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| number = ML17151B008
| number = ML17151B008
| issue date = 03/09/2017
| issue date = 03/09/2017
| title = Wolf Creek Revision 30 to Updated Final Safety Analysis Report, Chapter 10.0, Steam and Power Conversion System
| title = Revision 30 to Updated Final Safety Analysis Report, Chapter 10.0, Steam and Power Conversion System
| author name =  
| author name =  
| author affiliation = Wolf Creek Nuclear Operating Corp
| author affiliation = Wolf Creek Nuclear Operating Corp
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=Text=
=Text=
{{#Wiki_filter:WOLF CREEK CHAPTER 10.0 TABLE OF CONTENTS STEAM AND POWER CONVERSION SYSTEM Section                                                  Page 10.1 SUMMARY DESCRIPTION 10.1-1 10.1.1 GENERAL DISCUSSION 10.1-1 10.1.2 PROTECTIVE FEATURES 10.1-2  10.1.2.1 Loss of External Electrical Load and/or 10.1-2 Turbine Trip 10.1.2.2 Overpressure Protection 10.1-2 10.1.2.3 Loss of Main Feedwater Flow 10.1-2 10.1.2.4 Turbine Overspeed Protection 10.1-2 10.1.2.5 Turbine Missile Protection 10.1-2 10.1.2.6 Radioactivity 10.1-3
{{#Wiki_filter:WOLF CREEK CHAPTER 10.0 TABLE OF CONTENTS STEAM AND POWER CONVERSION SYSTEM  


10.2 TURBINE GENERATOR 10.2-1 10.2.1 DESIGN BASES 10.2-1
Section                                                  Page


10.2.1.1 Safety Design Bases 10.2-1 10.2.1.2 Power Generation Design Bases 10.2-1  10.2.2 SYSTEM DESCRIPTION 10.2-1  
10.1  


10.2.2.1 General Description 10.2-1 10.2.2.2 Component Description 10.2-3 10.2.2.3 System Operation 10.2-6 10.2.3 TURBINE INTEGRITY 10.2-10
==SUMMARY==
DESCRIPTION 10.1-1  


10.2.3.1 Materials Selection 10.2-10 10.2.3.2 Fracture Toughness 10.2-10 10.2.3.3 High Temperature Properties 10.2-10 10.2.3.4 Turbine Design 10.2-11 10.2.3.5 Preservice Inspection 10.2-11 10.2.3.6 Inservice Inspection 10.2-11 10.2.4 EVALUATION 10.2-12 10.
10.1.1 GENERAL DISCUSSION 10.1-1 10.1.2 PROTECTIVE FEATURES 10.1-2 10.1.2.1 Loss of External Electrical Load and/or 10.1-2 Turbine Trip 10.1.2.2 Overpressure Protection 10.1-2 10.1.2.3 Loss of Main Feedwater Flow 10.1-2 10.1.2.4 Turbine Overspeed Protection 10.1-2 10.1.2.5 Turbine Missile Protection 10.1-2 10.1.2.6 Radioactivity 10.1-3
 
10.2 TURBINE GENERATOR 10.2-1
 
10.2.1 DESIGN BASES 10.2-1
 
10.2.1.1 Safety Design Bases 10.2-1 10.2.1.2 Power Generation Design Bases 10.2-1 10.2.2 SYSTEM DESCRIPTION 10.2-1
 
10.2.2.1 General Description 10.2-1 10.2.2.2 Component Description 10.2-3 10.2.2.3 System Operation 10.2-6
 
10.2.3 TURBINE INTEGRITY 10.2-10
 
10.2.3.1 Materials Selection 10.2-10 10.2.3.2 Fracture Toughness 10.2-10 10.2.3.3 High Temperature Properties 10.2-10 10.2.3.4 Turbine Design 10.2-11 10.2.3.5 Preservice Inspection 10.2-11 10.2.3.6 Inservice Inspection 10.2-11 10.2.4 EVALUATION 10.2-12 10.


==2.5 REFERENCES==
==2.5 REFERENCES==
10.2-13  
10.2-13  


10.0-i                        Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)   Section                                                  Page 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1 10.3.1 DESIGN BASES 10.3-1  10.3.1.1 Safety Design Bases 10.3-1 10.3.1.2 Power Generation Design Bases 10.3-2
10.0-i                        Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Section                                                  Page 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1  


10.3.2 SYSTEM DESCRIPTION 10.3-2  10.3.2.1 General Description 10.3-2 10.3.2.2 Component Description 10.3-3 10.3.2.3 System Operation 10.3-5 10.3.3 SAFETY EVALUATION 10.3-6 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-8
10.3.1 DESIGN BASES 10.3-1 10.3.1.1 Safety Design Bases 10.3-1 10.3.1.2 Power Generation Design Bases 10.3-2  


10.3.4.1 Preservice Valve Testing 10.3-8 10.3.4.2 Preservice System Testing 10.3-8 10.3.4.3 Inservice Testing 10.3-8 10.3.5 SECONDARY WATER CHEMISTRY (PWR) 10.3-9
10.3.2 SYSTEM DESCRIPTION 10.3-2 10.3.2.1 General Description 10.3-2 10.3.2.2 Component Description 10.3-3 10.3.2.3 System Operation 10.3-5


10.3.5.1 Chemistry Control Basis 10.3-9 10.3.5.2 Corrosion Control Effectiveness 10.3-10 10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-11
10.3.3 SAFETY EVALUATION 10.3-6 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-8


10.3.6.1 Fracture Toughness 10.3-11 10.3.6.2 Material Selection and Fabrication 10.3-11 10.4 OTHER FEATURES OF STEAM AND POWER CONVER- 10.4-1 SION SYSTEM  10.4.1 MAIN CONDENSERS 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 10.4-4 10.4.1.4 Tests and Inspections 10.4-4 10.4.1.5 Instrument Applications 10.4-4
10.3.4.1 Preservice Valve Testing 10.3-8 10.3.4.2 Preservice System Testing 10.3-8 10.3.4.3 Inservice Testing 10.3-8


10.0-ii                        Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)   Section                                                  Page  10.4.2 MAIN CONDENSER EVACUATION SYSTEM 10.4-5
10.3.5 SECONDARY WATER CHEMISTRY (PWR) 10.3-9


10.4.2.1 Design Bases 10.4-5 10.4.2.2 System Description 10.4-5 10.4.2.3 Safety Evaluation 10.4-7 10.4.2.4 Tests and Inspections 10.4-7 10.4.2.5 Instrumentation Applications 10.4-7 10.4.3 TURBINE GLAND SEALING SYSTEM 10.4-7 10.4.3.1 Design Bases 10.4-7 10.4.3.2 System Description 10.4-8 10.4.3.3 Safety Evaluation 10.4-9 10.4.3.4 Tests and Inspections 10.4-9 10.4.3.5 Instrumentation Applications 10.4-10  
10.3.5.1 Chemistry Control Basis 10.3-9 10.3.5.2 Corrosion Control Effectiveness 10.3-10  


10.4.4 TURBINE BYPASS SYSTEM 10.4-10 10.4.4.1 Design Bases 10.4-10  10.4.4.2 System Description 10.4-10 10.4.4.3 Safety Evaluation 10.4-12 10.4.4.4 Inspection and Testing Requirements 10.4-12 10.4.4.5 Instrumentation Applications 10.4-13 10.4.5 CIRCULATING WATER SYSTEM 10.4-13  
10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-11
 
10.3.6.1 Fracture Toughness 10.3-11 10.3.6.2 Material Selection and Fabrication 10.3-11
 
10.4 OTHER FEATURES OF STEAM AND POWER CONVER- 10.4-1 SION SYSTEM 10.4.1 MAIN CONDENSERS 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 10.4-4 10.4.1.4 Tests and Inspections 10.4-4 10.4.1.5 Instrument Applications 10.4-4
 
10.0-ii                        Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Section                                                  Page 10.4.2 MAIN CONDENSER EVACUATION SYSTEM 10.4-5
 
10.4.2.1 Design Bases 10.4-5 10.4.2.2 System Description 10.4-5 10.4.2.3 Safety Evaluation 10.4-7 10.4.2.4 Tests and Inspections 10.4-7 10.4.2.5 Instrumentation Applications 10.4-7
 
10.4.3 TURBINE GLAND SEALING SYSTEM 10.4-7
 
10.4.3.1 Design Bases 10.4-7 10.4.3.2 System Description 10.4-8 10.4.3.3 Safety Evaluation 10.4-9 10.4.3.4 Tests and Inspections 10.4-9 10.4.3.5 Instrumentation Applications 10.4-10
 
10.4.4 TURBINE BYPASS SYSTEM 10.4-10  
 
10.4.4.1 Design Bases 10.4-10  10.4.4.2 System Description 10.4-10 10.4.4.3 Safety Evaluation 10.4-12 10.4.4.4 Inspection and Testing Requirements 10.4-12 10.4.4.5 Instrumentation Applications 10.4-13 10.4.5 CIRCULATING WATER SYSTEM 10.4-13  


10.4.5.1 Design Bases 10.4-13 10.4.5.2 System Description 10.4-14 10.4.5.3 Safety Evaluation 10.4-15 10.4.5.4 Tests and Inspections 10.4-16 10.4.5.5 Instrumentation Applications 10.4-16  
10.4.5.1 Design Bases 10.4-13 10.4.5.2 System Description 10.4-14 10.4.5.3 Safety Evaluation 10.4-15 10.4.5.4 Tests and Inspections 10.4-16 10.4.5.5 Instrumentation Applications 10.4-16  


10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-16 10.4.6.1 Design Bases 10.4-17 10.4.6.2 System Description 10.4-17 10.4.6.3 Safety Evaluation 10.4-20 10.4.6.4 Tests and Inspections 10.4-21 10.4.6.5 Instrumentation Applications 10.4-21 10.4.7 CONDENSATE AND FEEDWATER SYSTEM 10.4-21  
10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-16 10.4.6.1 Design Bases 10.4-17 10.4.6.2 System Description 10.4-17 10.4.6.3 Safety Evaluation 10.4-20 10.4.6.4 Tests and Inspections 10.4-21 10.4.6.5 Instrumentation Applications 10.4-21  
 
10.4.7 CONDENSATE AND FEEDWATER SYSTEM 10.4-21  
 
10.4.7.1 Design Bases 10.4-21 10.4.7.2 System Description 10.4-23 
 
10.0-iii                    Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Section                                                  Page 10.4.7.3 Safety Evaluation 10.4-30 10.4.7.4 Tests and Inspections 10.4-31 10.4.7.5 Instrumentation Applications 10.4-32 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-34
 
10.4.8.1 Design Bases 10.4-34 10.4.8.2 System Description 10.4-35  10.4.8.3 Radioactive Releases 10.4-44  10.4.8.4 Safety Evaluation 10.4-44 10.4.8.5 Tests and Inspections 10.4-45 10.4.8.6 Instrumentation Applications 10.4-46
 
10.4.9 AUXILIARY FEEDWATER SYSTEM 10.4-46
 
10.4.9.1 Design Bases 10.4-46 10.4.9.2 System Description 10.4-48 10.4.9.3 Safety Evaluation 10.4-51 10.4.9.4 Tests and Inspections 10.4-53 10.4.9.5 Instrumentation Applications 10.4-53
 
10.4.10 SECONDARY LIQUID WASTE SYSTEM 10.4-53
 
10.4.10.1 Design Bases 10.4-54 10.4.10.2 System Description 10.4-54 10.4.10.3 Safety Evaluation 10.4-60 10.4.10.4 Tests and Inspections 10.4-60 10.4.10.5 Instrumentation Applications 10.4-60
 
10.0-iv                  Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
LIST OF TABLES
 
Number                                Title
 
10.1-1 Summary of Important Design Features and Performance Characteristics of the Steam and  Power Conversion System 
 
10.2-1 Events Following Loss of Turbine Load with Postulated Equipment Failures 
 
10.3-1 Main Steam Supply System Control, Indicating,  and Alarm Devices 
 
10.3-2 Main Steam Supply System Design Data 
 
10.3-3 Main Steam System Single Active Failure Analysis
 
10.3-4 Deleted
 
10.4-1 Condenser Design Data
 
10.4-2 Main Condenser Air Removal System Design Data
 
10.4-3 Circulating Water System Component Description
 
10.4-4 Condensate Demineralization System Design
 
Data 10.4-5 Condensate and Feedwater System Component  Failure Analysis
 
10.4-6 Condensate and Feedwater System Design Data 
 
10.4-7 Feedwater Isolation Single Failure Analysis
 
10.4-8 Main Feedwater System Control, Indicating, and Alarm Devices
 
10.4-9 Steam Generator Blowdown System Major  Component Parameters
 
10.4-10 Steam Generator Blowdown System Single Active Failure Analysis
 
10.4-11 Steam Generator Blowdown System Control,  Indicating, and Alarm Devices
 
10.0-v                    Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Number                                  Title 10.4-12 Auxiliary Feedwater System Component Data
 
10.4-13 Auxiliary Feedwater System Single Active    Failure Analysis 
 
10.4-13A Design Comparisons to Recommendations of  Standard Review Plan 10.4.9 Revision 1, "Auxiliary Feedwater System (PWR)" and Branch  Technical Position ASB 10-1 Revision 1,  "Design Guidelines for Auxiliary Feedwater System Pump Drive and Power Supply Diversity for Pressurized Water Reactor Plant"  10.4-13B Design Comparisons to NRC Recommendations on  Auxiliary Feedwater Systems Contained in the  March 10, 1980 NRC Letter
 
10.4-14 Auxiliary Feedwater System Indicating, Alarm,  and Control Devices 
 
10.4-15 Secondary Liquid Waste System - Component Data   
 
10.0-vi                Rev. 29
 
WOLF CREEK CHAPTER 10 - LIST OF FIGURES
*Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference.
Figure# Sheet Title Drawing #* 10.1-1 0 Steam and Power Conversion System 10.1-2 0 Turbine Cycle Heat Balance 100 Percent of Manufacturer's Guaranteed Rating 10.1-3 0 Turbine Cycle Heat Balance Valves Wide Open 105 Percent of Manufacturer's Guaranteed  Rating 10.1-4 0 Turbine Cycle Heat Balance-104.5% Thermal Power Uprate and 0 F T HOT Reduction, 1% Steam Generator Blowdown  10.2-1 1 Main Turbine M-12AC01 10.2-1 2 Main Turbine M-12AC02 10.2-1 3 Main Turbine M-12AC03 10.2-1 4 Main Turbine M-12AC04 10.2-1 5 Lube Oil Storage, Transfer and Purification System M-12CF01 10.2-1 6 Lube Oil Storage, Transfer and Purification System M-12CF02 10.2-1 7 Main Turbine Control Oil System M-12CH01 10.2-1 8 Main Turbine Control Oil System M-12CH02 10.3-1 1 Main Steam System M-12AB01 10.3-1 2 Main Steam System M-12AB02 10.3-1 3 Main Steam System M-12AB03 10-3-2 1 Main Steam System 10.4-1 1 Circulating Water & Waterbox Drains System M-12DA01 10.4-1 2 Circulating Water System M-0021 10.4-1 3 Circulating Water Waterbox Venting System M-12DA02 10.4-1 4 Circulating Water Screenhouse Plans M-0004 10.4-1 5 Circulating Water Screenhouse - Sections M-0005 10.4-2 1 Condensate System M-12AD01 10.4-2 2 Condensate System M-12AD02 10.4-2 3 Condensate System M-12AD03 10.4-2 4 Condensate System M-12AD04 10.4-2 5 Condensate System M-12AD05 10.4-2 6 Condensate System M-12AD06 10.4-3 0 Condenser Air Removal M-12CG01 10.4-4 0 Steam Seal System M-12CA01 10.4-5 1 Condensate Demineralizer System M-12AK01 10.4-5 2 Condensate Demineralizer System M-12AK02 10.4-5 3 Condensate Demineralizer System M-12AK03 10.4-6 1 Feedwater System M-12AE01 10.4-6 2 Feedwater System M-12AE02 10.4-6 3 Feedwater Heater Extraction Drains & Vents M-12AF01 10.4-6 4 Feedwater Heater Extraction Drains & Vents M-12AF02 10.4-6 5 Feedwater Heater Extraction Drains & Vents M-12AF03 10.4-6 6 Feedwater Heater Extraction Drains & Vents M-12AF04 
 
10.0-vii    Rev. 29 WOLF CREEK CHAPTER 10 - LIST OF FIGURES
*Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference.
Figure# Sheet TitleDrawing #*
10.4-6 7 Auxiliary Turbines S.G.F.P. Turbine "A" M-12FC03 10.4-6 8 Auxiliary Turbines S.G.F.P. Turbine "B" M-12FC04 10.4-7 1 Condensate Chemical Addition System M-12AQ01 10.4-7 2 Feedwater Chemical Addition System M-12AQ02 10.4-8 1 Steam Generator Blowdown System M-12BM01 10.4-8 2 Steam Generator Blowdown System M-12BM02 10.4-8 3 Steam Generator Blowdown System M-12BM03 10.4-8 4 Steam Generator Blowdown System M-12BM04 10.4-8 5 Steam Generator Blowdown System M-12BM05 10.4-9 0 Auxiliary Feedwater System M-12AL01 10.4-10 0 Auxiliary Turbines Auxiliary Feedwater Pump Turbine M-12FC02 10.4-11 0 Deleted 10.4-12 1 Secondary Liquid Waste System M-12HF01 10.4-12 2 Secondary Liquid Waste System M-12HF02 10.4-12 3 Secondary Liquid Waste System M-12HF03 10.4-12 4 Secondary Liquid Waste System M-12HF04 


10.4.7.1 Design Bases 10.4-21 10.4.7.2 System Description 10.4-23   
10.0-viii    Rev. 17 WOLF CREEK CHAPTER 10.0 STEAM AND POWER CONVERSION SYSTEM 10.1 


10.0-iii                    Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)  Section                                                  Page  10.4.7.3 Safety Evaluation 10.4-30 10.4.7.4 Tests and Inspections 10.4-31 10.4.7.5 Instrumentation Applications 10.4-32  10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-34
==SUMMARY==
DESCRIPTION The steam and power conversion system is designed to remove heat energy from the reactor coolant in the four steam generators and convert it to electrical energy. The system includes the main steam system, the turbine-generator, the main condenser, the condensate system, the feedwater system, and other auxiliary systems. The turbine cycle is a closed cycle with water as the working fluid. Two stages of reheat and seven stages of regeneration are included in the cycle. The heat input is provided by reactor coolant in the steam generators. Work is performed by the expansion of the steam in the high and low pressure turbines. Steam is condensed and waste heat is rejected by the main condenser. The condensate and feedwater systems preheat and  


10.4.8.1 Design Bases 10.4-34 10.4.8.2 System Description 10.4-35  10.4.8.3 Radioactive Releases 10.4-44  10.4.8.4 Safety Evaluation 10.4-44 10.4.8.5 Tests and Inspections 10.4-45 10.4.8.6 Instrumentation Applications 10.4-46 10.4.9 AUXILIARY FEEDWATER SYSTEM 10.4-46 10.4.9.1 Design Bases 10.4-46 10.4.9.2 System Description 10.4-48 10.4.9.3 Safety Evaluation 10.4-51 10.4.9.4 Tests and Inspections 10.4-53 10.4.9.5 Instrumentation Applications 10.4-53
pressurize the water and return it to the steam generators, thereby closing the cycle.Figure 10.1-1 is an overall flow diagram of the steam and power conversion system. Table 10.1-1 gives the major design and performance data of the system and its major components. Heat balances at manufacturer's rated power and valves wide open (VWO) power are included as Figures 10.1-2 and 10.1-3, respectively. An estimated heat balance at the power rerate target operating condition (104.5% Thermal Power Up Rate and 0 F T HOT Reduction) is included as Figure 10.1-4.
The safety related design features are discussed in the sections of Chapter 10 which are devoted to the individual systems comprising the steam and power conversion system.
10.1.1 GENERAL DISCUSSION The main steam system supplies steam to the high pressure turbine and the second stage of steam reheating. The steam is expanded in the high pressure turbine. High pressure turbine extraction steam supplies the first stage of steam reheating and the sixth and seventh stage feedwater heaters. High pressure turbine exhaust steam is fed to the combined moisture separator


10.4.10 SECONDARY LIQUID WASTE SYSTEM 10.4-53 10.4.10.1 Design Bases 10.4-54 10.4.10.2 System Description 10.4-54 10.4.10.3 Safety Evaluation 10.4-60 10.4.10.4 Tests and Inspections 10.4-60 10.4.10.5 Instrumentation Applications 10.4-60 
reheaters (MSRs) and the fifth stage feedwater heaters. Steam is dried and superheated in the MSRs before it is supplied to the low pressure turbines and to the steam generator feedwater pump (SGFP) turbines. Extraction steam from the low pressure turbines supplies the low pressure feedwater heaters. The steam generator blowdown (SGB) flash tank steam is fed to the fifth stage


10.0-iv                  Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)                                 LIST OF TABLES Number                                Title 10.1-1 Summary of Important Design Features and Performance Characteristics of the Steam and  Power Conversion System 10.2-1 Events Following Loss of Turbine Load with Postulated Equipment Failures 10.3-1 Main Steam Supply System Control, Indicating,  and Alarm Devices  
feedwater heaters.
Exhaust steam from the low pressure turbines is condensed and deaerated in the main condenser. Volume change in the secondary side fluid is handled by the surge capacity of the condensate storage tank. Heating of the condensate first occurs in the 10.1-1 Rev. 18 WOLF CREEK reheating hotwells of the main condenser; the heating system is the SGFP turbine exhaust. Condensate is pumped from the condenser hotwells by the main condensate pumps through the condensate demineralizers (when in service) and the low pressure feedwater heaters to the suction of the SGFP. A portion of the condensate is directed to the SGB regenerative heat exchanger to recover additional heat while cooling the blowdown. The heater drain pumps feed the suction of the SGFPs from the heater drain tank. Feedwater is pumped through the high pressure feedwater heaters to the steam generators by means of the SGFPs.10.1.2 PROTECTIVE FEATURES


10.3-2 Main Steam Supply System Design Data 10.3-3 Main Steam System Single Active Failure Analysis
10.1.2.1  Loss of External Electrical Load and/or Turbine Trip Load rejection capabilities of the steam and power conversion systems are discussed in Section 10.3.
10.1.2.2 Overpressure Protection Overpressure protection for the steam generators is discussed in Section 10.3.
The following components are provided with overpressure protection in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII:
: a. MSRs
: b. Low pressure feedwater heaters
: c. High pressure feedwater heaters
: d. Heater drain tank
: e. SGB flash tank
: f. SGB regenerative heat exchanger 10.1.2.3 Loss of Main Feedwater Flow Loss of main feedwater flow is discussed in Section 10.4.9.
10.1.2.4 Turbine Overspeed Protection Turbine overspeed protection is discussed in Section 10.2.2.3 and 3.5.1.3.


