA XB X X L XA XB X X POSI- 0 AS S TIONER SEE NOTE 2 TABLE 1 SELECTOR PRESSURE PRESSURE PRESSURE VALVE COMPUTER COMPUTER I/P A I/P B SW. CONTROLLER BI-STABLE CONTROLLER W A B C D C

  • R G E IPY-2000-MS ITY-2000-MS IPV-2000-MS SSMS20 PC-2000 PC-2000B TY-408R1 1 17 54 37 Y1804D AD1013 E IPY-2010-MS ITY-2010-MS IPV-2010-MS SSMS21 PC-2010 PC-2010B TY-408R1 2 18 55 38 Y1804D AD1014 FAIL CLOSED IPY-2020-MS ITY-2020-MS IPV-2020-MS SSMS22 PC-2020 PC-2020B TY-408R2 3 19 56 39 Y1804D AD1015 MAIN STEAM POWER RELIEF THIS PORTION NOT SAFETY RELATED VALVE TYPICAL (SEE TABLE 3) C IPV-*-MS OPEN MID CLOSE NOTES:

PRESSURE CHANNEL C D B A 1. SOLENOID VALVES SHOWN DE-ENERGIZED.

CONTROL W 20 2 20C 20D 20 1 20B 20A CONT. FROM 2. SIGNALS IN TABLES 1, 2, 3 ORIGINATE ON B-802-001, SHEET MS-03.

XA X X XA B A 802 DRAWING SERIES WAS VOIDED PER CGSS-96-0091 AND RN 96-54.

TABLE ABOVE TY ***

XA X X XA B A F 3. PRESSURE BI-STABLE PB-2000B, PB-2010B, PB2020B CONTACTS CLOSE F XB X X XB B A ON INCREASING PRESSURE AT 1148 PSI AND OPEN ON DECREASING PRESSURE AT 1105 PSI.

C C 4. ESF MONITOR LIGHT IS BRIGHT WHEN VALVE IS NOT CLOSED.

I R G L A.S.

P TSC ESF SEE NOTE 4 SV 20C SV 20D SV 20B SV 20A POSI-A.S. 0 TIONER 0 0 0 TABLE 3 VENT VENT VENT VALVE IFV-2006-MB IFV-2016-MB IFV-2026-MB G G A 6 7 8 FAIL CLOSED SEE B 20 21 22 NOTE ATMOSPHERIC 2 C 51 52 53 RELIEF VALVE D 40 41 42 IFV-*-MB PRESSURE OPEN MID CLOSE CONTROL TY-408Q1 TY-408Q1 TY-408Q2 I/P CONVERTER IFY-2006-MB IFY-2016-MB IFY-2020-MB H ** H C 20A XA XA XA H

A 20B XB XB XB N

N 20C X X X R G E L 20D X X X C

Y1803D J

RN 19-006 J SOUTH CAROLINA ELECTRIC & GAS CO.

VIRGIL C. SUMMER NUCLEAR STATION FUNCTIONAL DIAGRAM K

MAIN STEAM SYSTEM K (NUCLEAR)

FIGURE 10.4-4a REV. 2 14 13 12 11 10 9 8 7 6 5 4 3 2 1

14 13 12 11 10 9 8 7 6 5 4 3 2 1 CIRCULATING WATER PUMP A BREAKER CLOSED A A 52a TURBINE LO-LO T AVG LO-LO T AVG CIRCULATING WATER TURBINE TURBINE CONDENSER CONDENSER IMPULSE PUMP B TRIP THIS PORTION TRIP PRESSURE PRESSURE CHAMBER CHANNEL A CHANNEL B BREAKER CLOSED CHANNEL A NUCLEAR SAFETY RELATED CHANNEL B PRESSURE B W SSPS K631 (1, 2) W SSPS K631 (1, 2) PY/3006A PY/3016A 52a W PY447C W SSPS K635 (1, 2) W SSPS K635 (1, 2)

B XCP-6114 XCP-6114 CS-MB02 CS-MB03 XCP-6114 THIS PORTION NUCLEAR SAFETY RELATED STEAM DUMP STEAM DUMP SS-MB01 TURBINE TURBINE INTERLOCK SELECT INTERLOCK SELECT CIRCULATING WATER IMPULSE IMPULSE STEAM DUMP CHANNEL A CHANNEL B PUMP C CHAMBER CHAMBER MODE SELECT BREAKER CLOSED PRESSURE PRESSURE OFF/RESET ON BYPASS OFF/RESET ON BYPASS CHANNEL A CHANNEL B 52a PB447A PB447B RESET TAVG STEAM PRESS C C TURBINE W IMPULSE TURBINE IMPULSE W CHAMBER CHAMBER PRESSURE W

PRESSURE CONDENSER AVAILABLE D D HI T AVG HI T AVG HI T AVG LOAD REJECTION LOAD REJECTION TURBINE TRIP STEAM DUMP STEAM DUMP STEAM DUMP W TB408F W TB408P W TB408J W