10.3-4 Deleted 10.4-1 Condenser Design Data 10.4-2 Main Condenser Air Removal System Design Data
10.1.2.5  Turbine Missile Protection Turbine missile protection is discussed in Sections 10.2.3 and 3.5.1.2. 10.1-2 Rev. 18 WOLF CREEK 10.1.2.6  Radioactivity Under normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system. It is possible for this system to become contaminated by a steam generator tube leakage. In this event, radiological monitoring of the main condenser air removal system


10.4-3 Circulating Water System Component  Description 10.4-4 Condensate Demineralization System Design Data 10.4-5 Condensate and Feedwater System Component  Failure Analysis
and the steam generator blowdown system, as described in Section 11.5, will


10.4-6 Condensate and Feedwater System Design Data 10.4-7 Feedwater Isolation Single Failure Analysis 10.4-8 Main Feedwater System Control, Indicating, and Alarm Devices 10.4-9 Steam Generator Blowdown System Major  Component Parameters
detect contamination.
Equilibrium secondary system activities, based on assumed primary-to-secondary side leakages, are developed in Chapter 11.0. The steam generator blowdown


10.4-10 Steam Generator Blowdown System Single Active Failure Analysis 10.4-11 Steam Generator Blowdown System Control,  Indicating, and Alarm Devices
system and the condensate demineralizer system serve to limit the radioactivity


10.0-v                    Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)  Number                                  Title  10.4-12 Auxiliary Feedwater System Component Data
level in the secondary cycle, as described in Sections 10.4.6 and 10.4.8.      10.1-3    Rev. 0 WOLF CREEK TABLE 10.1-1


10.4-13 Auxiliary Feedwater System Single Active    Failure Analysis 10.4-13A Design Comparisons to Recommendations of Standard Review Plan 10.4.9 Revision 1, "Auxiliary Feedwater System (PWR)" and Branch  Technical Position ASB 10-1 Revision 1,   "Design Guidelines for Auxiliary Feedwater System Pump Drive and Power Supply Diversity for Pressurized Water Reactor Plant" 10.4-13B Design Comparisons to NRC Recommendations on Auxiliary Feedwater Systems Contained in the  March 10, 1980 NRC Letter 10.4-14 Auxiliary Feedwater System Indicating, Alarm,   and Control Devices 10.4-15 Secondary Liquid Waste System - Component  Data   
==SUMMARY==
OF IMPORTANT DESIGN FEATURES AND PERFORMANCE CHARACTERISTICS OF THE STEAM AND POWER CONVERSION SYSTEM Nuclear Steam Supply System, Full Power Operation Rated NSSS power, MWt 3,425 Steam generator outlet pressure, psia 1,000 Steam generator inlet feedwater temp, F 444.5 Steam generator outlet steam moisture, % 0.25 Quantity of steam generators per unit 4  Flow rate per steam generator, 10 6 lb/hr 3.785 Nuclear Steam Supply System, Target Power Rerate Operation (104.5% Thermal Power Up Rate and 0 F T HOT Reduction)
NSSS power, MW (th) 3,579  Steam Generator outlet pressure, psia 970 Steam Generator inlet feedwater temp, °F 446 Steam Generator outlet steam moisture, % 0.25  Flow rate per steam generator, 10 6 lb/hr 3.98


10.0-vi                Rev. 29 WOLF CREEK  CHAPTER 10 - LIST OF FIGURES *Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference. Figure# Sheet Title Drawing #* 10.1-1 0 Steam and Power Conversion System 10.1-2 0 Turbine Cycle Heat Balance 100 Percent of Manufacturer's Guaranteed Rating  10.1-3 0 Turbine Cycle Heat Balance Valves Wide Open 105 Percent of Manufacturer's Guaranteed  Rating  10.1-4 0 Turbine Cycle Heat Balance-104.5% Thermal Power Uprate and 0F THOT Reduction, 1% Steam Generator Blowdown  10.2-1 1 Main Turbine M-12AC01 10.2-1 2 Main Turbine M-12AC02 10.2-1 3 Main Turbine M-12AC03 10.2-1 4 Main Turbine M-12AC04 10.2-1 5 Lube Oil Storage, Transfer and Purification System M-12CF01 10.2-1 6 Lube Oil Storage, Transfer and Purification System M-12CF02 10.2-1 7 Main Turbine Control Oil System M-12CH01 10.2-1 8 Main Turbine Control Oil System M-12CH02 10.3-1 1 Main Steam System M-12AB01 10.3-1 2 Main Steam System M-12AB02 10.3-1 3 Main Steam System M-12AB03 10-3-2 1 Main Steam System  10.4-1 1 Circulating Water & Waterbox Drains System M-12DA01 10.4-1 2 Circulating Water System M-0021 10.4-1 3 Circulating Water Waterbox Venting System M-12DA02 10.4-1 4 Circulating Water Screenhouse Plans M-0004 10.4-1 5 Circulating Water Screenhouse - Sections M-0005 10.4-2 1 Condensate System M-12AD01 10.4-2 2 Condensate System M-12AD02 10.4-2 3 Condensate System M-12AD03 10.4-2 4 Condensate System M-12AD04 10.4-2 5 Condensate System M-12AD05 10.4-2 6 Condensate System M-12AD06 10.4-3 0 Condenser Air Removal M-12CG01 10.4-4 0 Steam Seal System M-12CA01 10.4-5 1 Condensate Demineralizer System M-12AK01 10.4-5 2 Condensate Demineralizer System M-12AK02 10.4-5 3 Condensate Demineralizer System M-12AK03 10.4-6 1 Feedwater System M-12AE01 10.4-6 2 Feedwater System M-12AE02 10.4-6 3 Feedwater Heater Extraction Drains & Vents M-12AF01 10.4-6 4 Feedwater Heater Extraction Drains & Vents M-12AF02 10.4-6 5 Feedwater Heater Extraction Drains & Vents M-12AF03 10.4-6 6 Feedwater Heater Extraction Drains & Vents M-12AF04 
Nuclear Steam Supply System, Reduced Thermal Design Flow Operation


10.0-vii    Rev. 29 WOLF CREEK CHAPTER 10 - LIST OF FIGURES *Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference. Figure# Sheet TitleDrawing #*10.4-6 7 Auxiliary Turbines S.G.F.P. Turbine "A" M-12FC03 10.4-6 8 Auxiliary Turbines S.G.F.P. Turbine "B" M-12FC04 10.4-7 1 Condensate Chemical Addition System M-12AQ01 10.4-7 2 Feedwater Chemical Addition System M-12AQ02 10.4-8 1 Steam Generator Blowdown System M-12BM01 10.4-8 2 Steam Generator Blowdown System M-12BM02 10.4-8 3 Steam Generator Blowdown System M-12BM03 10.4-8 4 Steam Generator Blowdown System M-12BM04 10.4-8 5 Steam Generator Blowdown System M-12BM05 10.4-9 0 Auxiliary Feedwater System M-12AL01 10.4-10 0 Auxiliary Turbines Auxiliary Feedwater Pump Turbine M-12FC02 10.4-11 0 Deleted  10.4-12 1 Secondary Liquid Waste System M-12HF01 10.4-12 2 Secondary Liquid Waste System M-12HF02 10.4-12 3 Secondary Liquid Waste System M-12HF03 10.4-12 4 Secondary Liquid Waste System M-12HF04 
NSSS power, MW (th) 3,579 Steam Generator outlet pressure, psia 944  Steam Generator inlet feedwater temp, °F 446 Steam Generator outlet steam moisture, % 0.25 Flow rate per steam generator, 10 6 lb/hr 3.98 Turbine Generator


10.0-viii   Rev. 17 WOLF CREEK CHAPTER 10.0STEAM AND POWER CONVERSION SYSTEM10.1 SUMMARY DESCRIPTIONThe steam and power conversion system is designed to remove heat energy from the reactor coolant in the four steam generators and convert it to electrical energy. The system includes the main steam system, the turbine-generator, the main condenser, the condensate system, the feedwater system, and other auxiliary systems. The turbine cycle is a closed cycle with water as the working fluid. Two stages of reheat and seven stages of regeneration are included in the cycle. The heat input is provided by reactor coolant in the steam generators. Work is performed by the expansion of the steam in the high and low pressure turbines. Steam is condensed and waste heat is rejected by the main condenser. The condensate and feedwater systems preheat and pressurize the water and return it to the steam generators, thereby closing the cycle.Figure 10.1-1 is an overall flow diagram of the steam and power conversion system. Table 10.1-1 gives the major design and performance data of the system and its major components. Heat balances at manufacturer's rated power and valves wide open (VWO) power are included as Figures 10.1-2 and 10.1-3, respectively. An estimated heat balance at the power rerate target operating condition (104.5% Thermal Power Up Rate and 0F THOT Reduction) is included as Figure 10.1-4. The safety related design features are discussed in the sections of Chapter 10 which are devoted to the individual systems comprising the steam and power conversion system. 10.1.1  GENERAL DISCUSSION The main steam system supplies steam to the high pressure turbine and the second stage of steam reheating. The steam is expanded in the high pressure turbine. High pressure turbine extraction steam supplies the first stage of steam reheating and the sixth and seventh stage feedwater heaters. High pressure turbine exhaust steam is fed to the combined moisture separator reheaters (MSRs) and the fifth stage feedwater heaters. Steam is dried and superheated in the MSRs before it is supplied to the low pressure turbines and to the steam generator feedwater pump (SGFP) turbines. Extraction steam from the low pressure turbines supplies the low pressure feedwater heaters. The steam generator blowdown (SGB) flash tank steam is fed to the fifth stage feedwater heaters. Exhaust steam from the low pressure turbines is condensed and deaerated in the main condenser. Volume change in the secondary side fluid is handled by the surge capacity of the condensate storage tank. Heating of the condensate first occurs in the 10.1-1 Rev. 18 WOLF CREEK reheating hotwells of the main condenser; the heating system is the SGFP turbine exhaust. Condensate is pumped from the condenser hotwells by the main condensate pumps through the condensate demineralizers (when in service) and the low pressure feedwater heaters to the suction of the SGFP. A portion of the condensate is directed to the SGB regenerative heat exchanger to recover additional heat while cooling the blowdown. The heater drain pumps feed the suction of the SGFPs from the heater drain tank. Feedwater is pumped through the high pressure feedwater heaters to the steam generators by means of the SGFPs.10.1.2  PROTECTIVE FEATURES 10.1.2.1  Loss of External Electrical Load and/or Turbine TripLoad rejection capabilities of the steam and power conversion systems are discussed in Section 10.3. 10.1.2.2 Overpressure ProtectionOverpressure protection for the steam generators is discussed in Section 10.3.The following components are provided with overpressure protection in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII:      a. MSRs      b. Low pressure feedwater heaters c. High pressure feedwater heaters      d. Heater drain tank      e. SGB flash tank      f. SGB regenerative heat exchanger 10.1.2.3  Loss of Main Feedwater FlowLoss of main feedwater flow is discussed in Section 10.4.9. 10.1.2.4  Turbine Overspeed ProtectionTurbine overspeed protection is discussed in Section 10.2.2.3 and 3.5.1.3.
Secondary Power Uprate   Rating, MWe 1268 Turbine type Tandem compound six flow, 1 high pressure turbine,  3 low pressure turbines  Operating speed, rpm 1,800 Number of stages 16 Moisture Separator Reheater (MSR)  
10.1.2.5  Turbine Missile ProtectionTurbine missile protection is discussed in Sections 10.2.3 and 3.5.1.2. 10.1-2 Rev. 18 WOLF CREEK 10.1.2.6  RadioactivityUnder normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system. It is possible for this system to become contaminated by a steam generator tube leakage. In this event, radiological monitoring of the main condenser air removal system and the steam generator blowdown system, as described in Section 11.5, will detect contamination. Equilibrium secondary system activities, based on assumed primary-to-secondary side leakages, are developed in Chapter 11.0. The steam generator blowdown system and the condensate demineralizer system serve to limit the radioactivity level in the secondary cycle, as described in Sections 10.4.6 and 10.4.8.      10.1-3    Rev. 0 WOLF CREEK TABLE 10.1-1 SUMMARY OF IMPORTANT DESIGN FEATURES AND PERFORMANCE CHARACTERISTICS OF THE STEAM AND POWER CONVERSION SYSTEM  Nuclear Steam Supply System, Full Power Operation  Rated NSSS power, MWt 3,425 Steam generator outlet pressure, psia 1,000 Steam generator inlet feedwater temp, F 444.5 Steam generator outlet steam moisture, % 0.25 Quantity of steam generators per unit 4  Flow rate per steam generator, 106 lb/hr 3.785  Nuclear Steam Supply System, Target Power Rerate Operation (104.5% Thermal Power Up Rate and 0F THOT Reduction)  NSSS power, MW(th) 3,579  Steam Generator outlet pressure, psia 970  Steam Generator inlet feedwater temp, °F 446  Steam Generator outlet steam moisture, % 0.25  Flow rate per steam generator, 106 lb/hr 3.98 Nuclear Steam Supply System, Reduced Thermal Design Flow Operation NSSS power, MW(th) 3,579  Steam Generator outlet pressure, psia 944  Steam Generator inlet feedwater temp, °F 446 Steam Generator outlet steam moisture, % 0.25 Flow rate per steam generator, 106 lb/hr 3.98  Turbine Generator


Secondary Power Uprate    Rating, MWe 1268  Turbine type Tandem compound  six flow,  1 high pressure  turbine,  3 low pressure  turbines  Operating speed, rpm 1,800  Number of stages 16  Moisture Separator Reheater (MSR)
Stages of reheat 2  Stages of moisture separation 1  Quantity of MSRs per unit 4  
Stages of reheat 2  Stages of moisture separation 1  Quantity of MSRs per unit 4  


Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 2)  Main Condenser  
Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 2)
Main Condenser
 
Type Multiple pressure,  3-shell Quantity, per unit 1  Condensing capacity, Btu/hr 7.87 x 10 9  Circulating water flow rate See Section 10.4.5 Circulating water temperature rise See Section 10.4.5
 
Condenser Vacuum Pumps
 
Type Rotary, motor driven,  water sealed  Hogging capacity, each, std. Cfm 72 @ 5 in. Hga  Holding capacity, each, std. Cfm 35 @ 1 in. Hga  Pump speed, rpm 435 Motor hp, each 150 Motor speed, rpm 1,800 Quantity, per unit 3 Condensate Pumps


Type Multiple pressure,  3-shell  Quantity, per unit 1  Condensing capacity, Btu/hr 7.87 x 109  Circulating water flow rate See Section 10.4.5 Circulating water temperature rise See Section 10.4.5 Condenser Vacuum Pumps Type Rotary, motor driven, water sealed  Hogging capacity, each, std. Cfm 72 @ 5 in. Hga  Holding capacity, each, std. Cfm 35 @ 1 in. Hga Pump speed, rpm 435 Motor hp, each 150 Motor speed, rpm 1,800 Quantity, per unit 3 Condensate Pumps
Type Vertical,   centrifugal motor driven  Design Conditions Flow, gpm 7,266 Total head, ft 1,285 Motor hp 3,500  Quantity per unit 3  


Type Vertical,    centrifugal  motor driven  Design Conditions Flow, gpm 7,266 Total head, ft 1,285  Motor hp 3,500  Quantity per unit 3 Feedwater Heaters  
Feedwater Heaters  


Low Pressure Design Primary and      Secondary Power    Uprates  a. No. 1  Quantity per unit 3 3 Duty, Btu/hr 2.056 x 108 2.42 x 108 b. No. 2 Quantity per unit 3 3 Duty, Btu/hr 1.262 x 108 1.31 x 108   c. No. 3  Quantity per unit 3 3  Duty, Btu/hr 2.425 x 108 2.30 x 108 d. No. 4  Quantity per unit 3 3  Duty, Btu/hr 1.276 x 108 1.22 x 108 Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 3) High Pressure Design Primary and  Secondary Power Uprates  e. No. 5 Quantity per unit 2 2  Duty, Btu/hr 2.415 x 108 2.40 x 108   f. No. 6 Quantity per unit 2 2 Duty, Btu/hr 3.259 x 108 3.38 x 108 g. No. 7 Quantity per unit 2 2 Duty, Btu/hr 3.354 x 108 3.45 x 108 Steam Generator Feedwater Pumps   Pump type Horizontal, centrifugal  Turbine type Multistage    noncondensing  Quantity per unit 2  
Low Pressure Design Primary and      Secondary Power    Uprates  a. No. 1  Quantity per unit 3 3 Duty, Btu/hr 2.056 x 10 8 2.42 x 10 8
: b. No. 2 Quantity per unit 3 3 Duty, Btu/hr 1.262 x 10 8 1.31 x 10 8   c. No. 3  Quantity per unit 3 3  Duty, Btu/hr 2.425 x 10 8 2.30 x 10 8
: d. No. 4  Quantity per unit 3 3  Duty, Btu/hr 1.276 x 10 8 1.22 x 10 8
Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 3)
High Pressure Design Primary and  Secondary Power Uprates  e. No. 5 Quantity per unit 2 2  Duty, Btu/hr 2.415 x 10 8 2.40 x 10 8   f. No. 6 Quantity per unit 2 2 Duty, Btu/hr 3.259 x 10 8 3.38 x 10 8
: g. No. 7 Quantity per unit 2 2 Duty, Btu/hr 3.354 x 10 8 3.45 x 10 8 Steam Generator Feedwater Pumps Pump type Horizontal, centrifugal  Turbine type Multistage    noncondensing  Quantity per unit 2  


Design conditions, pump Flow, gpm 17,620  Total head, ft 2,387  Turbine hp @ 5,560 rpm 14,328  
Design conditions, pump Flow, gpm 17,620  Total head, ft 2,387  Turbine hp @ 5,560 rpm 14,328  


Motor-Driven Feedwater Pump Type Horizontal,    centrifugal Motor driven  Design conditions Flow, gpm 480  Total head, ft 1,820  Motor hp 300 Quantity per unit 1
Motor-Driven Feedwater Pump  


Heater Drain Pumps  Type Vertical, centrifugal Motor driven  Design conditions Flow, gpm 5,670  Total head, ft 910  Motor hp 1,500 Quantity per unit 2
Type Horizontal,   centrifugal  


Steam Generator Blowdown Regenerative Heat Exchanger  Duty, Btu/hr 26.64 x 1O6 Quantity per unit 1  
Motor driven  Design conditions Flow, gpm 480  Total head, ft 1,820 Motor hp 300 Quantity per unit 1  


Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 4) Steam Generator Blowdown Flash Tank    Steaming rate, lb/hr                40,000-52,800      (max. blowdown)    Outlet steam pressure, psia          135-185 Quantity per unit                   1  Heater Drain Tank    Quantity per unit                    1    Operating pressure, psia            166.6
Heater Drain Pumps Type Vertical, centrifugal Motor driven Design conditions Flow, gpm 5,670  Total head, ft 910  Motor hp 1,500 Quantity per unit 2


Rev. 13
Steam Generator Blowdown Regenerative Heat Exchanger Duty, Btu/hr 26.64 x 1O 6  Quantity per unit 1
..................... , . -....... I' L CJ L-, corf!Xor;.:.tt t>u"*a .. I 1 I Y0l<l (",,,, I ... ! LEGEND ---ioTtA" --*tjD tuo*rrP. REV. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 10.1*1 STEAM AND POWER CONVERSION SYSTEM , ,., .. c LC0521-02 REV. 2 QQuncJtl ( cclrlc -hi* duc11*nl an4 :nhwn:allor !11 tE & Ptapddory lnfotnOIIOft. Ho part ol thh toc....-.nt Clld hlomatictl nio)' M reprodUc*d. htrtml :ht, *lthcut the prior "Htea pttmiU!:M'I oJ the t;tntrol Electric Corpany. P 11192.5 H .. , , T :I .. m.IT 1112.5 H 21'<l. <ihm:sH u :!: -_ _L---124!2167. u 0 0 i 21 0 ;;:-0 -0 .. 0 :l,: N n:g i. ,. ... ,/') . C) :2 _;uii :8-( 3 "I"' '"1! ..;.u N
 
* 7 ;:; L__ fROI cr 1.!1l.CV.Cii.IN ,-----, 274. I ' 409.? 1 T = FP ..i. "14.0 p STE,AII REHEATER .14.1. r ro 37 "'*x :!J;:i .., . '-.-----+_.J 131.6' -4S?.* J . "-, E f) ' I I -:::l z 0 s :::! :'77 '--" SG 3L]II)(I,\N HOlY VALVE BE5T FO:tiT Rl 6.0 TO 10.0 oc C0 15047817. : 1197 .. 1-47J.O I ! : :mJ = m:s : CENE.AL ElECTRIC CCioiPAN", SCH:NECTA)Y NY X a1 n @ BTU *YMO K\Hf! :r X o.6H-l.IJ ...,,. 9.0 1: J 1J.O X -.!!) "'1-"N N \IOLF CREEK WCLEAR a'ERATING COOP. WOLF CREEK JNIT 1 -TB. NO. 170X734 NEW HP DENSE PACK AND NEW 43" LSB LP STEA!APATH. OP'RATION AT 0.954 TfR WITH MAY 7010 PIMT DATA. O.OX F'EEOWATER BYPASS Of Ta' FYI HEAI::RS. NSS5 THERMAL PQIIER = 3579.0 t.f.\'1 !RATED PCM'ERJ. TU'!BINE THRODLE PRESSURE= 956.0 PSIA. THROTTLE ENTHALPY = 11n.s BTUILEIJ. l'(JJE: HEAl BAL,ING&#xa3; CALCULATIONS ARE BASED JELlA A.T '<ATEC N5SS POIIER Rf_AT IVE -o 8A5ELlNE' HEAT BALAN:: REV. I AND ARE ON A VALVE BEST BASIS. 1JR611&#xa3; :.NO EXHACTI!ll .\P.R.ItlaENT IS SCIOA1:C lU THE VJ.lUE. 0' GENERA 1M CUTFLT SHl!li 00 I&#xa3;AT BJ.lAI+:E IS AFTER All PCllloR ftf! EX.CnTIOO All> C1ER Tmll1NE-<:&#xa3;N;1AT:R AIJXILIARIOS HAS BEEN DoD.X:1EO 10!89852. u 170.1 1268.0 H I P:v ......,=="+{8' [-------------(,fHFRATO! c:t.TPU1 KW n 6 a.. :ca..= AT1.00P::M&#xa3;RFACTOR FLO.V . IJJO 75.C PSIG H2 PRES ---N o.n >-a. BAS&#xa3;&#xa3;LEF= ,.::;1: -' N i i H a : :r : .:r: : 951.5 HAT '.5 1M t<<; .. :* ... H:XX>A ro:os t-o:Dc j :::_ 2.i .U M N 'J.I':lii/J'i. U if,"\ ,.., "-;: *.o R ELEP-H 93i.S H \: V l&#xa3;EP
Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 4)
Steam Generator Blowdown Flash Tank Steaming rate, lb/hr                40,000-52,800 (max. blowdown)
Outlet steam pressure, psia          135-185
 
Quantity per unit                    1 Heater Drain Tank Quantity per unit                    1 Operating pressure, psia            166.6
 
Rev. 13
 
..................... , .  
-....... I' L CJ L-, corf!Xor;.:.tt t>u"*a .. I 1 I Y 0 l<l (",,,, I ... ! LEGEND ---ioTtA" --
*tjD tuo*rrP. REV. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 10.1*1 STEAM AND POWER CONVERSION SYSTEM , ,., .. c LC0521-02 REV. 2 QQuncJt l ( c c lrlc -hi* duc 11*nl an4 :n h wn:allor !11 tE & P t apddory lnfo tnOIIOft.
Ho pa rt ol thh to c....-.nt Cll d hlo ma ti ctl nio)' M re p rodU c*d. h tr tml :h t,  
*lt h cut the prio r "Htea pttmiU!:M'I oJ the t;tntrol Electric Corpa ny. P 1 1192.5 H .. , , T :I .. m.I T 111 2.5 H 21'<l. <ihm:s H u :!: -
_ _L---1 2 4!2 1 67. u 0 0 i 21 0 ;;:-
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* 7 ;:; L__ fROI cr 1.!1l.CV.Cii.IN  
,-----, 274. I ' 409.? 1 T = F P ..i. "14.0 p STE,AII REHEAT ER .14.1. r ro 37 "'*x :!J;:i .., . '-.-----+_.J 1 31.6' -4 S?.* J . "-, E f) ' I I -:::l z 0 s :::! :'77 '--" SG 3L]II)(I,\N HOlY VALVE BE5 T FO:tiT R l 6.0 T O 10.0 oc C0 15047817.
: 1 1 97 .. 1-47J.O I !
: :mJ = m:s :
CE N E.AL ElEC T R I C CCioiPAN", SCH:NECTA)Y NY X a1 n @ BTU *YMO K\Hf! :r X o.6H-l.IJ ...,,. 9.0 1: J 1J.O X -.!!) "'1-"N N \IOLF CR EE K WC LE AR a'ERATING COOP. WOLF CR EE K JNIT 1 -TB. N O. 170X734 NEW HP DENS E PACK AND NEW 43" L S B L P ST E A!APATH. OP'RATION AT 0.954 TfR WITH MAY 70 1 0 PIMT DA T A. O.OX F'EEOWATER BYPASS Of Ta' FYI HEAI::RS.
NSS5 T H E RMAL PQIIER = 3579.0 t.f.\'1 !R A T ED PCM'ER J. TU'!BINE THRODLE PRESSURE=
956.0 PS I A. THROTTLE E NTHALPY = 1 1n.s BTUIL EIJ. l'(J J E: HEA l BA L ,ING&#xa3; CA L CU LAT IONS ARE BASED JELl A A.T '<ATEC N5SS POIIER Rf_AT I VE -o 8 A5ELl N E' H E A T BAL A N:: REV. I AND ARE ON A VALVE B EST BAS I S. 1JR6 11&#xa3; :.NO EXHAC T I!ll .\P.R.I t laENT I S SCIOA1:C lU THE VJ.l UE. 0' GENERA 1M CUTFLT SHl!li 00 I&#xa3;AT BJ.lAI+:E IS AFTE R All PCllloR f tf! EX.CnTIOO All> C1ER Tmll1NE-<:&#xa3;N;1AT:R AIJX ILI ARIOS HAS BEEN DoD.X:1 E O 10!89852.
u 170.1 1268.0 H I P:v ......,=="+{8'
[--
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---
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* 981.1 H 985.3 H 99 U H J"' "' . .... 16.6 p 774.
* 981.1 H 985.3 H 99 U H J"' "' . .... 16.6 p 774.
* 1 i':: ,.,, .... &#xa3; M I? I .., , I !fi 188.7 1 J.O TC ; 10.0 cc "':r .. .. v 2.05 Ill t'G 2.58 :1 HG 3.26 It, 1G CP !i LLfl.O p ;o r" 109C1SS9. M -,---0) 0.1 6 l[!DI) -CA1CIJLATI()I5 1!'.5&#xa3;0 ()I '967 /&E. STEAM TAUS 1272'05. I'IH 2.05 I 2.56/3.26 lt. 11:: A8S C.SC PCT loll M -I P -F)lESSlR&#xa3;-I'SIA : REV. 16/23/10 TC6f *3.1 lSB 1800 RPII PSIA UIL I liJ 2 SIAH CDI-140i000.KVA 0.!12 PF LIO 7S.C PS!C H2 PRES WOLF CREEK UPDATED SAFETY ANALYSIS REPORT REV.28 FIGURE 10.1-2 TURBINE CYCLE HEAT BALANCE 100 PERCENT OF ACTURER'S GUARANTEED RATING
* 1 i':: ,.,, .... &#xa3; M I? I .., , I !fi 1 88.7 1 J.O TC ; 10.0 cc "':r .. .. v 2.05 Ill t'G 2.58 :1 HG 3.26 It, 1G CP !i LLfl.O p  
:;! "' 0 51 "' ... ; 8: 0 0 ... S! ! (5 11 r.n571-01 RP.J. 1 t.Gtntrol [lactrle CQ'T9ont. This .iot<..fTWnl ond It GE Confl6tnllol t P*oprhlorr '4o pa*t of ttl* doclll'lllnt and 1nlo1n011onrmy bt rtproduced1 :ronnllttc, ttllh:.ut tttc )r'or triUcn pcminiar of the Gcnc*o E ectrlc C0'11111nJ. 727635. M "' 0 5A 13J29691. M 1061.0 H "r 1:77(107. ...: PSIA ':;' ---0.. (L_ c: .. _:_ ---r .. "' "' :;:; .;::. 2% J) &lio; L__ Gr FRCJ< SG 451.9 p :1= ":1" B_Oo\liOhN 2198!. , " ;:<SN * -o-Q 00 r----w ..... -':6 jg -161.. 7 p il lf't * .) I' 2 T 370.4 T " X 0 ;;; ,.r-.0 N _..: Ji'l-+'7""--"'---, -N FP = 6H=3.15 ;., r;p; 37 945.9 p u ;; % "' 10.0 DC %-,. .. "' flOW \!'! vAL;'[ BEST PO I NT If AT TE 15770107. i 1192.5-m.1 t 727!:.35. i 1192.5 .. .t6.1 t 99;:\.'i. i 1101.6 428.1 I 3TU 1319936.
;o r" 109C1SS9.
M -,---0) 0.1 6 l[!DI) -CA1CIJLATI()I5 1!'.5&#xa3;0 ()I '967 /&E. S TEAM TAUS 1272'05. I'IH 2.05 I 2.56/3.26 lt. 11:: A8S C.SC PC T loll M -I P -F)lESSlR&#xa3;-I'S I A :
REV. 1 6/23/10 TC6f *3.1 l SB 1800 RPII PSIA UIL I liJ 2 SIAH CDI-140i000.KVA 0.!12 PF L IO 7S.C PS!C H2 PRES WOLF CREEK UPDATED SAFETY ANALYSIS REPORT REV.28 FIGURE 1 0.1-2 TURBINE CYCLE HEAT BALANCE 1 00 PERCENT OF ACTURER'S GUARANTEED RATING
:;! "' 0 51 "' ... ; 8: 0 0 ... S! ! (5 1 1 r.n571-01 RP.J. 1 t.Gtntrol
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* CI<I:.I:.K NUCLI:.AH C!'I:.RA CORP. WO_' CREEK UNIT 1 -TB. NO. 170X73L NEW HP DENSE PACK AND NEW 43" LSB LP STEAMPATH. WiO UJ/IIl'ERATI(}I VIITH W.Y 2010 PLANT DATA. 0.0% 'EEIJtliATER svPASS :lF TOP 3 FW HEATERS. NSSS THFRMAI PONFR = .l715.5 Mill. TURBINE -HROTTLE PRESSURE -956, 0 PSI II. TURBINE -HROTTLE EHHALPY = 1192.5 BTUILBM. NOTC: I OALANCC ARC GA5CD ON DCL TA 1/We AT RATED NSSS PCINER RELATIVE TO 3ASELINE HEAT BALANCE 1LG0521 30 REV. 1 ANC ARE ON A VALVE BEST !'OINT -uRSINE AND EXHACTIIl"l ARRNl:EIAENT IS SCHEMATIC ll"llY CALOJLATED DATA-tVT GUARNHEED RATlNG flON (5 150L7812. AT ll\l[T STCAI.! CIJIID:TIDJ!j CJ" '7SLD PSIA A.NO 11'72.5 II TO THE POSSIBILITY H\T THE TL!lBIN' WILL BE JNA3LE TO '.ISS RATING FLO/I BECIIUSE VA"AIIDNo IN VALUlS, :;tl!1' IUllW<<:tS ON ut<MIM>S, tiC, IHI: TIHAINf lo Rrltr. llt.ilr.NFO fill A IJF51f.N flClll IF 157701(7. U Tf&#xa3; VALUE or GENERATOR CUTFUT SJO\N ON TH:S HEAT SAL/INC&#xa3; IS AfTER All l'a'f:R FOR EXCITATIOtl N.C CTHER flAllllt&#xa3; GENERAICil AUXILIARIES HAS 3EEN DEOU::T&#xa3;0 224857. M 11061753. 177.9 1266.0 i [--__j!!'7J-9 -----------Xa_X CL 6 C.... :l:o.,.% 0: F .fM '! ;:;: :: _ __!f.;&sect;l .. 2 ; -GBIERATOR Jl TPUT <ti AT 1.00 FO'IoR fACTOR *4391. KW GoN LOSSES 1600. RPI.t ;Q IO.J OG _.,"' :&; .... ll'l ..... r<'\..... 'o/ ..&.. o;:c) ;'! :8.; :;: . .; ,g '6 ; g ;: ;:: \.:" -" 10.0 IJC ,.x-.N-.-v;,...: 2: LEGE NO -C.*.LCULA 11()15 BASED ON 1967 STEAU w -fla.i-_11/HR T -TEII'HITURE-f DEGREES " r 9.JS :I 190.
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i:'li "' CP 443.0 p :6.H=1.65 HCOO C 2870C51. N 982 .C H .3 H 3.26 :N I(;  12 72 105. 2.0 5 I 2.58 I J.26 : N I(; AilS 0.5 PCT 1IJ TC6F 43.0 IN .SB 1100 RP\1 15<1.0 P51A 1112.5 BTU /LB 2 STAGo GEN 1409000.KVA 0.112 PF LIO 75.C f>SIG H2 'RES '(t.V. I WOLF CREEK 06123/1: UPDATED SAFETY ANAL YSlS REPORT REV.28 FIGURE 10.1-3 TURBINE CYCLE HEAT BALANCE V AI.. VES WIDE OPEN 105 PERCENT OF ACTURER'S GUARANTEED RATING   
 
"This Figure has been Deleted"
 
Rev. 25 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 10.1-4 Turbine Cycle Heat Balance 104.5% Thermal Power Update and 0 &deg;F T HOT  Reduction 1% Steam Generator Blowdown
 
10.2  TURBINE GENERATOR The turbine generator (T-G) receives high pressure steam from the main steam system and converts a portion of its thermal energy into electrical energy. 
 
The T-G also supplies extraction steam and condensate for feedwater heating and
 
steam for driving the steam generator feedwater pump turbines.
 
During Refueling 18 (RF18), three replacement LP-steampaths comprised of rotors, inner casings and diaphragms, and a single HP steampath consisting of a rotor and diaphragms were installed. The last stage buckets for the LP rotors increased from 38" to 43". The new DensePack TM HP increased from 7-stages to 9-stages. Each rotor was manufactured by General Electric (GE) from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking, while increasing turbine efficiency.
To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. Therefore, the three LP turbines maintain their original stage numbering, starting with the 8 th stage. This allows all extraction locations to remain numbered per the original design.
10.2.1  DESIGN BASES 10.2.1.1  Safety Design Bases
 
The T-G serves no safety function and has no safety design basis.
 
10.2.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The T-G is intended for base load
 
operation. The gross generator outputs as rated reactor power and stretch of
 
valves wide open (VWO) power are given on Figures 10.1-2 and 10.1-3, respectively. The gross generator output at the power rerate operating condition is given on Figure 10.1-4.
 
POWER GENERATION DESIGN BASIS TWO - The T-G load change characteristics are
 
compatible with the instrumentation and control system which coordinates T-G and reactor operation.
 
POWER GENERATION DESIGN BASIS THREE - The T-G is designed to accept a sudden
 
loss of full load without exceeding design over-speed.
 
POWER GENERATION DESIGN BASIS FOUR - The T-G is designed to permit periodic testing of steam valves important to overspeed protection, emergency overspeed
 
trip circuits, and several other trip circuits under load.
 
POWER GENERATION DESIGN BASIS FIVE - The failure of any single component will
 
not cause the rotor speed to exceed the design speed.
POWER GENERATION DESIGN BASIS SIX - Unlimited access to all levels of the
 
turbine area under all operating conditions is provided.
 
10.2.2  SYSTEM DESCRIPTION 10.2.2.1  General Description The T-G system is shown in Figure 10.2-1. Performance characteristics are
 
provided in Section 10.1.
10.2-1                    Rev. 25 WOLF CREEK The turbine consists of double-flow, high-pressure, and low-pressure elements in tandem. Moisture separation and reheating of the steam are


"This Figure has been Deleted" 
provided between the high-pressure and low-pressure elements by four combined moisture separator reheater (MSR) assemblies. Two assemblies are located on each side of the T-G center-line. The generator is


Rev. 25WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 10.1-4  Turbine Cycle Heat Balance 104.5% Thermal Power Update and 0 &deg;F THOT  Reduction 1% Steam Generator Blowdown 10.2  TURBINE GENERATOR  The turbine generator (T-G) receives high pressure steam from the main steam system and converts a portion of its thermal energy into electrical energy.
coupled directly to the turbine shaft. It is equipped with an
The T-G also supplies extraction steam and condensate for feedwater heating and steam for driving the steam generator feedwater pump turbines.
During Refueling 18 (RF18), three replacement LP-steampaths comprised of rotors, inner casings and diaphragms, and a single HP steampath consisting of a rotor and diaphragms were installed. The last stage buckets for the LP rotors increased from 38" to 43". The new DensePackTM HP increased from 7-stages to 9-stages. Each rotor was manufactured by General Electric (GE) from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking, while increasing turbine efficiency. To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. Therefore, the three LP turbines maintain their original stage numbering, starting with the 8th stage. This allows all extraction locations to remain numbered per the original design.
10.2.1  DESIGN BASES  10.2.1.1  Safety Design Bases The T-G serves no safety function and has no safety design basis.
10.2.1.2  Power Generation Design Bases  POWER GENERATION DESIGN BASIS ONE - The T-G is intended for base load operation. The gross generator outputs as rated reactor power and stretch of valves wide open (VWO) power are given on Figures 10.1-2 and 10.1-3, respectively. The gross generator output at the power rerate operating  condition is given on Figure 10.1-4.


POWER GENERATION DESIGN BASIS TWO - The T-G load change characteristics are compatible with the instrumentation and control system which coordinates T-G and reactor operation.
excitation system coupled directly to the generator shaft.  
POWER GENERATION DESIGN BASIS THREE - The T-G is designed to accept a sudden loss of full load without exceeding design over-speed.
POWER GENERATION DESIGN BASIS FOUR - The T-G is designed to permit periodic testing of steam valves important to overspeed protection, emergency overspeed trip circuits, and several other trip circuits under load.  


POWER GENERATION DESIGN BASIS FIVE - The failure of any single component will not cause the rotor speed to exceed the design speed. POWER GENERATION DESIGN BASIS SIX - Unlimited access to all levels of the turbine area under all operating conditions is provided.
T-G accessories include the bearing lubrication oil system, turning gear, hydrogen system, seal oil system, stator cooling water system, exhaust hood spray system, steam seal system, and turbine supervisory


10.2.2  SYSTEM DESCRIPTION  10.2.2.1  General Description  The T-G system is shown in Figure 10.2-1. Performance characteristics are provided in Section 10.1.                                  10.2-1                    Rev. 25 WOLF CREEK The turbine consists of double-flow, high-pressure, and low-pressure elements in tandem. Moisture separation and reheating of the steam are provided between the high-pressure and low-pressure elements by four combined moisture separator reheater (MSR) assemblies. Two assemblies are located on each side of the T-G center-line. The generator is coupled directly to the turbine shaft. It is equipped with an excitation system coupled directly to the generator shaft.
instrument (TSI) system.  
T-G accessories include the bearing lubrication oil system, turning gear, hydrogen system, seal oil system, stator cooling water system, exhaust hood spray system, steam seal system, and turbine supervisory instrument (TSI) system.
The analog Electro-Hydraulic Control (EHC) system has been replaced with a new digital Turbine Control system (TCS). The new system utilizes an Ovation-Based Distributed Control system (DCS). Two redundant sets of controllers are used in the turbine control system. The turbine control system architecture is based on combined functional and hardware redundancy to create a robust and reliable system. In order to increase reliability of the new TCS, the Ovation system is provided with redundancy as follows:  1. Two 100% capable controllers, one primary and one backup dedicated to Over Speed Protection and Trip function - Ovation Emergency Trip System (ETS). 2. Two 100% capable controllers, one primary and one backup dedicated to Turbine Control and providing backup Over Speed Protection and Trip Function - Ovation Operator Auto/Overspeed Protection and Control (OA/OPC). 3. The system is configured to provide cross trips between the two sets of redundant controllers. 4. Diverse Overspeed Protection (DOPS) using Woodward ProTech GII modules. The ETS and the OA/OPC controllers interface with two sets of diverse and independent speed probes, which measure turbine speed. One set consists of three passive speed probes which interface to the ETS controller. The other set consists of three active probes which interface to the OA/OPC controller. Both of the TCS controllers - OA/OPC and ETS - perform the Emergency Trip function. Each controller has an associated solenoid-operated valve Testable Dump Manifold (TDM) that releases Electro-Hydraulic (EH) oil pressure, and causes the main stop valves, the control valves, the intermediate stop valves, and the intercept valves to rapidly close, thus blocking the flow of steam to the turbine. To prevent both function failure and spurious activation from a single solenoid control circuit failure, each manifold operates on a "two-out-of-three" coincidence voting logic. An additional set of three passive speed probes interface with the Woodward ProTech GII modules to provide a diverse overspeed trip. DOPS contact outputs trip the turbine through the ETS TDM using "two-out-of-three" coincidence voting logic. 


10.2-2                    Rev. 27 WOLF CREEK The T-G unit and associated piping, valves, and controls are located completely within the turbine building. There are no safety-related systems or components located within the turbine building (See Figures 1.2-29 through 1.2-42), hence any failures associated with the T-G unit will not affect any safety-related equipment. Failure of T-G equipment does not preclude safe shutdown of the reactor coolant system. There is unlimited access to T-G components and instrumentation associated with T-G overspeed protection, under all operating conditions. 10.2.2.2  Component Description The MSRs, MSR drain tanks, stator water coolers, and stator water demineralier are designed to ASME Section VIII. The balance of the T-G is designed to General Electric (GE) Company Standards. MAIN STOP AND CONTROL VALVES - Four high pressure, angle body, main stop and control valve chests admit steam to the high pressure (HP) turbine. The primary function of the main stop valves is to quickly shut off the steam flow to the turbine under emergency conditions. The primary function of the control valves is to control steam flow to the turbine in response to the turbine control system. The four sets of valves are located at El. 2033, south of the high pressure turbine shell. The valve chests are made of a copper-bearing, low-carbon steel. The main stop valves are single disc type valves operated in an open-closed mode either by the emergency trip, fluid operated, fast acting valve for tripping, or by a small solenoid valve for testing. The discs are totally unbalanced and cannot open against full  differential pressure. An internal bypass valve is provided in the number two main stop valve to pressurize the below seat areas of the four valves. Springs are designed to close the main stop valve in 0.19 second under the emergency conditions listed in Section 10.2.2.3.4. Each main stop valve has one inlet and one outlet. The outlet of each valve is welded directly to the inlet of a control valve casing. The four stop valves are also welded together through below-seat equalizers. Each stop valve contains a permanent steam strainer to prevent foreign matter from entering the control valves and turbine.
The analog Electro-Hydraulic Control (EHC) system has been replaced with a new digital Turbine Control system (TCS). The new system utilizes an Ovation-Based Distributed Control system (DCS). Two redundant sets of controllers are used in the turbine control system.
The control valves are poppet-type valves with venturi seats. The valve discs have sperical seats to ensure tight shutoff. The valves are of sufficient size, relative to their cracking pressure, to require partial balancing. This is accomplished by a skirt on the valve disc sliding inside a balance chamber. When a control valve starts to open, a small internal valve is opened to decrease the pressure in the balance chamber. Further lifting of the stem opens the main disc.
The turbine control system architecture is based on combined functional and hardware redundancy to create a robust and reliable system. In order to increase reliability of the new TCS, the Ovation system is provided with redundancy as follows:
Each control valve is operated by a single acting, spring-closed servomotor opened by high pressure fire-resistant fluid through a servo valve. The control valve is designed to close in 0.20 seconds.
: 1. Two 100% capable controllers, one primary and one backup dedicated to Over Speed Protection and Trip function - Ovation Emergency Trip System (ETS).
HIGH PRESSURE TURBINE - As discussed at the beginning of Section 10.2, a new nine-stage HP turbine was installed in RF18, replacing the original seven-stage turbine. To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the extraction locations to remain   
: 2. Two 100% capable controllers, one primary and one backup dedicated to Turbine Control and providing backup Over Speed Protection and Trip Function - Ovation Operator Auto/Overspeed Protection and Control (OA/OPC).
: 3. The system is configured to provide cross trips between the two sets of redundant controllers.
: 4. Diverse Overspeed Protection (DOPS) using Woodward ProTech GII modules. The ETS and the OA/OPC controllers interface with two sets of diverse and independent speed probes, which measure turbine speed. One set consists of three passive speed probes which interface to the ETS controller. The other set consists of three active probes which interface to the OA/OPC controller.
Both of the TCS controllers - OA/OPC and ETS - perform the Emergency Trip function. Each controller has an associated solenoid-operated valve Testable Dump Manifold (TDM) that releases Electro-Hydraulic (EH) oil pressure, and causes the main stop valves, the control valves, the intermediate stop valves, and the intercept valves to rapidly close, thus blocking the flow of steam to the turbine. To prevent both function failure and spurious activation from a single solenoid control circuit failure, each manifold operates on a "two-out-of-three" coincidence voting logic.
An additional set of three passive speed probes interface with the Woodward ProTech GII modules to provide a diverse overspeed trip. DOPS contact outputs trip the turbine through the ETS TDM using "two-out-of-three" coincidence voting logic.
 