E STEAM DUMP E BYPASSED W

STEAM DUMP ACTUATION F F A

STEAM DUMP CONTROL ENERGIZE IPV-2000-SV20A ENERGIZE IPV-2010-SV20A ENERGIZE IPV-2020-SV20A ENERGIZE IFV-2096-SV20A ENERGIZE IFV-2116-SV20A ENERGIZE IFV-2006-SV20A ENERGIZE IFV-2016-SV20A ENERGIZE IFV-2026-SV20A ENERGIZE IFV-2097-SV20A ENERGIZE IFV-2106-SV20A ENERGIZE IFV-2107-SV20A ENERGIZE IFV-2117-SV20A ENERGIZE IFV-2126-SV20A ENERGIZE IFV-2127-SV20A ENERGIZE IFV-2116-SV20B ENERGIZE IFV-2096-SV20B ENERGIZE IPV-2000-SV20B ENERGIZE IPV-2010-SV20B ENERGIZE IPV-2020-SV20B ENERGIZE IFV-2006-SV20B ENERGIZE IFV-2016-SV20B ENERGIZE IFV-2026-SV20B ENERGIZE IFV-2097-SV20B ENERGIZE IFV-2106-SV20B ENERGIZE IFV-2117-SV20B ENERGIZE IFV-2107-SV20B ENERGIZE IFV-2126-SV20B ENERGIZE IFV-2127-SV20B ENERGIZE IFV-2096-SV20D ENERGIZE IFV-2097-SV20D ENERGIZE IFV-2106-SV20D ENERGIZE IFV-2107-SV20D ENERGIZE IFV-2116-SV20D ENERGIZE IFV-2117-SV20D ENERGIZE IFV-2126-SV20D ENERGIZE IFV-2127-SV20D ENERGIZE IPV-2000-SV20D ENERGIZE IPV-2010-SV20D ENERGIZE IPV-2020-SV20D ENERGIZE IFV-2006-SV20D ENERGIZE IFV-2016-SV20D ENERGIZE IFV-2026-SV20D ENERGIZE IFV-2116-SV20C ENERGIZE IFV-2096-SV20C ENERGIZE IFV-2097-SV20C ENERGIZE IFV-2106-SV20C ENERGIZE IFV-2107-SV20C ENERGIZE IFV-2117-SV20C ENERGIZE IFV-2126-SV20C ENERGIZE IFV-2127-SV20C ENERGIZE IFV-2006-SV20C ENERGIZE IFV-2016-SV20C ENERGIZE IFV-2026-SV20C ENERGIZE IPV-2000-SV20C ENERGIZE IPV-2010-SV20C ENERGIZE IPV-2020-SV20C ENERGIZE IFV-2116-SV20C ENERGIZE IFV-2096-SV20C ENERGIZE IFV-2097-SV20C ENERGIZE IFV-2106-SV20C ENERGIZE IFV-2107-SV20C ENERGIZE IFV-2117-SV20C ENERGIZE IFV-2126-SV20C ENERGIZE IFV-2127-SV20C G G H H 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 BLOCK STEAM DUMP PERMIT MODULATION PERMIT TRIP OPEN TRIP OPEN TRIP OPEN TRIP OPEN TRIP OPEN TRIP OPEN TO OF COOLDOWN CONDENSER MODULATION OF COOLDOWN CONDENSER ATMOSPHERIC POWER COOLDOWN CONDENSER COOLDOWN CONDENSER VALVES & CONDENSER DUMP ATMOSPHERIC & CONDENSER DUMP VALVES RELIEF RELIEF CONDENSER DUMP VALVES CONDENSER DUMP VALVES VALVES POWER RELIEF DUMP VALVES VALVES VALVES DUMP VALVES ATMOSPHERIC RELIEF VALVES VALVES RN 19-006 POWER RELIEF VALVES J J NOTES:

1. INDICATING LIGHTS SHOWN ON THE SHEET ARE MAIN STEAM SYSTEM STATUS LIGHTS AND ARE LOCATED ON THE CONTROL BOARD. SOUTH CAROLINA ELECTRIC & GAS CO.
2. MATCH LINE CONNECTIONS ARE ON B-802-001, SHEET 2.

802 DRAWING SERIES WAS VOIDED PER CGSS-96-0091 AND RN 96-54. VIRGIL C. SUMMER NUCLEAR STATION FUNCTIONAL DIAGRAM K

MAIN STEAM SYSTEM K FIGURE 10.4-4b REV. 2 14 13 12 11 10 9 8 7 6 5 4 3 2 1

FSAR FIGURE REFERENCE FIGURE 10.4-5 DRAWING D-302-201

FSAR Figure 10.4-6, D-302-202 and FSAR Figure 10.4-7, D-302-203 Deleted Per Amendment 96-03, MRF-90105, RN 96-44 Amendment 96-03, September 1996 Implemented New FSAR Figure 10.4-6, D-302-204 ECR 50617 August 2006 Reformatted Per August 2006

FSAR FIGURE REFERENCE FIGURE 10.4-6 DRAWING D-302-204

FSAR FIGURE REFERENCE FIGURE 10.4-7A DRAWING D-302-165

FSAR FIGURE REFERENCE FIGURE 10.4-8 DRAWING D-302-101

FSAR FIGURE REFERENCE FIGURE 10.4-9 DRAWING D-302-102

FSAR FIGURE REFERENCE FIGURE 10.4-10 DRAWING D-302-081

FSAR FIGURE REFERENCE FIGURE 10.4-11 DRAWING D-302-082

FSAR FIGURE REFERENCE FIGURE 10.4-12 DRAWING D-302-083

FSAR FIGURE REFERENCE FIGURE 10.4-13 DRAWING D-302-781

FSAR FIGURE REFERENCE FIGURE 10.4-14 DRAWING D-302-782

FSAR FIGURE REFERENCE FIGURE 10.4-15 DRAWING D-302-783

FSAR FIGURE REFERENCE FIGURE 10.4-16 DRAWING D-302-085

FSAR FIGURE REFERENCE FIGURE 10.4-17 DRAWING D-302-362

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