10.2-2                    Rev. 27 WOLF CREEK The T-G unit and associated piping, valves, and controls are located completely within the turbine building. There are no safety-related systems or components located within the turbine building (See Figures 1.2-29 through 1.2-42), hence any failures associated with the T-G unit will not affect any safety-related equipment. Failure of T-G equipment does not preclude safe shutdown of the reactor coolant system. There is unlimited access to T-G components and instrumentation associated with T-G overspeed protection, under all operating conditions.
10.2.2.2  Component Description The MSRs, MSR drain tanks, stator water coolers, and stator water demineralier are designed to ASME Section VIII. The balance of the T-G is designed to General Electric (GE) Company Standards.
MAIN STOP AND CONTROL VALVES - Four high pressure, angle body, main stop and control valve chests admit steam to the high pressure (HP) turbine. The primary function of the main stop valves is to quickly shut off the steam flow to the turbine under emergency conditions. The primary function of the control valves is to control steam flow to the turbine in response to the turbine control system. The four sets of valves are located at El. 2033, south of the high pressure turbine shell. The valve chests are made of a copper-bearing, low-carbon steel. The main stop valves are single disc type valves operated in an open-closed mode either by the emergency trip, fluid operated, fast acting valve for tripping, or by a small solenoid valve for testing. The discs are totally unbalanced and cannot open against full  differential pressure. An internal bypass valve is provided in the number two main stop valve to pressurize the below seat areas of the four valves.
Springs are designed to close the main stop valve in 0.19 second under  
 
the emergency conditions listed in Section 10.2.2.3.4.
Each main stop valve has one inlet and one outlet. The outlet of each  
 
valve is welded directly to the inlet of a control valve casing. The  
 
four stop valves are also welded together through below-seat  
 
equalizers. Each stop valve contains a permanent steam strainer to prevent foreign matter from entering the control valves and turbine.  
 
The control valves are poppet-type valves with venturi seats. The  
 
valve discs have sperical seats to ensure tight shutoff. The valves  
 
are of sufficient size, relative to their cracking pressure, to require partial balancing. This is accomplished by a skirt on the valve disc sliding inside a balance chamber. When a control valve starts to open, a small internal valve is opened to decrease the pressure in the  
 
balance chamber. Further lifting of the stem opens the main disc.
 
Each control valve is operated by a single acting, spring-closed  
 
servomotor opened by high pressure fire-resistant fluid through a servo valve. The control valve is designed to close in 0.20 seconds.  
 
HIGH PRESSURE TURBINE - As discussed at the beginning of Section 10.2, a new nine-stage HP turbine was installed in RF18, replacing the  
 
original seven-stage turbine. To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the extraction locations to remain
 
10.2-3                    Rev. 27 WOLF CREEK numbered per the original design. The HP turbine receives steam through four pipes, called steams leads, one from each control valve outlet. The steam is expanded axially across nine stages of stationary and moving blades. Steam pressure immediately downstream of the first stage is used as a load reference signal for reactor control.
Extraction steam from the third turbine stage supplies the seventh stage of feedwater heating and the first stage of steam reheating.
Extraction steam from the fifth and seventh turbine stages supplies the sixth and fifth stages of feedwater heating, respectively. Turbine exhaust steam is collected in eight pipes called cold reheat pipes, four at each end of the turbine.
The new HP rotor was forged from a single piece of alloy steel, per GE specification (similar to ASTM A470), employing integral wheels and couplings (monoblock design). The monoblock rotor is designed with modern low stress dovetail profiles. There are nine stages of advanced design buckets (TE and GE -18 rows). The buckets utilize a 12 percent Chromium Alloy, similar to ASTM A479 Type 403.
MOISTURE SEPARATOR REHEATERS - Four horizontal cylindrical-shell, combined moisture separator reheater (MSR) assemblies are installed in the steam lines between the high and low pressure turbines. The MSRs serve to dry and reheat the steam before it enters the low pressure turbine. This improves cycle efficiency and reduces moisture-related erosion and corrosion in the low pressure turbines. Steam from the high pressure turbine is piped into the bottom of the MSR. Moisture is
 
removed in chevron-type moisture separators, and is drained to the
 
moisture separator drain tank and from there to the heater drain tank.
The dry steam passes upward across the tube bundle of the first stage reheater. The first stage reheater steam source is extraction steam
 
from the third HP turbine stage. The reheater is drained to the first
 
stage reheater drain tank and from there to the sixth feedwater heater. 
 
The dried and reheated steam then passes through the tube bundle of the second stage reheater. The second stage reheater steam source is main steam. The reheater is drained to the second stage reheater drain tank
 
and from there to the seventh feedwater heater. Safety valves are
 
provided on the MSR for overpressure protection.
 
COMBINED INTERMEDIATE VALVES - Two combined intermediate valves (CIV) per LP turbine are provided, one in each steam supply line, called the
 
hot reheat line, from the MSR. The CIV consists of two valves sharing
 
a common casing. The two valves are the intercept valve and the
 
intermediate stop valve. Although they utilize a common casing, these valves have entirely separate operating mechanisms and controls. The function of the CIVs is to protect the turbine against over-speed from
 
stored steam between the main stop and control valves and the CIVs.  


10.2-3                    Rev. 27 WOLF CREEK numbered per the original design. The HP turbine receives steam through four pipes, called steams leads, one from each control valve outlet. The steam is expanded axially across nine stages of stationary and moving blades. Steam pressure immediately downstream of the first stage is used as a load reference signal for reactor control. Extraction steam from the third turbine stage supplies the seventh stage of feedwater heating and the first stage of steam reheating. Extraction steam from the fifth and seventh turbine stages supplies the sixth and fifth stages of feedwater heating, respectively. Turbine exhaust steam is collected in eight pipes called cold reheat pipes, four at each end of the turbine. The new HP rotor was forged from a single piece of alloy steel, per GE specification (similar to ASTM A470), employing integral wheels and couplings (monoblock design). The monoblock rotor is designed with modern low stress dovetail profiles. There are nine stages of advanced design buckets (TE and GE -18 rows). The buckets utilize a 12 percent Chromium Alloy, similar to ASTM A479 Type 403. MOISTURE SEPARATOR REHEATERS - Four horizontal cylindrical-shell, combined moisture separator reheater (MSR) assemblies are installed in the steam lines between the high and low pressure turbines. The MSRs serve to dry and reheat the steam before it enters the low pressure turbine. This improves cycle efficiency and reduces moisture-related erosion and corrosion in the low pressure turbines. Steam from the high pressure turbine is piped into the bottom of the MSR. Moisture is removed in chevron-type moisture separators, and is drained to the moisture separator drain tank and from there to the heater drain tank. The dry steam passes upward across the tube bundle of the first stage reheater. The first stage reheater steam source is extraction steam from the third HP turbine stage. The reheater is drained to the first stage reheater drain tank and from there to the sixth feedwater heater.
The dried and reheated steam then passes through the tube bundle of the second stage reheater. The second stage reheater steam source is main steam. The reheater is drained to the second stage reheater drain tank and from there to the seventh feedwater heater. Safety valves are provided on the MSR for overpressure protection.
COMBINED INTERMEDIATE VALVES - Two combined intermediate valves (CIV) per LP turbine are provided, one in each steam supply line, called the hot reheat line, from the MSR. The CIV consists of two valves sharing a common casing. The two valves are the intercept valve and the intermediate stop valve. Although they utilize a common casing, these valves have entirely separate operating mechanisms and controls. The function of the CIVs is to protect the turbine against over-speed from stored steam between the main stop and control valves and the CIVs.
Three CIVs are located on each side of the turbine.  
Three CIVs are located on each side of the turbine.  


Steam from the MSR enters the single inlet of each valve casing, passes through the permanent basket strainer, past the intercept valve and stop valve disc, and discharges through a single outlet connected to the LP turbine. The CIVs are located as close to the LP turbine as possible to limit the amount of controlled steam available for overspeeding the turbine. Upon loss of load, the intercept valve first closes then throttles steam to the LP turbine, as required, to control speed and maintain synchronization. It is capable of opening against full system pressure. The intermediate stop valve closes only if the intercept valves fail to operate properly. It is capable of opening 10.2-4                        Rev. 27 WOLF CREEK against a pressure differential of approximately 15 percent of the maximum expected system pressure. The intermediate stop valve and intercept valve are designed to close in 0.2 second. LOW PRESSURE TURBINES - As discussed at the beginning of Section 10.2, new LP steam paths were installed in RF18. To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the LP turbine stages to remain numbered per the original design (8 through 14). Each LP turbine receives steam flow from two CIVs. The steam is expanded axially across seven stages of stationary and moving buckets.
Steam from the MSR enters the single inlet of each valve casing, passes through the permanent basket strainer, past the intercept valve and stop valve disc, and discharges through a single outlet connected to  
Extraction steam flow from stages 8, 9, 11 and 12 supply the fourth, third, second and first stage of feedwater heating, respectively. The ninth stage extraction is also the normal source of turbine gland sealing steam. The thirteenth turbine stage is a moisture removal stage where moisture is removed to protect the last stages from erosion induced by water droplets. This extraction is drained directly to the condenser. The LP steam paths were designed using 43-inch last stage buckets on monoblock rotors with compatible diaphragms and new inner casings. The steam paths consist of three sets of seven stage, double-flow rotors without bore, utilizing an alloy similar to ASTM A470 and designed with modern low-stress dovetails.
 
Forged bucket material utilizes 12 percent Chromium Alloy, similar to ASTM A470 XM30. The last stage leading edge buckets are flame-hardened for protection against water droplet erosion and are designed for continuous operation at exhaust pressures up to 5.5 inches HgA. The prior two stages are also flame-hardened for erosion protection.  
the LP turbine. The CIVs are located as close to the LP turbine as  
 
possible to limit the amount of controlled steam available for  
 
overspeeding the turbine. Upon loss of load, the intercept valve first closes then throttles steam to the LP turbine, as required, to control speed and maintain synchronization. It is capable of opening against  
 
full system pressure. The intermediate stop valve closes only if the  
 
intercept valves fail to operate properly. It is capable of opening
 
10.2-4                        Rev. 27 WOLF CREEK against a pressure differential of approximately 15 percent of the maximum expected system pressure. The intermediate stop valve and  
 
intercept valve are designed to close in 0.2 second.
LOW PRESSURE TURBINES - As discussed at the beginning of Section 10.2, new LP steam paths were installed in RF18. To maintain configuration  
 
consistency, the numbering of the stages for the new 9-stage HP turbine  
 
are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the LP turbine stages to remain numbered per the original design (8 through 14). Each LP turbine receives steam flow from two CIVs. The steam is expanded  
 
axially across seven stages of stationary and moving buckets.
 
Extraction steam flow from stages 8, 9, 11 and 12 supply the fourth, third, second and first stage of feedwater heating, respectively. The ninth stage extraction is also the normal source of turbine gland sealing steam. The thirteenth turbine stage is a moisture removal  
 
stage where moisture is removed to protect the last stages from erosion  
 
induced by water droplets. This extraction is drained directly to the  
 
condenser.
The LP steam paths were designed using 43-inch last stage buckets on  
 
monoblock rotors with compatible diaphragms and new inner casings. The  
 
steam paths consist of three sets of seven stage, double-flow rotors  
 
without bore, utilizing an alloy similar to ASTM A470 and designed with modern low-stress dovetails.  
 
Forged bucket material utilizes 12 percent Chromium Alloy, similar to  
 
ASTM A470 XM30. The last stage leading edge buckets are flame-hardened  
 
for protection against water droplet erosion and are designed for continuous operation at exhaust pressures up to 5.5 inches HgA. The prior two stages are also flame-hardened for erosion protection.  
 
EXTRACTION NONRETURN VALVES - Upon loss of load, the steam contained
 
within turbine extraction lines would flow back into the turbine, across the remaining turbine stages, and into the condenser.
Condensate contained in feedwater heaters will flash to steam under
 
this condition and contribute to the backflow of steam. Extraction
 
nonreturn valves are installed in the third, fifth, eighth, ninth, and


EXTRACTION NONRETURN VALVES - Upon loss of load, the steam contained within turbine extraction lines would flow back into the turbine, across the remaining turbine stages, and into the condenser. Condensate contained in feedwater heaters will flash to steam under this condition and contribute to the backflow of steam. Extraction nonreturn valves are installed in the third, fifth, eighth, ninth, and eleventh stage turbine extraction lines to guard against this backflow of steam and the contribution it would make to a rotor overspeed condition. The nonreturn valves are free-swinging. The eleventh stage nonreturn valves have double "D" swing plates. The plates are closed by a torsion spring as flow decreases. For the remaining nonreturn valves, under normal operation, air bears against a piston which mechanically prevents a coiled spring from assisting in valve closure. Upon turbine trip, the air is dumped to atmosphere via the turbine control system's air relay dump valve.
eleventh stage turbine extraction lines to guard against this backflow of steam and the contribution it would make to a rotor overspeed condition. The nonreturn valves are free-swinging. The eleventh stage  


GENERATOR - The generator operates at 1,800 rpm and is rated at 1,409,000 kVA at 75 psig hydrogen pressure and a 0.92 power factor. The stator core and rotor conductors are cooled by hydrogen circulated by fans mounted at each end of the generator shaft. Two water-cooled hydrogen coolers are mounted in the generator frame. A seal oil system isolated the hydrogen from the atmosphere. The stator conductors are water cooled. The rotor consists of layers of field windings embedded in milled slots. The winding material is silver-bearing copper in preformed coils, carried in molded glass liners in the slots. The windings are held radially by steel slot wedges at the rotor outside diameter. The                                  10.2-5                    Rev. 28 WOLF CREEK wedge material maintains its mechanical properties at elevated temperature, which could occur as a result of loss of cooling, for example. The magnetic field is generated by dc power which is fed to the windings through collector rings located outboard of the main generator bearings. The rotor body and shaft is machined from a single, solid steel forging. The material is a nickel-molybdenum-vanadium alloy steel. Detailed examinations and tests are carried out at each stage of rotor manufacture. These include:      a. Material property checks on test specimens taken from the          forging      b. Ultrasonic tests for internal flaws      c. Photomicrographs for examination of microstructure      d. Magnetic particle and ultrasonic examination of the bore      e. Surface finish tests of slots for indication of a stress          riser  The rotor end turns are restrained against centrifugal force by retaining rings. The rings are the highest stressed components of the generator. The retaining ring is shrunk on a machined fit at the end of the rotor body. It is locked against axial and circumferential movement by a locking ring screwed into the retaining ring and keyed to the rotor body. The ring material is a manganese-chromium, alloy steel forging. All retaining ring forgings are tested for chemical composition, tensile properties, Charpy-V notch impact properties, grain size, internal flaws by ultrasonic inspection, surface flaws by dye penetrant inspection, and performance by cyclic hydrostatic testing. 10.2.2.3  System Operation  10.2.2.3.1  Normal Operation
nonreturn valves have double "D" swing plates. The plates are closed


Under normal operation, the main stop valves and CIVs are wide open. Operation of the T-G is under the control of the TCS OA/OPC controller. The OA/OPC controller performs speed control, load control and flow control as well as backup overspeed protection. Speed Control  The OA/OPC controller receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket with no mechanical modifications required. The probes are powered by redundant 24VDC power supplies within the drop. The three signals are received into the system via separate modules located on separate I/O branches. The median speed signal is selected to provide speed feedback to the system. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped. A rate of acceleration is calculated from the selected signal to determine appropriate actions of the control valves. A speed setpoint and a rate are entered by the operator via a graphical interface. The speed control ramps to the speed setpoint at the rate entered by the operator using closed loop control. In startups, when the turbine is identified to be in a critical speed range where high 10.2-6                      Rev. 27 WOLF CREEK vibrations can be observed, the control system accelerates the speed to the maximum rate as determined by the turbine manufacturer until the speed is outside the critical range. The control system then returns to the operator pre-set speed rate. The operator cannot enter a critical speed value as a "go to" speed in RPM. Load Control / Flow Control  The OA/OPC controller controls the load of the turbine. The load control has two operator selectable loops, the First Stage Pressure (FSP) or megawatt (MW) loop. When the MW loop is placed into service, the system maintains closed loop control using two new megawatt transducers as feedback. When the first stage pressure loop is placed into service, the system uses three new pressure transmitters as a median selected value for feedback. The load control loops are mutually exclusive where only one can be placed into service at a time. The load control function generates a flow reference that is sent to the control and intercept valves for position control. Each modulating valves position is controlled by redundant valve positioner modules. The operator enters a load setpoint and rate in the same manner as the speed control function. The values entered are checked for exceeding limits and are rejected in such situations. The load setpoint of the turbine can be changed manually or automatically depending on circumstances which cause the T-G protection circuits to come into action. For example, stator cooling water system trouble will automatically cause the maximum permissible load to be reduced. The load rates are generated within the system by predefined values. The reactor is capable of accepting these rates without abnormal effect or bypass of steam to the atmosphere or condenser. The load control receives a speed error signal to correct speed variations while in load control. The error is limited to allow correction in the speed increasing direction only. 10.2.2.3.2  Operation Upon Loss of Load  Upon loss of generator load, the EHC system acts to prevent rotor speed from exceeding design overspeed. Refer to Table 10.2-1 for the description of the sequence of events following loss of turbine load. Failure of any single component will not result in rotor speed exceeding design overspeed (i.e. 120 percent of rated speed). The following component redundancies are employed to guard against overspeed:      a. Main stop valves/Control valves      b. Intermediate stop valves/Intercept valves      c. OA/OPC controller - Primary speed control / Overspeed trip / Speed detector module trip d. Fast acting solenoid valves/Emergency trip fluid system (ETS)
by a torsion spring as flow decreases. For the remaining nonreturn


e. ETS controller - Overspeed trip / Speed detector module trip / Diverse overspeed protection system trip The main stop valves and control valves are in series and have completely independent operating controls and operating mechanisms.
valves, under normal operation, air bears against a piston which mechanically prevents a coiled spring from assisting in valve closure.
Closure of either all four stop valves or all four control valves shuts off all main steam flow to the HP turbine. The combined stop and 10.2-7 Rev. 27 WOLF CREEK  intercept valves are also in series and have completely independent operating controls and operating mechanisms. Closure of either all six stop valves or all six intercept valves shuts off all MSR outlet steam flow to the three LP turbines. The OA drop speed control receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket. Increase of speed will begin to close the control valves. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped. Fast acting solenoid valves initiate fast closure of control valves under load rejection conditions that might lead to rapid rotor acceleration. The solenoid valve dumps ETS pressure at the control valve. Valve action occurs when power exceeds load by more than 40 percent and generator current is lost suddenly. The ETS initiates fast closure of the valves whether the fast-acting solenoid valves work or not. The ETS pressure is dumped by either the ETS TDM or the OA/OPC TDM. If speed control should fail, the overspeed trip devices must close the steam admission valves to prevent turbine overspeed. Woodward ProTech GII modules provide a diverse overspeed trip as a replacement for the mechanical trip bolt. It is set to operate at 110 percent of rated speed. Ovation ETS and OA/OPC controller overspeed trip setpoints are 110% (1980 RPM). Ovation SDM hard-wired trips provide a backup overspeed trip set at 111% (1998 RPM). Component redundancy and fail safe design of the ETS hydraulic system and trip circuitry provide turbine overspeed protection. The combination of Ovation ETS and OA/OPC controller trips, hardwired overspeed protection found within the Ovation Speed Detector Modules (SDMs), and Woodward ProTech GII modules provide diverse measures for safeguarding the turbine. Overspeed trips are initiated through either the ETS TDM or the OA/OPC TDM. Single component failure does not compromise trip protection. OA/OPC Controller  OA/OPC TDM configuration is de-energized to trip and can be actuated by any of the following conditions:  1. The OA/OPC controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the ETS controller. 2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs. 3. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated. Loss of both primary and backup 24 Vdc auxiliary power de-energizes the TDM which results in a trip. Loss of power trips the turbine through fail safe circuitry. ETS Controller  The ETS TDM configuration is de-energized to trip and can be actuated by any of the following conditions:  10.2-8 Rev. 27 WOLF CREEK  1. The ETS controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the OA/OPC controller. 2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs. 3. Woodward ProTech GII modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs. 4. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated. Loss of two-out-of-three 125 Vdc power supplies from the station batteries de-energizes the TDM which results in a trip. Loss of power trips the turbine through fail safe circuitry. The TDMs are powered via separate systems. The ETS TDM is powered via three independent 125VDC station batteries. The OA/OPC TDM is powered from redundant 24VDC power supplies powered by two separate 120VAC UPS systems. 10.2.2.3.3  Testing  Each TDM can be tested online via Ovation HMI displays to verify the solenoids have de-energized. Only one solenoid and one TDM can be tested at a time. The overspeed trip devices can be tested in accordance to the plant operation. The soft overspeed trip can be tested by setting a value below normal operating speed during startup. The hard-wired trips can be tested independently by removing a speed probe from operation and injecting a signal from a function generator that will exceed the module set threshold. This test will only activate the signal and solenoid for the hardwired circuit. 10.2.2.3.4  Turbine Trips  a. Emergency trip pushbuttons in control room. Two pushbuttons must be pressed simultaneously. b. Moisture separator high level  c. Low condenser vacuum  d. Low lube oil pressure  e. Deleted  f. Reactor trip  g. Thrust bearing wear  h. Overspeed (ETS TDM and OA TDM)  i. Manual trip handle on TDM stand  j. Loss of stator coolant (2 minute and 3.5 minute trip)  k. Low hydraulic fluid pressure                                10.2-9                    Rev. 27 WOLF CREEK  l. Any generator trip  m. Loss of TDM electrical power  n. Excessive vibration  o. AMSAC  10.2.3  TURBINE INTEGRITY  10.2.3.1  Materials Selection  The material used for the new monoblock rotors is a forged nickel-chrome-molybdenum-vanadium alloy that is similar to ASTM Class 6. A GE material specification was used for the actual material in order to tightly control the condition of the resulting forgings. Ranges of key alloying elements were defined; maximum permissible levels of tramp elements were defined; process procedures affecting properties, such as heat treatments were specified; and the permissible ranges or levels of mechanical properties at each of the acceptance test locations were specified. The forging alloys used in the HP and LP rotors are extremely similar. The property differences are due to the range of strengths and properties needed for the nuclear HP and LP rotor applications. 10.2.3.2  Fracture Toughness  The original turbine rotors had shrunk on disks and couplings. New turbine rotors were installed in RF18. Each rotor was manufactured by GE from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking. The brittle fracture failure mechanism in rotors with shrunk on wheels was due to the initiation and growth of stress corrosion cracks to critical size in the exposed wheel keyway surfaces. The probability of this failure mode is dependent on environment, speed, temperature and material properties, as well as inspection methods and inspection intervals. For a shrunk-on wheel operated at, or near, normal running speed, the probability of bursting and thus of missile generation, was dominated by this fracture mechanism. The new rotors are of monoblock construction and do not have shrunk-on wheels. Therefore, the formerly dominant brittle fracture failure mechanism is eliminated in monoblock rotors. With the installation of the new monoblock rotors, the concern of rotor disk integrity is eliminated. 10.2.3.3  High Temperature Properties  Primarily, the life limiting factors for rotors are attributable to the higher temperature dependent phenomena, typically in the range of 650&#xba;F or higher. Material creep, thermal fatigue and embrittlement are the major factors that can limit a rotor's useful life. The Wolf Creek rotor components operate at temperatures less than 575&#xba;F. Therefore, the material creep rupture at high temperatures is not a consideration; and embrittlement and the rotor thermal transient stress that can cause low cycle fatigue are not significant factors. The primary design parameters in the design of the nuclear monoblock rotors are therefore the shaft bending and torsional stresses, centrifugal stress, and  10.2-10 Rev. 27 WOLF CREEK stress corrosion cracking protection. These factors have been properly engineered, with operating conditions and reasonably controlled environment, to design the rotors for the intended life. 10.2.3.4  Turbine Design  In the design of the monoblock rotor, the rotor dynamic bending stresses and torsional stresses were kept to a minimum by maintaining reasonable operating margins between the rotor natural frequencies and the known potential stimulas. The rotor geometry was also optimized to accommodate manufacturing and operating tolerances such as bearing misalignment and electrical transients, etc. These design practices ensure that the potential vibratory stresses are kept below the fatigue strength endurance limit of the component materials.
Upon turbine trip, the air is dumped to atmosphere via the turbine  
10.2.3.5  Preservice Inspection The preservice procedures and acceptance criteria are as follows:  a. The rotor forgings were subjected to an NDT acceptance procedure by the forging vendors and an NDT acceptance procedure by GE. b. Preliminary pre-service peripheral ultrasonic examinations were performed on the monoblock rotor forgings. The rotor forgings were semi-machined to provide a suitable surface for the ultrasonic inspection. After the final heat treatment, a battery of NDT testing was performed to ensure rotor structural integrity. Prior to accepting a monoblock forging, extensive specimen testing was performed to assure that the rotor met the application requirements.
c. All finished machined surfaces are subjected to a magnetic          particle test with no flaw indications permissible.
d. Each fully bucketed turbine rotor assembly is spin tested at 20-percent overspeed.
Additional preservice inspections include air leakage tests performed to determine that the hydrogen cooling system is tight before hydrogen is introduced into the generator casing. The hydrogen purity is tested in the generator after hydrogen has been introduced. The generator windings and all motors are megger tested. Vibration tests are performed on all motor-driven equipment. Hydrostatic tests are performed on all coolers. All piping is pressure tested for leaks.
Motor-operated valves are factory leak tested and inplace tested once installed.


10.2.3.6  Inservice Inspection The inservice inspection program for the turbine assembly includes the disassembly of the turbine and complete inspection of all normally inaccessible parts, such as couplings, coupling bolts, turbine shafts, low-pressure turbine buckets, and high-pressure rotors. During plant shutdown coinciding with the inservice inspection schedule for ASME Section III components, as required by the ASME Boiler and Presser Vessel Code, Section XI, turbine inspection is done in sections during the refueling outages so that in 10 years total inspection has been completed at least once.                               10.2-11                    Rev. 27 WOLF CREEK This inspection consists of visual and surface examinations as indicated below: a. Visual examination of all accessible surfaces of rotors     b. Visual and surface examination of all low-pressure buckets  
control system's air relay dump valve.
 
GENERATOR - The generator operates at 1,800 rpm and is rated at
 
1,409,000 kVA at 75 psig hydrogen pressure and a 0.92 power factor.
The stator core and rotor conductors are cooled by hydrogen circulated
 
by fans mounted at each end of the generator shaft. Two water-cooled
 
hydrogen coolers are mounted in the generator frame. A seal oil system
 
isolated the hydrogen from the atmosphere. The stator conductors are
 
water cooled.
The rotor consists of layers of field windings embedded in milled
 
slots. The winding material is silver-bearing copper in preformed
 
coils, carried in molded glass liners in the slots. The windings are
 
held radially by steel slot wedges at the rotor outside diameter. The 10.2-5                    Rev. 28 WOLF CREEK wedge material maintains its mechanical properties at elevated temperature, which could occur as a result of loss of cooling, for example. The magnetic field is generated by dc power which is fed to the windings through collector rings located outboard of the main generator bearings. The rotor body and shaft is machined from a single, solid steel forging. The material is a nickel-molybdenum-vanadium alloy steel. Detailed examinations and tests are carried out at each stage of rotor manufacture. These include:
: a. Material property checks on test specimens taken from the forging
: b. Ultrasonic tests for internal flaws
: c. Photomicrographs for examination of microstructure
: d. Magnetic particle and ultrasonic examination of the bore
: e. Surface finish tests of slots for indication of a stress riser The rotor end turns are restrained against centrifugal force by retaining rings. The rings are the highest stressed components of the generator. The retaining ring is shrunk on a machined fit at the end of the rotor body. It is locked against axial and circumferential movement by a locking ring screwed into the retaining ring and keyed to the rotor body. The ring material is a manganese-chromium, alloy steel forging. All retaining ring forgings are tested for chemical composition, tensile properties, Charpy-V notch impact properties, grain size, internal flaws by ultrasonic inspection, surface flaws by dye penetrant inspection, and performance by cyclic hydrostatic testing. 10.2.2.3  System Operation 10.2.2.3.1  Normal Operation
 
Under normal operation, the main stop valves and CIVs are wide open.
Operation of the T-G is under the control of the TCS OA/OPC controller.
The OA/OPC controller performs speed control, load control and flow control as well as backup overspeed protection.
Speed Control The OA/OPC controller receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket with no mechanical modifications required. The probes are powered by redundant 24VDC power supplies within the drop. The three signals are received into the system via separate modules located on separate I/O branches. The median speed signal is selected to provide speed feedback to the system. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped. A rate of acceleration is calculated from the selected signal to determine appropriate actions of the control valves.
A speed setpoint and a rate are entered by the operator via a graphical interface. The speed control ramps to the speed setpoint at the rate entered by the operator using closed loop control. In startups, when the turbine is identified to be in a critical speed range where high
 
10.2-6                      Rev. 27 WOLF CREEK vibrations can be observed, the control system accelerates the speed to the maximum rate as determined by the turbine manufacturer until the speed is outside the critical range. The control system then returns to the operator pre-set speed rate. The operator cannot enter a critical speed value as a "go to" speed in RPM.
Load Control / Flow Control The OA/OPC controller controls the load of the turbine. The load control has two operator selectable loops, the First Stage Pressure (FSP) or megawatt (MW) loop. When the MW loop is placed into service, the system maintains closed loop control using two new megawatt transducers as feedback. When the first stage pressure loop is placed into service, the system uses three new pressure transmitters as a median selected value for feedback. The load control loops are mutually exclusive where only one can be placed into service at a time.
The load control function generates a flow reference that is sent to the control and intercept valves for position control. Each modulating valves position is controlled by redundant valve positioner modules.
The operator enters a load setpoint and rate in the same manner as the speed control function. The values entered are checked for exceeding limits and are rejected in such situations. The load setpoint of the turbine can be changed manually or automatically depending on circumstances which cause the T-G protection circuits to come into action. For example, stator cooling water system trouble will automatically cause the maximum permissible load to be reduced. The load rates are generated within the system by predefined values. The reactor is capable of accepting these rates without abnormal effect or bypass of steam to the atmosphere or condenser.
The load control receives a speed error signal to correct speed variations while in load control. The error is limited to allow correction in the speed increasing direction only.
10.2.2.3.2  Operation Upon Loss of Load Upon loss of generator load, the EHC system acts to prevent rotor speed from exceeding design overspeed. Refer to Table 10.2-1 for the description of the sequence of events following loss of turbine load.
Failure of any single component will not result in rotor speed exceeding design overspeed (i.e. 120 percent of rated speed). The following component redundancies are employed to guard against overspeed:
: a. Main stop valves/Control valves
: b. Intermediate stop valves/Intercept valves
: c. OA/OPC controller - Primary speed control / Overspeed trip /
Speed detector module trip
: d. Fast acting solenoid valves/Emergency trip fluid system (ETS)
: e. ETS controller - Overspeed trip / Speed detector module trip /
Diverse overspeed protection system trip
 
The main stop valves and control valves are in series and have
 
completely independent operating controls and operating mechanisms. 
 
Closure of either all four stop valves or all four control valves shuts off all main steam flow to the HP turbine. The combined stop and 
 
10.2-7 Rev. 27 WOLF CREEK intercept valves are also in series and have completely independent operating controls and operating mechanisms. Closure of either all six stop valves or all six intercept valves shuts off all MSR outlet steam flow to the three LP turbines.
The OA drop speed control receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket.
Increase of speed will begin to close the control valves. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped.
Fast acting solenoid valves initiate fast closure of control valves under load rejection conditions that might lead to rapid rotor acceleration. The solenoid valve dumps ETS pressure at the control valve. Valve action occurs when power exceeds load by more than 40 percent and generator current is lost suddenly. The ETS initiates fast closure of the valves whether the fast-acting solenoid valves work or not. The ETS pressure is dumped by either the ETS TDM or the OA/OPC TDM. If speed control should fail, the overspeed trip devices must close the steam admission valves to prevent turbine overspeed. Woodward ProTech GII modules provide a diverse overspeed trip as a replacement for the mechanical trip bolt. It is set to operate at 110 percent of rated speed. Ovation ETS and OA/OPC controller overspeed trip setpoints are 110% (1980 RPM). Ovation SDM hard-wired trips provide a backup overspeed trip set at 111% (1998 RPM). Component redundancy and fail safe design of the ETS hydraulic system and trip circuitry provide turbine overspeed protection. The combination of Ovation ETS and OA/OPC controller trips, hardwired overspeed protection found within the Ovation Speed Detector Modules (SDMs), and Woodward ProTech GII modules provide diverse measures for safeguarding the turbine.
Overspeed trips are initiated through either the ETS TDM or the OA/OPC TDM. Single component failure does not compromise trip protection.
OA/OPC Controller OA/OPC TDM configuration is de-energized to trip and can be actuated by any of the following conditions:
: 1. The OA/OPC controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the ETS controller.
: 2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
: 3. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated.
Loss of both primary and backup 24 Vdc auxiliary power de-energizes the TDM which results in a trip. Loss of power trips the turbine through fail safe circuitry.
ETS Controller The ETS TDM configuration is de-energized to trip and can be actuated by any of the following conditions:
10.2-8 Rev.
27 WOLF CREEK
: 1. The ETS controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the OA/OPC controller.
: 2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
: 3. Woodward ProTech GII modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
: 4. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated.
Loss of two-out-of-three 125 Vdc power supplies from the station batteries de-energizes the TDM which results in a trip.
Loss of power trips the turbine through fail safe circuitry. The TDMs are powered via separate systems. The ETS TDM is powered via three independent 125VDC station batteries. The OA/OPC TDM is powered from redundant 24VDC power supplies powered by two separate 120VAC UPS systems. 10.2.2.3.3  Testing Each TDM can be tested online via Ovation HMI displays to verify the solenoids have de-energized. Only one solenoid and one TDM can be tested at a time. The overspeed trip devices can be tested in accordance to the plant operation. The soft overspeed trip can be tested by setting a value below normal operating speed during startup.
The hard-wired trips can be tested independently by removing a speed probe from operation and injecting a signal from a function generator that will exceed the module set threshold. This test will only activate the signal and solenoid for the hardwired circuit.
10.2.2.3.4  Turbine Trips
: a. Emergency trip pushbuttons in control room. Two pushbuttons must be pressed simultaneously.
: b. Moisture separator high level
: c. Low condenser vacuum
: d. Low lube oil pressure
: e. Deleted
: f. Reactor trip
: g. Thrust bearing wear
: h. Overspeed (ETS TDM and OA TDM)
: i. Manual trip handle on TDM stand
: j. Loss of stator coolant (2 minute and 3.5 minute trip)
: k. Low hydraulic fluid pressure 10.2-9                    Rev. 27 WOLF CREEK  l. Any generator trip
: m. Loss of TDM electrical power
: n. Excessive vibration
: o. AMSAC 10.2.3  TURBINE INTEGRITY 10.2.3.1  Materials Selection The material used for the new monoblock rotors is a forged nickel-chrome-molybdenum-vanadium alloy that is similar to ASTM Class 6. A GE material specification was used for the actual material in order to tightly control the condition of the resulting forgings. Ranges of key alloying elements were defined; maximum permissible levels of tramp elements were defined; process procedures affecting properties, such as heat treatments were specified; and the permissible ranges or levels of mechanical properties at each of the acceptance test locations were specified. The forging alloys used in the HP and LP rotors are extremely similar. The property differences are due to the range of strengths and properties needed for the nuclear HP and LP rotor applications.
10.2.3.2  Fracture Toughness The original turbine rotors had shrunk on disks and couplings. New turbine rotors were installed in RF18. Each rotor was manufactured by GE from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking. The brittle fracture failure mechanism in rotors with shrunk on wheels was due to the initiation and growth of stress corrosion cracks to critical size in the exposed wheel keyway surfaces. The probability of this failure mode is dependent on environment, speed, temperature and material properties, as well as inspection methods and inspection intervals.
For a shrunk-on wheel operated at, or near, normal running speed, the probability of bursting and thus of missile generation, was dominated by this fracture mechanism. The new rotors are of monoblock construction and do not have shrunk-on wheels. Therefore, the formerly dominant brittle fracture failure mechanism is eliminated in monoblock rotors. With the installation of the new monoblock rotors, the concern of rotor disk integrity is eliminated.
10.2.3.3  High Temperature Properties Primarily, the life limiting factors for rotors are attributable to the higher temperature dependent phenomena, typically in the range of 650&#xba;F or higher. Material creep, thermal fatigue and embrittlement are the major factors that can limit a rotor's useful life. The Wolf Creek rotor components operate at temperatures less than 575&#xba;F. Therefore, the material creep rupture at high temperatures is not a consideration; and embrittlement and the rotor thermal transient stress that can cause low cycle fatigue are not significant factors. The primary design parameters in the design of the nuclear monoblock rotors are therefore the shaft bending and torsional stresses, centrifugal stress, and 10.2-10 Rev.
27 WOLF CREEK stress corrosion cracking protection. These factors have been properly engineered, with operating conditions and reasonably controlled environment, to design the rotors for the intended life.
10.2.3.4  Turbine Design In the design of the monoblock rotor, the rotor dynamic bending
 
stresses and torsional stresses were kept to a minimum by maintaining reasonable operating margins between the rotor natural frequencies and the known potential stimulas. The rotor geometry was also optimized to
 
accommodate manufacturing and operating tolerances such as bearing
 
misalignment and electrical transients, etc. These design practices
 
ensure that the potential vibratory stresses are kept below the fatigue strength endurance limit of the component materials.
 
10.2.3.5  Preservice Inspection
 
The preservice procedures and acceptance criteria are as follows:
: a. The rotor forgings were subjected to an NDT acceptance procedure by the forging vendors and an NDT acceptance
 
procedure by GE.
: b. Preliminary pre-service peripheral ultrasonic examinations were performed on the monoblock rotor forgings. The rotor
 
forgings were semi-machined to provide a suitable surface for
 
the ultrasonic inspection. After the final heat treatment, a
 
battery of NDT testing was performed to ensure rotor structural integrity. Prior to accepting a monoblock forging, extensive specimen testing was performed to assure that the
 
rotor met the application requirements.
: c. All finished machined surfaces are subjected to a magnetic particle test with no flaw indications permissible.
: d. Each fully bucketed turbine rotor assembly is spin tested
 
at 20-percent overspeed.
 
Additional preservice inspections include air leakage tests performed to determine that the hydrogen cooling system is tight before hydrogen
 
is introduced into the generator casing. The hydrogen purity is tested
 
in the generator after hydrogen has been introduced. The generator
 
windings and all motors are megger tested. Vibration tests are performed on all motor-driven equipment. Hydrostatic tests are performed on all coolers. All piping is pressure tested for leaks. 
 
Motor-operated valves are factory leak tested and inplace tested once
 
installed.
 
10.2.3.6  Inservice Inspection  
 
The inservice inspection program for the turbine assembly includes the  
 
disassembly of the turbine and complete inspection of all normally  
 
inaccessible parts, such as couplings, coupling bolts, turbine shafts, low-pressure turbine buckets, and high-pressure rotors. During plant shutdown coinciding with the inservice inspection schedule for ASME Section III components, as required by the ASME Boiler and Presser  
 
Vessel Code, Section XI, turbine inspection is done in sections during  
 
the refueling outages so that in 10 years total inspection has been  
 
completed at least once.
10.2-11                    Rev. 27 WOLF CREEK This inspection consists of visual and surface examinations as indicated below:
: a. Visual examination of all accessible surfaces of rotors
: b. Visual and surface examination of all low-pressure buckets
: c. 100-percent visual examination of couplings and coupling bolts
 
The inservice inspection of valves important to overspeed protection
 
includes the following:
: a. All main stop valves, control valves, extraction nonreturn
 
valves, and CIVs are tested underload. Operator Workstation
 
Graphic displays will permit full stroking of the stop valve, control valves, and CIVs. Valve position indication is
 
provided on the graphic display. No load reduction is necessary before testing main stop valves and CIVs.
Extraction nonreturn valves are tested locally by equalizing
 
air pressure across the air cylinder. Movement of the valve
 
arm is observed upon action of the spring closure mechanisms.
: b. Main stop valves, control valves, and CIVs are tested quarterly. Extraction nonreturn valves are tested daily. 
 
Closure of each valve during test is verified by direct
 
observation of the valve motion.
: c. All main stop, main control, and CIVs are inspected on a frequency that meets or exceeds the minimum inspection
 
requirements established by the company's insurance provider (Nuclear Electric Insurance Limited) Loss Control Standards. 
 
These inspections are conducted for:


c. 100-percent visual examination of couplings and coupling          bolts The inservice inspection of valves important to overspeed protection includes the following:
a. All main stop valves, control valves, extraction nonreturn valves, and CIVs are tested underload. Operator Workstation Graphic displays will permit full stroking of the stop valve, control valves, and CIVs. Valve position indication is provided on the graphic display. No load reduction is necessary before testing main stop valves and CIVs. Extraction nonreturn valves are tested locally by equalizing air pressure across the air cylinder. Movement of the valve arm is observed upon action of the spring closure mechanisms. b. Main stop valves, control valves, and CIVs are tested quarterly. Extraction nonreturn valves are tested daily.
Closure of each valve during test is verified by direct observation of the valve motion. c. All main stop, main control, and CIVs are inspected on a frequency that meets or exceeds the minimum inspection requirements established by the company's insurance provider (Nuclear Electric Insurance Limited) Loss Control Standards.
These inspections are conducted for:
Wear of linkages and stem packings  
Wear of linkages and stem packings  


Erosion of valve seats and stems Deposits on stems and other valve parts which could interfere with valve operation   Distortions, misalignment Inspection of all valves of one type will be conducted if any unusual condition is discovered 10.2.4  EVALUATION  
Erosion of valve seats and stems  
 
Deposits on stems and other valve parts which could interfere with valve operation Distortions, misalignment  
 
Inspection of all valves of one type will be conducted if any unusual condition is discovered 10.2.4  EVALUATION  


The reactor system is a PWR type; hence, under normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system.  
The reactor system is a PWR type; hence, under normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system.  


No radiation shielding is required for the turbine-generator system.
No radiation shielding is required for the turbine-generator system.
Continuous access to the components of the system for inservice inspection, etc., is possible during all operating conditions. Even in the event of a large primary-to-secondary steam generator leak, the T-G system will not become contaminated to the extent that access is precluded.
 
10.2-12                    Rev. 27 WOLF CREEK A full discussion of the radiological aspects of primary-to-secondary leakage, including anticipated operating concentrations of radioactive contamination, anticipated releases to the environment, and limiting conditions for operation, is included in Chapter 11.0.  
Continuous access to the components of the system for inservice inspection, etc., is possible during all operating conditions. Even in the event of a large primary-to-secondary steam generator leak, the T-G  
 
system will not become contaminated to the extent that access is  
 
precluded.  
 
10.2-12                    Rev. 27 WOLF CREEK A full discussion of the radiological aspects of primary-to-secondary leakage, including anticipated operating concentrations of radioactive contamination, anticipated releases to the environment, and limiting  
 
conditions for operation, is included in Chapter 11.0.  


10.
10.


==2.5  REFERENCES==
==2.5  REFERENCES==
1. Begley, J. A., and Logsdon, W. A., "Correlation of Fracture Toughness Charpy Properties for Rotor Steels," Westinghouse, Scientific Paper 71-1E7-MSLRF-P1, July 26, 1971 2. Spencer, R.C., and Timo, D. P., "Starting and Loading of     Turbines," General Electric Company, 36th Annual Meeting of     the American Power Conference, Chicago, Illinois, April 29-     May 1, 1974 3. Engineering Design Summary, WCNOC Turbine Upgrade Retrofit Project, General Electric Company, GE Energy Engineering Division, Schenectady, New York, Rev. A, ated 25 March 2010. Wolf Creek document number M-800-00391.   
: 1. Begley, J. A., and Logsdon, W. A., "Correlation of Fracture  
 
Toughness Charpy Properties for Rotor Steels," Westinghouse, Scientific Paper 71-1E7-MSLRF-P1, July 26, 1971
: 2. Spencer, R.C., and Timo, D. P., "Starting and Loading of Turbines," General Electric Company, 36th Annual Meeting of the American Power Conference, Chicago, Illinois, April 29-May 1, 1974
: 3. Engineering Design Summary, WCNOC Turbine Upgrade Retrofit Project, General Electric Company, GE Energy  
 
Engineering Division, Schenectady, New York, Rev. A, ated 25 March 2010. Wolf Creek document number M-800-
 
00391.   
 
10.2-13                    Rev. 27
 
WOLF CREEK TABLE 10.2-1 EVENTS FOLLOWING LOSS OF TURBINE LOAD WITH POSTULATED EQUIPMENT FAILURES Approximate
 
Speed-Percent                      Event 100                      Full load is lost. Speed begins to rise.
101                      Control and intercept valves begin
 
to close. As turbine stage
 
pressures decrease, extraction
 
nonreturn valves swing closed.
 
104                      Control and intercept valves fully
 
closed.
 
109                      Peak transient speed with normally
 
operating control system.
 
Assume that power/load unbalance
 
and speed control systems had
 
failed prior to loss of load.


10.2-13                    Rev. 27 WOLF CREEK TABLE 10.2-1  EVENTS FOLLOWING LOSS OF TURBINE LOAD WITH POSTULATED EQUIPMENT FAILURES  Approximate
110 Diverse Overspeed Protection System (DOPS) or OA/ETS soft trip signals all valves to close.
Operation of air relay dump valves releases spring closure mechanisms of extraction nonreturn valves.  


Speed-Percent                      Event  100                      Full load is lost. Speed begins to rise.
111 Backup overspeed trip from OA/ETS Speed Detector Module (SDM) signals all valves to close.  
101                      Control and intercept valves begin to close. As turbine stage pressures decrease, extraction nonreturn valves swing closed.  


104                       Control and intercept valves fully closed.
113                       All valves full closed, activated


109                      Peak transient speed with normally operating control system.  
by DOPS trip.  


Assume that power/load unbalance and speed control systems had failed prior to loss of load.
114                      All valves fully closed, activated


110 Diverse Overspeed Protection System (DOPS) or OA/ETS soft trip signals all valves to close. Operation of air relay dump valves releases spring closure mechanisms of extraction nonreturn valves.
by OA/ETS SDM trip.  
111 Backup overspeed trip from OA/ETS Speed Detector Module (SDM) signals all valves to close.
113                      All valves full closed, activated by DOPS trip.
114                      All valves fully closed, activated by OA/ETS SDM trip.


Rev. 27 WOLF CREEK                       TABLE 10.2-1 (Sheet 2)
Rev. 27 WOLF CREEK TABLE 10.2-1 (Sheet 2)  


Approximate  
Approximate  


Speed-Percent                      Event 119                      Peak transient speed with normal control system failure and operation of DOPS trip.
Speed-Percent                      Event  
120                      Peak transient speed with failure of both normal control systems and DOPS trips, proper operation of backup OA/ETS SDM overspeed trip. 


Rev. 27 WOLF CREEK 10.3  MAIN STEAM SUPPLY SYSTEM  The function of the main steam supply system (MSSS) is to convey steam generated in the steam generators by the reactor coolant system to the turbine-generator system and auxiliary systems for power generation.
119                      Peak transient speed with normal
10.3.1  DESIGN BASES 10.3.1.1  Safety Design Bases  The portion of the MSSS from the steam generator to the steam generator isolation valves is safety related and is required to function following a DBA and to achieve and maintain the plant in a post accident safe shutdown condition.


SAFETY DESIGN BASIS ONE - The safety-related portion of the MSSS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2). SAFETY DESIGN BASIS TWO - The safety-related portion of the MSSS is designed to remain functional after a SSE and to perform its intended function following postulated hazards such as internal missile, or pipe break (GDC-4). SAFETY DESIGN BASIS THREE - Component redundancy is provided so that safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).
control system failure and  
SAFETY DESIGN BASIS FOUR - The MSSS is designed so that the active components are capable of being tested during plant operation. Provisions are made to allow for inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code, Section XI.


SAFETY DESIGN BASIS FIVE - The MSSS uses design and fabrication codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32.  
operation of DOPS trip.
 
120                      Peak transient speed with failure
 
of both normal control systems and
 
DOPS trips, proper operation of backup OA/ETS SDM overspeed trip.
 
Rev. 27 WOLF CREEK 10.3  MAIN STEAM SUPPLY SYSTEM The function of the main steam supply system (MSSS) is to convey steam generated in the steam generators by the reactor coolant system to the turbine-generator system and auxiliary systems for power generation.
 
10.3.1  DESIGN BASES
 
10.3.1.1  Safety Design Bases The portion of the MSSS from the steam generator to the steam generator
 
isolation valves is safety related and is required to function following a DBA
 
and to achieve and maintain the plant in a post accident safe shutdown condition.
 
SAFETY DESIGN BASIS ONE - The safety-related portion of the MSSS is protected
 
from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).
SAFETY DESIGN BASIS TWO - The safety-related portion of the MSSS is designed to
 
remain functional after a SSE and to perform its intended function following postulated hazards such as internal missile, or pipe break (GDC-4).
SAFETY DESIGN BASIS THREE - Component redundancy is provided so that safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).
 
SAFETY DESIGN BASIS FOUR - The MSSS is designed so that the active components are capable of being tested during plant operation. Provisions are made to allow for inservice inspection of components at appropriate times specified in
 
the ASME Boiler and Pressure Vessel Code, Section XI.
 
SAFETY DESIGN BASIS FIVE - The MSSS uses design and fabrication codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power  
 
supply and control functions are in accordance with Regulatory Guide 1.32.  


SAFETY DESIGN BASIS SIX - The MSSS provides for isolation of the secondary side of the steam generator to deal with leakage or malfunctions and to isolate nonsafety-related portions of the system.  
SAFETY DESIGN BASIS SIX - The MSSS provides for isolation of the secondary side of the steam generator to deal with leakage or malfunctions and to isolate nonsafety-related portions of the system.  


10.3-1    Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SEVEN - The MSSS provides means to dissipate heat generated in the reactor coolant system during hot shutdown and cooldown (GDC-34).
10.3-1    Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SEVEN - The MSSS provides means to dissipate heat generated in the reactor coolant system during hot shutdown and cooldown (GDC-34).  
 
SAFETY DESIGN BASIS EIGHT - The MSSS provides an assured source of steam to operate the turbine-driven auxiliary feedwater pump for reactor cooldown under emergency conditions and for shutdown operations (GDC-34).  
SAFETY DESIGN BASIS EIGHT - The MSSS provides an assured source of steam to operate the turbine-driven auxiliary feedwater pump for reactor cooldown under emergency conditions and for shutdown operations (GDC-34).  


10.3.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The MSSS is designed to deliver steam from the steam generators to the turbine-generator system for a range of flows and pressures varying from warmup to rated conditions. The system provides means to dissipate heat during plant step load reductions and during plant startup. It also provides steam to:
10.3.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The MSSS is designed to deliver steam from  
a. The turbine-generator system second stage reheaters  
 
the steam generators to the turbine-generator system for a range of flows and pressures varying from warmup to rated conditions. The system provides means to dissipate heat during plant step load reductions and during plant startup.
It also provides steam to:
: a. The turbine-generator system second stage reheaters
: b. The main feed pump turbines and auxiliary feed pump turbine
: c. The steam seal system
: d. The turbine bypass system
: e. The auxiliary steam reboiler
: f. The process sampling system
: g. Condenser spargers
 
10.3.2  SYSTEM DESCRIPTION
 
10.3.2.1  General Description The MSSS is shown in Figure 10.3-1. The system conveys steam from the steam
 
generators to the turbine-generator system. The system consists of main steam piping, atmospheric relief valves, safety valves, and main steam isolation valves. The turbine bypass system is discussed in detail in Section 10.4.4.
The MSSS instrumentation, as described in Table 10.3-1, is designed to
 
facilitate automatic operation and remote control of the system and to provide continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the steam line break protection system.
 
10.3-2    Rev. 11 WOLF CREEK 10.3.2.2  Component Description Codes and standards applicable to the MSSS are listed in Table 3.2-1. The MSSS is designed and constructed in accordance with quality group B and seismic Category I requirements from the steam generator out to the torsional restraint downstream of the main steam isolation valves (MSIV). The remaining piping out
 
to the turbine-generator and auxiliaries meets ANSI B31.1 requirements. Design
 
data for the MSSS components are listed in Table 10.3-2.
MAIN STEAM PIPING - Saturated steam from the four steam generators is conveyed


b. The main feed pump turbines and auxiliary feed pump          turbine c. The steam seal system
to the turbine generator by four 28-inch-0.D. lines. The lines are sized for a


d. The turbine bypass system      e. The auxiliary steam reboiler
pressure drop of 25 psi from the steam generators to the turbine stop valves at


f. The process sampling system g. Condenser spargers 10.3.2  SYSTEM DESCRIPTION
turbine manufacturer's guaranteed conditions. Refer to Figure 10.1-2.
Each of the lines is anchored at the containment wall and has sufficient


10.3.2.1  General Description  The MSSS is shown in Figure 10.3-1. The system conveys steam from the steam generators to the turbine-generator system. The system consists of main steam piping, atmospheric relief valves, safety valves, and main steam isolation valves. The turbine bypass system is discussed in detail in Section 10.4.4. The MSSS instrumentation, as described in Table 10.3-1, is designed to facilitate automatic operation and remote control of the system and to provide continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the steam line break protection system. 
flexibility to provide for relative movement of the steam generators due to thermal expansion. The main steam line and associated branch lines between the  


10.3-2    Rev. 11 WOLF CREEK 10.3.2.2  Component Description  Codes and standards applicable to the MSSS are listed in Table 3.2-1. The MSSS is designed and constructed in accordance with quality group B and seismic Category I requirements from the steam generator out to the torsional restraint downstream of the main steam isolation valves (MSIV). The remaining piping out to the turbine-generator and auxiliaries meets ANSI B31.1 requirements. Design data for the MSSS components are listed in Table 10.3-2. MAIN STEAM PIPING - Saturated steam from the four steam generators is conveyed to the turbine generator by four 28-inch-0.D. lines. The lines are sized for a pressure drop of 25 psi from the steam generators to the turbine stop valves at turbine manufacturer's guaranteed conditions. Refer to Figure 10.1-2. Each of the lines is anchored at the containment wall and has sufficient flexibility to provide for relative movement of the steam generators due to thermal expansion. The main steam line and associated branch lines between the containment penetration and the first torsional restraint downstream of the MSIV are designed to meet the "no break zone" criteria of NRC BTP MEB 3-1, as described in Section 3.6.  
containment penetration and the first torsional restraint downstream of the MSIV are designed to meet the "no break zone" criteria of NRC BTP MEB 3-1, as described in Section 3.6.  


Each line is equipped with:
Each line is equipped with:
a. One atmospheric relief valve       b. Five spring-loaded safety valves  
: a. One atmospheric relief valve
: b. Five spring-loaded safety valves
: c. One main steam isolation valve and associated by-pass isolation valve
: d. One low point drain, which is piped to the condenser
 
through a drain valve
 
All main steam branch process line connections are made downstream of the isolation valves with the exception of the line to the atmospheric relief valve, connections for the safety valves, lines to the auxiliary feedwater pump turbine, and low point drains and high point vents.
 
Each steam generator outlet nozzle contains a flow restrictor of 1.4 square feet to limit flow in the event of a MSLB.
 
Immediately upstream of the turbine stop valves, each main steam pipe is cross
 
connected, via an 18-inch line, to a 36-inch header to equalize pressure and flow to the four turbine stop valves. The 18-inch equalizing line limits the back flow from the three 
 
10.3-3    Rev. 11 WOLF CREEK intact steam generators in the event of a MSLB. The cross-connecting piping is sized to permit on-line testing of each turbine stop valve without exceeding
 
allowable limits on steam generator differential pressure. Branch piping downstream of the isolation valves provides steam to the second stage reheaters, steam seal system, main feedwater pump turbines, turbine bypass system, auxiliary steam reboiler, and condenser spargers.
 
POWER-OPERATED ATMOSPHERIC RELIEF VALVE (ARV)- A power-operated, atmospheric, relief valve is installed on the outlet piping from each steam generator. The four valves are installed to provide for controlled removal of reactor decay
 
heat during normal reactor cooldown when the main steam isolation valves are
 
closed or the turbine bypass system is not available. The valves will pass
 
sufficient flow at all pressures to achieve a 50 F per hour plant cooldown rate. The total capacity of the four valves is a minimum of 10 percent of rated main steam flow at steam generator no-load pressure. The maximum actual
 
capacity of the relief valve at design pressure is limited to reduce the magnitude of a reactor transient if one valve would inadvertently open and
 
remain open.
The atmospheric relief valves are air operated carbon steel, 8 inch 1,500 pound
 
globe valves, supplied by a safety-related air supply (as described in Section
 
9.3.1), and controlled from Class IE sources. A nonsafety-related air supply
 
is available during normal operating conditions. The capability for remote manual valve operation is provided in the main control room, the auxiliary shutdown panel and locally at the valves for AB-PV-2 and AB-PV-3. The valves
 
are opened by pneumatic pressure and closed by spring action.
 
SAFETY VALVES - The spring-loaded main steam safety valves provide overpressure protection in accordance with the ASME Section III code requirement for the secondary side of the steam generators and the main steam piping. There are five valves installed in each main steam line. Table 10.3-2 identifies the
 
valves, their set pressure, and capacities. The valves discharge directly to
 
the atmosphere via vent stacks. The maximum actual capacity of the safety valves at the design pressure is limited to reduce the magnitude of a reactor transient if one of the valves would open and remain open.
 
MAIN STEAM ISOLATION VALVES AND BYPASS ISOLATION VALVES - One MSIV and
 
associated bypass isolation valve (BIV) is installed in each of the four main steam lines outside the containment and downstream of the safety valves. The MSIVs are installed to prevent uncontrolled blowdown from more than one steam
 
generator. The valves isolate the nonsafety-related portions from the safety-
 
related portions of the system. The valves are bidirectional, double disc, parallel slide gate valves. 
 
10.3-4 Rev. 24 WOLF CREEK The MSIVs are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or close) is accomplished through a series of six electric solenoid pilot valves, which
 
direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower
 
Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves
 
are divided into two trains that are independently powered and controlled. 
 
Either train can independently perform the safety function to fast close the valve. The lower portion of the valve is the system medium chamber, which remains at system pressure during normal operation. The chamber is connected
 
to the solenoid pilot valve leading to the LPC and UPC through ports internal
 
to the actuator cylinder wall. The system medium chamber is isolated from the
 
piston chamber by means of double stem seals and a leak tight backseat. The closure time for MSIVs is a bounding performance curves as a function of the system pressure relative to the closure time (Fig. 10.3-2). As can be seen
 
from Fig. 10.3-2, the valve is capable of closing within seconds against the
 
flow associated with line breaks on either side of the valve, assuming the most
 
limiting normal operating conditions prior to the occurrence of the break.
Valve closure capability is tested in the manufacturer's facility. Preservice and inservice tests are also performed. Preservice and inservice tests are
 
also performed as discussed in Sections 10.3.4.2 and 10.3.4.3, respectively.
 
The main steam BIV is used when the MSIVs are closed to permit warming of the main steam lines prior to startup. The bypass valves are air-operated globe valves. For emergency closure, either of two separate solenoids, when de-
 
energized, will result in valve closure. Electrical solenoids are energized
 
from a separate Class IE source.
 
10.3.2.3  System Operation NORMAL OPERATION - At low plant power levels, the MSSS supplies steam to the
 
steam generator feedwater pump turbines, the auxiliary steam reboiler, and the
 
turbine steam seal system. At high plant power levels, these components are supplied from turbine extraction steam. Steam is supplied to the second stage steam reheaters in the T-G system when the T-G load exceeds 15 percent.
 
If a large, rapid reduction in T-G load occurs, steam is bypassed (40 percent
 
of VWO) directly to the condenser via the turbine bypass system. The system is capable of accepting a 50-percent load rejection without reactor trip and a full load rejection without lifting safety valves. If the turbine bypass
 
system is not available, steam is vented to the atmosphere via the atmospheric
 
relief valves (ARV) and the safety valves, as required.
 
EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, the MSIV and other valves (except to the auxiliary feedpump
 
turbine) associated with the main steam lines are closed. The ARV may be
 
employed to remove decay heat and to lower the steam generator pressure to
 
achieve cold 
 
10.3-5    Rev. 25 WOLF CREEK shutdown. If the atmospheric relief valve for an individual main steam line is unavailable due to the loss of its control gas supply or power supply, the


c. One main steam isolation valve and associated by-pass          isolation valve d. One low point drain, which is piped to the condenser through a drain valve All main steam branch process line connections are made downstream of the isolation valves with the exception of the line to the atmospheric relief valve, connections for the safety valves, lines to the auxiliary feedwater pump turbine, and low point drains and high point vents.
associated safety valves will provide overpressure protection. The remaining ARVs are sufficient to achieve cold shutdown.
Each steam generator outlet nozzle contains a flow restrictor of 1.4 square feet to limit flow in the event of a MSLB.
In the event that a DBA occurs which results in a SLIS (i.e. large steam line  
Immediately upstream of the turbine stop valves, each main steam pipe is cross connected, via an 18-inch line, to a 36-inch header to equalize pressure and flow to the four turbine stop valves. The 18-inch equalizing line limits the back flow from the three 


10.3-3    Rev. 11 WOLF CREEK intact steam generators in the event of a MSLB. The cross-connecting piping is sized to permit on-line testing of each turbine stop valve without exceeding allowable limits on steam generator differential pressure. Branch piping downstream of the isolation valves provides steam to the second stage reheaters, steam seal system, main feedwater pump turbines, turbine bypass system, auxiliary steam reboiler, and condenser spargers.
break), the MSIV automatically closes. Steam is automatically provided to the  


POWER-OPERATED ATMOSPHERIC RELIEF VALVE (ARV)- A power-operated, atmospheric, relief valve is installed on the outlet piping from each steam generator. The four valves are installed to provide for controlled removal of reactor decay heat during normal reactor cooldown when the main steam isolation valves are closed or the turbine bypass system is not available. The valves will pass sufficient flow at all pressures to achieve a 50 F per hour plant cooldown rate. The total capacity of the four valves is a minimum of 10 percent of rated main steam flow at steam generator no-load pressure. The maximum actual capacity of the relief valve at design pressure is limited to reduce the magnitude of a reactor transient if one valve would inadvertently open and remain open. The atmospheric relief valves are air operated carbon steel, 8 inch 1,500 pound globe valves, supplied by a safety-related air supply (as described in Section 9.3.1), and controlled from Class IE sources. A nonsafety-related air supply is available during normal operating conditions. The capability for remote manual valve operation is provided in the main control room, the auxiliary shutdown panel and locally at the valves for AB-PV-2 and AB-PV-3. The valves are opened by pneumatic pressure and closed by spring action.
auxiliary feedwater pump turbine from two of four steam lines upon low-low level in two steam generators or loss of offsite power. Redundant check valves are installed in the lines to the turbine to ensure that only one steam


SAFETY VALVES - The spring-loaded main steam safety valves provide overpressure protection in accordance with the ASME Section III code requirement for the secondary side of the steam generators and the main steam piping. There are five valves installed in each main steam line. Table 10.3-2 identifies the valves, their set pressure, and capacities. The valves discharge directly to the atmosphere via vent stacks. The maximum actual capacity of the safety valves at the design pressure is limited to reduce the magnitude of a reactor transient if one of the valves would open and remain open.
generator will feed a ruptured main steam line and ensure that one steam


MAIN STEAM ISOLATION VALVES AND BYPASS ISOLATION VALVES - One MSIV and associated bypass isolation valve (BIV) is installed in each of the four main steam lines outside the containment and downstream of the safety valves. The MSIVs are installed to prevent uncontrolled blowdown from more than one steam generator. The valves isolate the nonsafety-related portions from the safety-related portions of the system. The valves are bidirectional, double disc, parallel slide gate valves.   
generator is available to supply steam to the AFW turbine. The closure of  


10.3-4 Rev. 24 WOLF CREEK The MSIVs are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or close) is accomplished through a series of six electric solenoid pilot valves, which direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves are divided into two trains that are independently powered and controlled.
three out of four MSIVs will ensure that no more than one steam generator can supply a postulated break. In addition, closure of the HP turbine steam stop and steam control valves prevents uncontrolled blowdown of more than one steam
Either train can independently perform the safety function to fast close the valve. The lower portion of the valve is the system medium chamber, which remains at system pressure during normal operation. The chamber is connected to the solenoid pilot valve leading to the LPC and UPC through ports internal to the actuator cylinder wall. The system medium chamber is isolated from the piston chamber by means of double stem seals and a leak tight backseat. The closure time for MSIVs is a bounding performance curves as a function of the system pressure relative to the closure time (Fig. 10.3-2). As can be seen from Fig. 10.3-2, the valve is capable of closing within seconds against the flow associated with line breaks on either side of the valve, assuming the most limiting normal operating conditions prior to the occurrence of the break. Valve closure capability is tested in the manufacturer's facility. Preservice and inservice tests are also performed. Preservice and inservice tests are also performed as discussed in Sections 10.3.4.2 and 10.3.4.3, respectively.


The main steam BIV is used when the MSIVs are closed to permit warming of the main steam lines prior to startup. The bypass valves are air-operated globe valves. For emergency closure, either of two separate solenoids, when de-energized, will result in valve closure. Electrical solenoids are energized from a separate Class IE source.
generator following a postulated main steam line break inside the containment.
10.3.2.3 System Operation  NORMAL OPERATION - At low plant power levels, the MSSS supplies steam to the steam generator feedwater pump turbines, the auxiliary steam reboiler, and the turbine steam seal system. At high plant power levels, these components are supplied from turbine extraction steam. Steam is supplied to the second stage steam reheaters in the T-G system when the T-G load exceeds 15 percent.
Reliability of the turbine trip system is discussed in Section 10.2.   


If a large, rapid reduction in T-G load occurs, steam is bypassed (40 percent of VWO) directly to the condenser via the turbine bypass system. The system is capable of accepting a 50-percent load rejection without reactor trip and a full load rejection without lifting safety valves. If the turbine bypass system is not available, steam is vented to the atmosphere via the atmospheric relief valves (ARV) and the safety valves, as required.
Coordinated operation of the auxiliary feedwater system (refer to Section 10.4.9) and ARV or safety valve may be employed to remove decay heat.
EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, the MSIV and other valves (except to the auxiliary feedpump turbine) associated with the main steam lines are closed. The ARV may be employed to remove decay heat and to lower the steam generator pressure to achieve cold 


10.3-5    Rev. 25 WOLF CREEK shutdown. If the atmospheric relief valve for an individual main steam line is unavailable due to the loss of its control gas supply or power supply, the associated safety valves will provide overpressure protection. The remaining ARVs are sufficient to achieve cold shutdown. In the event that a DBA occurs which results in a SLIS (i.e. large steam line break), the MSIV automatically closes. Steam is automatically provided to the auxiliary feedwater pump turbine from two of four steam lines upon low-low level in two steam generators or loss of offsite power. Redundant check valves are installed in the lines to the turbine to ensure that only one steam generator will feed a ruptured main steam line and ensure that one steam generator is available to supply steam to the AFW turbine. The closure of three out of four MSIVs will ensure that no more than one steam generator can supply a postulated break. In addition, closure of the HP turbine steam stop and steam control valves prevents uncontrolled blowdown of more than one steam generator following a postulated main steam line break inside the containment. Reliability of the turbine trip system is discussed in Section 10.2.
Coordinated operation of the auxiliary feedwater system (refer to Section 10.4.9) and ARV or safety valve may be employed to remove decay heat.
10.3.3  SAFETY EVALUATION  
10.3.3  SAFETY EVALUATION  


Safety evaluations are numbered to correspond to the safety design bases of Section 10.3.1.1.
Safety evaluations are numbered to correspond to the safety design bases of Section 10.3.1.1.  
SAFETY EVALUATION ONE - The safety-related portions of the MSSS are located in the reactor and auxiliary buildings. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.  
 
SAFETY EVALUATION ONE - The safety-related portions of the MSSS are located in  
 
the reactor and auxiliary buildings. These buildings are designed to withstand  
 
the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.
 
SAFETY EVALUATION TWO - The safety-related portions of the MSSS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.  


SAFETY EVALUATION TWO - The safety-related portions of the MSSS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.
SAFETY EVALUATION THREE - As indicated by Table 10.3-3, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.  
SAFETY EVALUATION THREE - As indicated by Table 10.3-3, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.  


10.3-6    Rev. 19 WOLF CREEK SAFETY EVALUATION FOUR - The MSSS is initially tested with the program given in Chapter 14.0. Periodic inservice functional testing is done in accordance with Section 10.3.4. Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI requirements that are appropriate for the MSSS.
10.3-6    Rev. 19 WOLF CREEK SAFETY EVALUATION FOUR - The MSSS is initially tested with the program given in Chapter 14.0. Periodic inservice functional testing is done in accordance with  


SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.3-2 shows that the components meet the design and fabrication codes given in Section 3.2. All the power supplies and controls necessary for safety-related functions of the MSSS are Class IE, as described in Chapters 7.0 and 8.0. SAFETY EVALUATION SIX - Redundant power supplies and power trains operate the MSIVs to isolate safety and nonsafety-related portions of the system. Branch lines upstream of the MSIV contain normally closed, atmospheric relief valves which modulate open and closed on steam line pressure. The atmospheric relief valves fail closed on loss of air, and the safety valves provide the overpressure protection.
Section 10.3.4.
Accidental releases of radioactivity from the MSSS are minimized by the negligible amount of radioactivity in the system under normal operating conditions. Additionally, the main steam isolation system provides controls for reducing accidental releases, as discussed in Chapter 15.0, following a steam generator tube rupture.  
Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI requirements that are appropriate for the MSSS.
 
SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.3-2 shows that the components meet  
 
the design and fabrication codes given in Section 3.2. All the power supplies  
 
and controls necessary for safety-related functions of the MSSS are Class IE, as described in Chapters 7.0 and 8.0.
SAFETY EVALUATION SIX - Redundant power supplies and power trains operate the  
 
MSIVs to isolate safety and nonsafety-related portions of the system. Branch lines upstream of the MSIV contain normally closed, atmospheric relief valves which modulate open and closed on steam line pressure. The atmospheric relief valves fail closed on loss of air, and the safety valves provide the overpressure protection.  
 
Accidental releases of radioactivity from the MSSS are minimized by the negligible amount of radioactivity in the system under normal operating conditions. Additionally, the main steam isolation system provides controls for reducing accidental releases, as discussed in Chapter 15.0, following a  
 
steam generator tube rupture.  


Detection of radioactive leakage into and out of the system is facilitated by area radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).  
Detection of radioactive leakage into and out of the system is facilitated by area radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).  


SAFETY EVALUATION SEVEN - Each main steam line is provided with safety valves that limit the pressure in the line to preclude overpressurization and remove stored energy. Each line is provided with an atmospheric relief valve to permit reduction of the main steam line pressure and remove stored energy to achieve an orderly shutdown. The auxiliary feedwater system, which is described and evaluated in Section 10.4.9, provides makeup to the steam generators consistent with the steaming rate.
SAFETY EVALUATION SEVEN - Each main steam line is provided with safety valves that limit the pressure in the line to preclude overpressurization and remove stored energy. Each line is provided with an atmospheric relief valve to  
SAFETY EVALUATION EIGHT - The steam line to the auxiliary feedwater pump turbine is connected to a cross-connecting header upstream of the MSIV. This arrangement ensures a supply of steam to this turbine when the steam generators are isolated. Redundant 


10.3-7    Rev. 11 WOLF CREEK check valves are provided in each supply line from the main steam lines to preclude any potential backflow during a postulated main steam line break. The auxiliary feedwater system is described in Section 10.4.9. 10.3.4  INSPECTION AND TESTING REQUIREMENTS 10.3.4.1  Preservice Valve Testing  The set pressures of the safety valves are individually checked during initial startup either by bench testing or with a pneumatic test device. A pneumatic test device is attached to the valve stem. The pneumatic pressure is applied until the valve seat just lifts, as indicated by the steam noise. Combination of the steam pressure and pneumatic pressure with calibration data furnished by the valve manufacturer verifies the set pressure.
permit reduction of the main steam line pressure and remove stored energy to  
The lift-point of each ARV is verified by channel check and channel calibration. The MSIVs were checked for closing time prior to initial startup. 10.3.4.2  Preservice System Testing Preoperational testing is described in Chapter 14.0. The MSSS is designed to include the capability for testing through the full operational sequence that brings the system into operation for reactor shutdown and for MSLB accidents, including operation of applicable portions of the protection system and the transfer between normal and standby power sources. The safety-related components of the system, i.e. valves and piping, are designed and located to permit preservice and inservice inspections to the extent practicable.
10.3.4.3  Inservice Testing  The performance and structural and leaktight integrity of all system components are demonstrated by continuous operation.
The redundant actuator power trains of each MSIV are subjected to the following tests:


a. Closure time - The valves are checked for closure time at each refueling. 
achieve an orderly shutdown. The auxiliary feedwater system, which is


10.3-8    Rev. 11 WOLF CREEK  Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is contained in Section 6.6. 10.3.5  SECONDARY WATER CHEMISTRY (PWR)  10.3.5.1  Chemistry Control Basis  Steam generator secondary side water chemistry control is accomplished by:      a. A close control of the feedwater chemistry to limit the          amount of impurities that can be introduced into the steam generator      b. The capability of a continuous blowdown of the steam generators to reduce concentrating effects of the steam generator c. Chemical addition to establish and maintain an          environment that minimizes system corrosion
described and evaluated in Section 10.4.9, provides makeup to the steam generators consistent with the steaming rate.  


d. By post-construction cleaning of the feedwater system      e. Minimizing feedwater oxygen content prior to entry into          the steam generator by deaeration in the hotwell
SAFETY EVALUATION EIGHT - The steam line to the auxiliary feedwater pump


f. The capability of continuous demineralization and filtration of the condensate system through full-flow,          deep bed condensate demineralizers.
turbine is connected to a cross-connecting header upstream of the MSIV. This  
Secondary water chemistry is based on the all volatile treatment (AVT) method.
This method employs the use of volatile additives to maintain system pH and to scavenge dissolved oxygen present in the feedwater. A pH control chemical such as ammonia and/or an or an organic amine is added to establish and maintain alkaline conditions in the feedtrain. Although the pH control chemical is volatile and will not concentrate in the steam generator, it will reach an equilibrium level which will establish an alkaline condition in the steam generator. An oxygen control chemical is added to scavenge dissolved oxygen present in the feedwater. The oxygen control chemical also tends to promote the formation of a protective oxide layer on metal surfaces by keeping these layers in a reduced chemical state. 


10.3-9    Rev. 24 WOLF CREEK Both the pH control chemical and the oxygen control chemical can be injected continuously at the discharge headers of the condensate pumps and are added, as necessary, for chemistry control. Operating chemistry guidelines for secondary steam generator water have been developed using EPRI guidelines and Westinghouse chemistry recommendations with actual implementation and control being defined and maintained in plant chemistry procedures. Water chemistry monitoring is discussed in Section 9.3.2. The requirements of BTP MTEB 5-3 are met. The condensate demineralizer system is discussed in Section 10.4.6.  
arrangement ensures a supply of steam to this turbine when the steam generators are isolated. Redundant 


10.3.5.2  Corrosion Control Effectiveness Alkaline conditions in the feedtrain and the steam generator reduce general corrosion at elevated temperatures and tend to decrease the release of soluble corrosion products from metal surfaces. These conditions promote formation of a protective metal oxide film and thus reduce the corrosion products released into the steam generator.
10.3-7    Rev. 11 WOLF CREEK check valves are provided in each supply line from the main steam lines to preclude any potential backflow during a postulated main steam line break. The  
An oxygen control chemical also promotes formation of a metal oxide film by the reduction of ferric oxide to magnetite. Ferric oxide may be loosened from the metal surfaces and be transported by the feedwater. Magnetite, however, provides an adhesive, protective layer on carbon steel surfaces. An oxygen control chemical also promotes formation of protective metal oxide layers on copper surfaces. Removal of oxygen from the secondary waters is also essential in reducing corrosion. Oxygen dissolved in water causes general corrosion that can result in pitting of ferrous metals, particularly carbon steel. Oxygen is removed from the steam cycle condensate in the main condenser deaerating section. Additional oxygen protection is obtained by chemical injection of an oxygen control chemical into the condensate stream. Maintaining a residual level of oxygen control chemical in the feedwater ensures that any dissolved oxygen not removed by the main condenser is scavenged before it can enter the steam generator.
The presence of free hydroxide (OH) can cause rapid corrosion (caustic stress corrosion) if it is allowed to concentrate in a local area. Free hydroxide is avoided by maintaining proper pH control and by minimizing impurity ingress into the steam generator.
AVT control is a technique whereby both soluble and insoluble solids are kept at a minimum within the steam generator. This is accomplished by maintaining strict surveillance over the possible sources of feedtrain contamination (e.g., main condenser cooling 


10.3-10 Rev. 13 WOLF CREEK water leakage, air inleakage, and subsequent corrosion product generation in the low pressure drain system, etc.). Solids are also excluded, as discussed above, by injecting only volatile chemicals to establish conditions that reduce corrosion and, therefore, reduce transport of corrosion products into the steam generator.
auxiliary feedwater system is described in Section 10.4.9.
In addition to minimizing the sources of contaminants entering the steam generator, condensate demineralizers are used when required, and a continuous blowdown from the steam generators is employed to limit the concentration of contaminants. With the low solids level that results from employing the above procedures, the accumulation of scale and deposits on steam generator heat transfer surfaces and internals is limited. Scale and deposit formations can alter the thermal hydraulic performance in local regions which creates a mechanism that allows impurities to concentrate and thus possibly cause corrosion. The effect of this type of corrosion is reduced by limiting the ingress of solids into the steam generator and limiting their buildup.  
10.3.4  INSPECTION AND TESTING REQUIREMENTS
 
10.3.4.1  Preservice Valve Testing The set pressures of the safety valves are individually checked during initial startup either by bench testing or with a pneumatic test device. A pneumatic test device is attached to the valve stem. The pneumatic pressure is applied until the valve seat just lifts, as indicated by the steam noise. Combination
 
of the steam pressure and pneumatic pressure with calibration data furnished by the valve manufacturer verifies the set pressure.
 
The lift-point of each ARV is verified by channel check and channel calibration.
The MSIVs were checked for closing time prior to initial startup.
10.3.4.2  Preservice System Testing
 
Preoperational testing is described in Chapter 14.0.
The MSSS is designed to include the capability for testing through the full operational sequence that brings the system into operation for reactor shutdown
 
and for MSLB accidents, including operation of applicable portions of the
 
protection system and the transfer between normal and standby power sources.
The safety-related components of the system, i.e. valves and piping, are
 
designed and located to permit preservice and inservice inspections to the
 
extent practicable.
 
10.3.4.3  Inservice Testing The performance and structural and leaktight integrity of all system components
 
are demonstrated by continuous operation.
 
The redundant actuator power trains of each MSIV are subjected to the following tests:
: a. Closure time - The valves are checked for closure time
 
at each refueling.
 
10.3-8    Rev. 11 WOLF CREEK Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is contained in Section 6.6.
10.3.5  SECONDARY WATER CHEMISTRY (PWR) 10.3.5.1  Chemistry Control Basis Steam generator secondary side water chemistry control is accomplished by:
: a. A close control of the feedwater chemistry to limit the amount of impurities that can be introduced into the
 
steam generator
: b. The capability of a continuous blowdown of the steam
 
generators to reduce concentrating effects of the steam
 
generator
: c. Chemical addition to establish and maintain an environment that minimizes system corrosion
: d. By post-construction cleaning of the feedwater system
: e. Minimizing feedwater oxygen content prior to entry into the steam generator by deaeration in the hotwell
: f. The capability of continuous demineralization and
 
filtration of the condensate system through full-flow,          deep bed condensate demineralizers.
 
Secondary water chemistry is based on the all volatile treatment (AVT) method. 
 
This method employs the use of volatile additives to maintain system pH and to
 
scavenge dissolved oxygen present in the feedwater. A pH control chemical such as ammonia and/or an or an organic amine is added to establish and maintain alkaline conditions in the feedtrain. Although the pH control chemical is
 
volatile and will not concentrate in the steam generator, it will reach an equilibrium level which will establish an alkaline condition in the steam
 
generator.
An oxygen control chemical is added to scavenge dissolved oxygen present in the
 
feedwater. The oxygen control chemical also tends to promote the formation of
 
a protective oxide layer on metal surfaces by keeping these layers in a reduced
 
chemical state.
 
10.3-9    Rev. 24 WOLF CREEK Both the pH control chemical and the oxygen control chemical can be injected continuously at the discharge headers of the condensate pumps and are added, as
 
necessary, for chemistry control.
Operating chemistry guidelines for secondary steam generator water have been developed using EPRI guidelines and Westinghouse chemistry recommendations with actual implementation and control being defined and maintained in plant chemistry procedures. Water chemistry monitoring is discussed in Section 9.3.2. The requirements of BTP MTEB 5-3 are met.
The condensate demineralizer system is discussed in Section 10.4.6.
 
10.3.5.2  Corrosion Control Effectiveness
 
Alkaline conditions in the feedtrain and the steam generator reduce general
 
corrosion at elevated temperatures and tend to decrease the release of soluble corrosion products from metal surfaces. These conditions promote formation of a protective metal oxide film and thus reduce the corrosion products released into the steam generator.
 
An oxygen control chemical also promotes formation of a metal oxide film by the
 
reduction of ferric oxide to magnetite. Ferric oxide may be loosened from the
 
metal surfaces and be transported by the feedwater. Magnetite, however, provides an adhesive, protective layer on carbon steel surfaces. An oxygen control chemical also promotes formation of protective metal oxide layers on
 
copper surfaces. Removal of oxygen from the secondary waters is also essential
 
in reducing corrosion. Oxygen dissolved in water causes general corrosion that
 
can result in pitting of ferrous metals, particularly carbon steel. Oxygen is removed from the steam cycle condensate in the main condenser deaerating section. Additional oxygen protection is obtained by chemical injection of an
 
oxygen control chemical into the condensate stream. Maintaining a residual
 
level of oxygen control chemical in the feedwater ensures that any dissolved
 
oxygen not removed by the main condenser is scavenged before it can enter the steam generator.
 
The presence of free hydroxide (OH) can cause rapid corrosion (caustic stress
 
corrosion) if it is allowed to concentrate in a local area. Free hydroxide is
 
avoided by maintaining proper pH control and by minimizing impurity ingress into the steam generator.
 
AVT control is a technique whereby both soluble and insoluble solids are kept at a minimum within the steam generator. This is accomplished by maintaining
 
strict surveillance over the possible sources of feedtrain contamination (e.g., main condenser cooling 
 
10.3-10 Rev. 13 WOLF CREEK water leakage, air inleakage, and subsequent corrosion product generation in the low pressure drain system, etc.). Solids are also excluded, as discussed  
 
above, by injecting only volatile chemicals to establish conditions that reduce corrosion and, therefore, reduce transport of corrosion products into the steam generator.  
 
In addition to minimizing the sources of contaminants entering the steam  
 
generator, condensate demineralizers are used when required, and a continuous blowdown from the steam generators is employed to limit the concentration of contaminants. With the low solids level that results from employing the above  
 
procedures, the accumulation of scale and deposits on steam generator heat  
 
transfer surfaces and internals is limited. Scale and deposit formations can  
 
alter the thermal hydraulic performance in local regions which creates a mechanism that allows impurities to concentrate and thus possibly cause corrosion. The effect of this type of corrosion is reduced by limiting the  
 
ingress of solids into the steam generator and limiting their buildup.  


The chemical additives, because they are volatile, do not concentrate in the steam generator and do not represent chemical impurities that can themselves cause corrosion.  
The chemical additives, because they are volatile, do not concentrate in the steam generator and do not represent chemical impurities that can themselves cause corrosion.  


10.3.6  STEAM AND FEEDWATER SYSTEM MATERIALS 10.3.6.1  Fracture Toughness Compliance with fracture toughness requirements of ASME III, Article NC-2300 is discussed in Section 6.1.
10.3.6  STEAM AND FEEDWATER SYSTEM MATERIALS  
10.3.6.2  Material Selection and Fabrication All pipe, flanges, fittings, valves, and other piping material conform to the referenced ASME, ASTM, ANSI, or MSS-SP code.
 
The following code requirements apply:
10.3.6.1  Fracture Toughness Compliance with fracture toughness requirements of ASME III, Article NC-2300 is  
Stainless Steel           Carbon Steel Pipe          ANSI B36.19                ANSI B36.10 Fittings      ANSI B16.9, B16.11 or      ANSI B16.9, B16.11 or                 B16.28                    B16.28  
 
discussed in Section 6.1.  
 
10.3.6.2  Material Selection and Fabrication All pipe, flanges, fittings, valves, and other piping material conform to the  
 
referenced ASME, ASTM, ANSI, or MSS-SP code.  
 
The following code requirements apply:  
 
Stainless Steel Carbon Steel Pipe          ANSI B36.19                ANSI B36.10 Fittings      ANSI B16.9, B16.11 or      ANSI B16.9, B16.11 or B16.28                    B16.28  
 
Flanges      ANSI B16.5                ANSI B16.5
 
10.3-11    Rev. 18 WOLF CREEK The following ASME Material Specifications apply specifically:


Flanges      ANSI B16.5                ANSI B16.5 
ASME SA-155 GR KCF 70 Class 1 (impact tested)
ASME SA-155 GR KCF 70 Class 1


10.3-11    Rev. 18 WOLF CREEK The following ASME Material Specifications apply specifically:
ASME SA-106, GR C (impact tested)  
ASME SA-155 GR KCF 70 Class 1 (impact tested)      ASME SA-155 GR KCF 70 Class 1 ASME SA-106, GR C (impact tested)
ASME SA-106, GR, B ASME SA-106, GR, B (normalized)  


ASME SA-234 GR WPB      ASME SA-234 GR WPBW (Mfd from gr 70 plate)
ASME SA-106, GR, B
ASME SA-234 GR WPC ASME SA-105 ASME SA-193 GR B7


ASME SA-194 GR 2H/Grade 7  ASME SA-194 GR 7      ASME SA-216 GR WCB ASME SA-333 GR 6 (impact tested)      ASME SA-420 GR WPL6 (impact tested)  
ASME SA-106, GR, B (normalized)  


ASME SA-508 Class 1 (impact tested)      ASME SA-312, TP 304
ASME SA-234 GR WPB ASME SA-234 GR WPBW (Mfd from gr 70 plate)


ASME SA-403, WP-304 ASME SA-403, WP-304 W ASME SA-182, F-304 ASME SA 672 GR C70  ASME SA 350 GR LF2 (impact tested)  Compliance with the following Regulatory Guides is discussed in Section 6.1:
ASME SA-234 GR WPC


Regulatory Guide 1.31 - Control of Stainless Steel Welding 
ASME SA-105


10.3-12    Rev. 23 WOLF CREEK      Regulatory Guide 1.36 - Nonmetallic Thermal Insulation for      Austenitic Stainless Steel Regulatory Guide 1.37 - Quality Assurance Requirement for      Cleaning of Fluid Systems and Associated Components of Water-      cooled Nuclear Power Plants
ASME SA-193 GR B7


Regulatory Guide 1.44 - Control of the Use of Sensitized      Stainless Steel Regulatory Guide 1.50 - Control of Preheat Temperatures for Welding of Low-Alloy Steels Regulatory Guide 1.71 - Welder Qualification for Areas of      Limited Accessibility
ASME SA-194 GR 2H/Grade 7 ASME SA-194 GR 7 ASME SA-216 GR WCB


10.3-13    Rev. 0 WOLF CREEK TABLE 10.3-1  MAIN STEAM SUPPLY SYSTEM CONTROL, INDICATING AND ALARM DEVICES 
ASME SA-333 GR 6 (impact tested)
ASME SA-420 GR WPL6 (impact tested)


Device Control Room  Local Control Room Alarm Flow rate indication (2)        Yes        -         Yes (4)
ASME SA-508 Class 1 (impact tested)
Pressure indication (1)(3)      Yes (5)    -             - Pressure Control                Yes        -            -  (1)  For each generator, three devices are involved in 2-out-of-3 logic to generate input to reactor trip, SLIS, and SIS
ASME SA-312, TP 304


(2)  Two per steamline  (3)  Total of four per steamline
ASME SA-403, WP-304


(4)  Steam flow - feed flow mismatch (5)  One per steamline (atmospheric relief valves) 
ASME SA-403, WP-304 W


Rev. 24 WOLF CREEK TABLE 10.3-2  MAIN STEAM SUPPLY SYSTEM DESIGN DATA  Main Steam Piping (Safety-Related Portion)  Design VWO flowrate at 1,000 psia and 0.25 percent moisture, lb/hr 15,850,801 Power Rerate flowrate at 970 psia and 0.25 percent moisture, lb/hr 15,906,000 Reduced Thermal Design flowrate at 944 psia and 0.25 percent moisture, lb/hr 15,920,000 Number of lines 4 0.D., in. 28 Minimum wall thickness, in. 1.5 Design pressure, psia 1,200 Design temperature, F 600 Design code ASME Section III, Class 2 Seismic design Category I  Main Steam Isolation Valves  Number per main steam line 1 Closing time, seconds 1.5 to 5 (at normal operating conditions prior to receiving isolation signal)  Design code ASME Section III, Class 2 Seismic design Category I  Atmospheric Relief Valves  Number per main steam line 1 Normal set pressure, psig 1,125 Capacity (each) at 1,107 psia, lb/hr 594,642 Capacity (each) at 100 psia, lb/hr 54,000 Design code ASME Section III, Class 2 Seismic design Category I  Main Steam Safety Valves  Number per main steam line 5 Orifice area, sq in. 16 Size, in. 6 x 8 x 8 Design code ASME Section III, Class 2 Seismic design Category I  Set Pressure Capacity at 3-Percent Accumulation Number (psig) (lb/hr)  1 1185 893,160 2 1197 902,096 3 1210 911,779 4 1222 920,715 5 1234 929,652 Rev. 24 WOLF CREEK  TABLE 10.3-2 (SHEET 2)    MAIN STEAM SUPPLY SYSTEM DESIGN DATA    The Following information provides the "FLOWRATE PER STEAMLINE" and the  "TOTAL SYSTEM FLOWRATE" using regression limits and spring constants (K- RATEs) varying from 25000 to 27770 lbf/in, for the Main Steam Safety Valves  (MSSVs). K-RATE REGRESSION FLOWRATE PER  TOTAL SYSTEM  LBF/IN LIMIT  STEAMLINE LMB/HR FLOWRATE LMB/HR  25000  Lower Limit  4913613  19654452  25000 Regression Line 5131912 20527648  25000 Upper Limit 5149865 20599460      27770 Lower Limit 4212594 16850376  27770 Regression Line 4695591 18782364  27770 Upper Limit 5045732 20182928 
ASME SA-182, F-304


Rev. 7 WOLF CREEK                                   TABLE 10.3-3                                 MAIN STEAM SYSTEM                           SINGLE ACTIVE FAILURE ANALYSIS         Component                    Failure                   Comments1. Main steam line iso-    Loss of power from one      Redundant power supply     lation and bypass        power supply                provided. valves.
ASME SA 672 GR C70 ASME SA 350 GR LF2 (impact tested)
Valve fails to close        Closure of three out                             upon receipt of auto-        of four isolation                             matic signal (SLIS)          valves adequate to meet requirements.2. Atmospheric relief      Loss of power or air        Safety valves provide     valves                  to valve fails to modu-      overpressure protection                             late upon high pressure      for the associate line.                                                           Atmospheric relief                                                           valves on two out of                                                           four lines adequate                                                           to meet shutdown re-quirements.3. Pressure transmitters    No signal generated for      For each generator                             protection logic            2-out-of-3 logic                                                           reverts to 1-out-of-2                                                           logic, and protection                                                           logic is generated by                                                           other devices. Refer                                                           to Chapter 7.0.                                                                             Rev. 0 WOLF CREEK                               TABLE 10.3-3 (Sheet 2)         Component                    Failure                   Comments4. Main steam line drain    Valve fails to close        Negligible steam lost     line isolation valve    upon receipt of auto-        from generator. In                             matic signal (SLIS)          addition, three of                                                           four intact secondary                                                           loops are required                                                           to meet safety require-ments.5. Steam supply valve to    Valve fails to open          Redundant valve pro-     auxiliary feedpump      upon receipt of auto-        vides 100 percent of     turbine                  matic signal (AFAS)          flow requirements to                                                           the auxiliary feed pump turbine.                             Supplied from broken        Redundant motor-driven                             secondary loop and          auxiliary feedwater                             train of power for          pump meets 100 per-                             redundant supply            cent of auxiliary feed-valve lost                  water requirements.                                                                             Rev. 0 WOLF CREEK 10.4  OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM This section provides discussions of each of the principal design features of the steam and power conversion system. 10.4.1  MAIN CONDENSERS The main condenser is the steam cycle heat sink. During normal operation, it receives and condenses main turbine exhaust steam, steam generator feedwater pump turbine exhaust steam, and turbine bypass steam. The main condenser is also a collection point for other steam cycle miscellaneous flows, drains, and vents. The main condenser is utilized as a heat sink for reactor cooldown during a normal plant shutdown.
Compliance with the following Regulatory Guides is discussed in Section 6.1:
10.4.1.1  Design Bases 10.4.1.1.1  Safety Design Bases The main condenser serves no safety function and has no safety design basis. 10.4.1.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The main condenser is designed to function as the steam cycle heat sink and miscellaneous flow collection point.
 
POWER GENERATION DESIGN BASIS TWO - The main condenser accommodates up to 40 percent of the VWO main steam flow which is bypassed directly to the condenser by the turbine bypass system.  
Regulatory Guide 1.31 - Control of Stainless Steel Welding
 
10.3-12    Rev. 23 WOLF CREEK Regulatory Guide 1.36 - Nonmetallic Thermal Insulation for Austenitic Stainless Steel
 
Regulatory Guide 1.37 - Quality Assurance Requirement for Cleaning of Fluid Systems and Associated Components of Water-cooled Nuclear Power Plants
 
Regulatory Guide 1.44 - Control of the Use of Sensitized Stainless Steel
 
Regulatory Guide 1.50 - Control of Preheat Temperatures for
 
Welding of Low-Alloy Steels
 
Regulatory Guide 1.71 - Welder Qualification for Areas of Limited Accessibility
 
10.3-13    Rev. 0 WOLF CREEK TABLE 10.3-1 MAIN STEAM SUPPLY SYSTEM CONTROL, INDICATING AND ALARM DEVICES
 
Device Control Room  Local Control Room Alarm Flow rate indication (2)        Yes        -          Yes (4)
 
Pressure indication (1)(3)      Yes (5)    -            -
Pressure Control                Yes        -            -
(1)  For each generator, three devices are involved in 2-out-of-3
 
logic to generate input to reactor trip, SLIS, and SIS
 
(2)  Two per steamline (3)  Total of four per steamline
 
(4)  Steam flow - feed flow mismatch
 
(5)  One per steamline (atmospheric relief valves)
 
Rev. 24 WOLF CREEK TABLE 10.3-2 MAIN STEAM SUPPLY SYSTEM DESIGN DATA Main Steam Piping (Safety-Related Portion)
Design VWO flowrate at 1,000 psia and 0.25 percent moisture, lb/hr 15,850,801
 
Power Rerate flowrate at 970 psia and 0.25 percent moisture, lb/hr 15,906,000
 
Reduced Thermal Design flowrate at 944 psia and 0.25 percent moisture, lb/hr 15,920,000 Number of lines 4 0.D., in. 28 Minimum wall thickness, in. 1.5 Design pressure, psia 1,200 Design temperature, F 600 Design code ASME Section III, Class 2 Seismic design Category I Main Steam Isolation Valves Number per main steam line 1 Closing time, seconds 1.5 to 5 (at normal operating conditions prior to receiving isolation signal)  Design code ASME Section III, Class 2 Seismic design Category I Atmospheric Relief Valves Number per main steam line 1 Normal set pressure, psig 1,125 Capacity (each) at 1,107 psia, lb/hr 594,642 Capacity (each) at 100 psia, lb/hr 54,000 Design code ASME Section III, Class 2 Seismic design Category I Main Steam Safety Valves Number per main steam line 5 Orifice area, sq in. 16 Size, in. 6 x 8 x 8 Design code ASME Section III, Class 2 Seismic design Category I Set Pressure Capacity at 3-Percent Accumulation Number (psig) (lb/hr) 1 1185 893,160 2 1197 902,096 3 1210 911,779 4 1222 920,715 5 1234 929,652
 
Rev. 24 WOLF CREEK TABLE 10.3-2 (SHEET 2)
MAIN STEAM SUPPLY SYSTEM DESIGN DATA The Following information provides the "FLOWRATE PER STEAMLINE" and the  "TOTAL SYSTEM FLOWRATE" using regression limits and spring constants (K-RATEs) varying from 25000 to 27770 lbf/in, for the Main Steam Safety Valves  (MSSVs).
K-RATE REGRESSION FLOWRATE PER  TOTAL SYSTEM  LBF/IN LIMIT  STEAMLINE LMB/HR FLOWRATE LMB/HR 25000  Lower Limit 4913613  19654452  25000 Regression Line 5131912 20527648  25000 Upper Limit 5149865 20599460      27770 Lower Limit 4212594 16850376  27770 Regression Line 4695591 18782364  27770 Upper Limit 5045732 20182928 
 
Rev. 7 WOLF CREEK TABLE 10.3-3 MAIN STEAM SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component                    Failure Comments
: 1. Main steam line iso-    Loss of power from one      Redundant power supply lation and bypass        power supply                provided.
valves.
 
Valve fails to close        Closure of three out upon receipt of auto-        of four isolation matic signal (SLIS)          valves adequate to meet
 
requirements.
: 2. Atmospheric relief      Loss of power or air        Safety valves provide valves                  to valve fails to modu-      overpressure protection late upon high pressure      for the associate line.
Atmospheric relief valves on two out of four lines adequate to meet shutdown re-
 
quirements.
: 3. Pressure transmitters    No signal generated for      For each generator protection logic            2-out-of-3 logic reverts to 1-out-of-2 logic, and protection logic is generated by other devices. Refer to Chapter 7.0.
Rev. 0 WOLF CREEK TABLE 10.3-3 (Sheet 2)
Component                    Failure Comments
: 4. Main steam line drain    Valve fails to close        Negligible steam lost line isolation valve    upon receipt of auto-        from generator. In matic signal (SLIS)          addition, three of four intact secondary loops are required to meet safety require-
 
ments.
: 5. Steam supply valve to    Valve fails to open          Redundant valve pro-auxiliary feedpump      upon receipt of auto-        vides 100 percent of turbine                  matic signal (AFAS)          flow requirements to the auxiliary feed
 
pump turbine.
Supplied from broken        Redundant motor-driven secondary loop and          auxiliary feedwater train of power for          pump meets 100 per-redundant supply            cent of auxiliary feed-
 
valve lost                  water requirements.
Rev. 0 WOLF CREEK 10.4  OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM This section provides discussions of each of the principal design features of the steam and power conversion system.
10.4.1  MAIN CONDENSERS  
 
The main condenser is the steam cycle heat sink. During normal operation, it receives and condenses main turbine exhaust steam, steam generator feedwater  
 
pump turbine exhaust steam, and turbine bypass steam. The main condenser is  
 
also a collection point for other steam cycle miscellaneous flows, drains, and  
 
vents. The main condenser is utilized as a heat sink for reactor cooldown during a normal plant shutdown.  
 
10.4.1.1  Design Bases 10.4.1.1.1  Safety Design Bases  
 
The main condenser serves no safety function and has no safety design basis.
10.4.1.1.2  Power Generation Design Bases  
 
POWER GENERATION DESIGN BASIS ONE - The main condenser is designed to function  
 
as the steam cycle heat sink and miscellaneous flow collection point.  
 
POWER GENERATION DESIGN BASIS TWO - The main condenser accommodates up to 40 percent of the VWO main steam flow which is bypassed directly to the condenser  
 
by the turbine bypass system.  


POWER GENERATION DESIGN BASIS THREE - The main condenser provides for the removal of noncondensable gases from the condensing steam through the main condenser air removal system, as described in Section 10.4.2.  
POWER GENERATION DESIGN BASIS THREE - The main condenser provides for the removal of noncondensable gases from the condensing steam through the main condenser air removal system, as described in Section 10.4.2.  


POWER GENERATION DESIGN BASIS FOUR - The main condenser provides the surge volume required for the condensate and feedwater system. POWER GENERATION DESIGN BASIS FIVE - The main condenser provides for deaeration of the condensate, such that condensate oxygen content should not exceed 7 ppb under normal full power operating condition.   
POWER GENERATION DESIGN BASIS FOUR - The main condenser provides the surge  
 
volume required for the condensate and feedwater system.
POWER GENERATION DESIGN BASIS FIVE - The main condenser provides for deaeration  
 
of the condensate, such that condensate oxygen content should not exceed 7 ppb
 
under normal full power operating condition.   
 
10.4-1 Rev. 13 WOLF CREEK 10 4.1.2  System Description 10.4.1.2.1  General Description The main condenser is a multipressure, three-shell, deaerating unit. Each
 
shell is located beneath its respective low-pressure turbine. The tubes in
 
each shell are oriented transverse to the turbine-generator longitudinal axis.
 
The three condenser shells are designated as the low-pressure shell, the intermediate-pressure shell, and the high-pressure shell. Each shell has six
 
tube bundles. Circulating water flows in series through the three single-pass
 
shells, as shown in Figure 10.4-1.
 
Exhaust steam from the steam generator feedwater pump turbine is used to reheat the condensate in the condenser. Each hotwell is divided longitudinally by a
 
vertical partition plate. The condensate pumps take suction from these
 
hotwells, as shown in Figure 10.4-2.
 
The condenser shells are located in pits below the turbine building operating floor and are supported above the turbine building foundation. Failure of or
 
leakage from a condenser shell will only result in a minimum water level in the


10.4-1 Rev. 13 WOLF CREEK 10 4.1.2  System Description  10.4.1.2.1  General Description  The main condenser is a multipressure, three-shell, deaerating unit. Each shell is located beneath its respective low-pressure turbine. The tubes in each shell are oriented transverse to the turbine-generator longitudinal axis.
condenser pit. Expansion joints are provided between each turbine exhaust  
The three condenser shells are designated as the low-pressure shell, the intermediate-pressure shell, and the high-pressure shell. Each shell has six tube bundles. Circulating water flows in series through the three single-pass shells, as shown in Figure 10.4-1.
Exhaust steam from the steam generator feedwater pump turbine is used to reheat the condensate in the condenser. Each hotwell is divided longitudinally by a vertical partition plate. The condensate pumps take suction from these hotwells, as shown in Figure 10.4-2.
The condenser shells are located in pits below the turbine building operating floor and are supported above the turbine building foundation. Failure of or leakage from a condenser shell will only result in a minimum water level in the condenser pit. Expansion joints are provided between each turbine exhaust opening and the steam inlet connections of the condenser shell. Water seals are provided around the entire outside periphery of these expansion joints, but are only placed in service (filled with water) during post maintenance testing following new joint installation and in times when it is expected that an expansion joints vacuum seal has been breached. When water seals are filled with water, level indication provides detection of leakage through the expansion joint. The hotwells of the three shells are interconnected by steam-equalizing lines. Four low-pressure feedwater heaters are located in the steam dome of each shell. Piping is installed for hotwell level control and condensate sampling.
10.4.1.2.2  Component Description Table 10.4-1 provides the design data for each condenser shell for both the closed loop and open loop circulating water systems.
10.4.1.2.3  System Operation During normal operation, exhaust steam from the low-pressure turbines is directed into the main condenser shells. The condenser also receives auxiliary system flows, such as feedwater heater vents and drains and feedwater pump turbine exhaust. 


10.4-2 Rev. 29 WOLF CREEK Hotwell level controls provide automatic makeup or rejection of condensate to maintain a normal level in the condenser hotwells. On low water level in a hotwell, the makeup control valves open and admit condensate to the hotwell from the condensate storage tank. When the hotwell is brought to within normal-operating range, the valves close. On high water level in the hotwell, the condensate reject control valve opens to divert condensate from the condensate pump discharge (downstream of the demineralizers) to the condensate storage tank; rejection is stopped when the hotwell level falls to within normal operating range.
opening and the steam inlet connections of the condenser shell. Water seals are provided around the entire outside periphery of these expansion joints, but are only placed in service (filled with water) during post maintenance testing following new joint installation and in times when it is expected that an expansion joints vacuum seal has been breached. When water seals are filled with water, level indication provides detection of leakage through the expansion joint. The hotwells of the three shells are interconnected by steam-equalizing lines. Four low-pressure feedwater heaters are located in the steam  
Sparger piping is provided for distribution of turbine bypass discharge and other high temperature drains. Orifices are provided internal to the spargers where necessary for pressure reduction prior to distribution within the condenser. Where sparger piping cannot be utilized due to space limitations, baffles are provided to direct the discharge away from the tubes and other condenser components. Pressure reducing orifices are provided in the drains piping outside the condenser, where required.
The main condenser, with the assistance of auxiliary steam at low loads, deaerates the condensate so that dissolved oxygen should not exceed 7 ppb over the entire load range. Both the air inleakage and the noncondensable gases contained in the turbine exhaust are collected in the condenser and removed by the condenser air removal system. During the cooling period after plant shutdown, the main condenser removes residual heat from the reactor coolant system via the turbine bypass system.
The main condenser receives up to 40 percent of VWO main steam flow through the turbine bypass valves. If the condenser is not available to receive steam via the turbine bypass system, the reactor coolant system can be safely cooled down by discharging steam through the atmospheric relief valves or the main steam safety valves, as described in Section 10.3.


Circulating water leakage occurring within the condenser is detected by  monitoring the condensate leaving each hotwell (six monitoring points altogether). This information permits determination of which tube bundle has sustained the leakage. Steps may then be taken to isolate and dewater that bundle and its water boxes and, subsequently, repair or plug the leaking tubes.
dome of each shell. Piping is installed for hotwell level control and  
Section 10.4.6 describes the contaminants allowed in the condensate and the  length of time the condenser may operate with degraded conditions without  affecting the condensate/feedwater quality for safe operation. 


During normal operation and shutdown, the main condenser has a negligible inventory of radioactive contaminants. Radioactive 
condensate sampling.  


10.4-3 Rev. 13 WOLF CREEK contaminants may enter through a steam generator tube leak. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated operating concentrations of radioactive contaminants, is included in Chapter 11.0. No hydrogen buildup in the main condenser is anticipated.
10.4.1.2.2 Component Description
The failure of the main condenser and the resulting flooding will not preclude operation of any essential system because the limited safety related components, instruments and cabling associated with the main steam dumps and  turbine trip/reactor trip signals are located well above the expected flood level in the turbine building, and the water cannot reach the equipment located in the auxiliary building. Refer to Section 10.4.5.


10.4.1.3  Safety Evaluation The main condenser serves no safety-related function.
Table 10.4-1 provides the design data for each condenser shell for both the


10.4.1.4  Tests and Inspections  The condenser shells are hydrostatically tested after erection.
closed loop and open loop circulating water systems.  
The condenser waterboxes, tubesheets, and tubes are hydrostatically tested as a unit.
The extent of inservice inspection of the main condenser includes the following:


1. Monitor condensate conductivity, temperature, and dissolved oxygen level. 2. When an expansion joint water seal is in service in times when it is expected that the vacuum seal has been breached, check water level in the condenser/turbine connection expansion joint water seal for seal leak detection.
10.4.1.2.3 System Operation
The frequency of these inspections will depend on past condenser operating experience and the type of problems identified in the previously described inspections.
10.4.1.5  Instrument Applications The main condenser hotwells are equipped with level control devices for automatic control of condensate makeup and rejection. Local and remote indicating devices are provided for monitoring the water level in the condenser shells. High, low, and low-low hotwell water level alarms are provided in the control room.


A sensor is provided to monitor condenser back-pressure. A high back-pressure alarm is activated at approximately 5 inches Hg absolute (Hga), and turbine trip is activated at 7.5 inches Hga. 
During normal operation, exhaust steam from the low-pressure turbines is  


10.4-4 Rev. 29 WOLF CREEK Conductivity and sodium content of the condensate from each condenser shell is monitored to provide an indication of condenser tube leakage.
directed into the main condenser shells. The condenser also receives auxiliary
Turbine exhaust hood temperature is monitored and controlled with water sprays supplied from the condensate pump discharge.
10.4.2  MAIN CONDENSER EVACUATION SYSTEM Main condenser evacuation is performed by the main condenser air removal system (MCARS). The MCARS removes noncondensable gases and air from the main condenser during plant startup, cooldown, and normal operation.


10.4.2.1  Design Bases 10.4.2.1.1  Safety Design Bases The MCARS serves no safety function and has no safety design bases. 10.4.2.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The MCARS is designed to remove air and noncondensable gases from the condenser during plant startup, cooldown, and normal operation. POWER GENERATION DESIGN BASIS TWO - The MCARS establishes and maintains a vacuum in the condenser during startup and normal operation by the use of mechanical vacuum pumps.
system flows, such as feedwater heater vents and drains and feedwater pump turbine exhaust.
10.4.2.2  System Description 10.4.2.2.1  General Description  
 
10.4-2 Rev. 29 WOLF CREEK Hotwell level controls provide automatic makeup or rejection of condensate to maintain a normal level in the condenser hotwells. On low water level in a
 
hotwell, the makeup control valves open and admit condensate to the hotwell from the condensate storage tank. When the hotwell is brought to within normal-operating range, the valves close. On high water level in the hotwell, the condensate reject control valve opens to divert condensate from the
 
condensate pump discharge (downstream of the demineralizers) to the condensate
 
storage tank; rejection is stopped when the hotwell level falls to within normal operating range.
 
Sparger piping is provided for distribution of turbine bypass discharge and
 
other high temperature drains. Orifices are provided internal to the spargers
 
where necessary for pressure reduction prior to distribution within the condenser. Where sparger piping cannot be utilized due to space limitations, baffles are provided to direct the discharge away from the tubes and other
 
condenser components. Pressure reducing orifices are provided in the drains
 
piping outside the condenser, where required.
 
The main condenser, with the assistance of auxiliary steam at low loads, deaerates the condensate so that dissolved oxygen should not exceed 7 ppb over 
 
the entire load range. Both the air inleakage and the noncondensable gases
 
contained in the turbine exhaust are collected in the condenser and removed by
 
the condenser air removal system.
During the cooling period after plant shutdown, the main condenser removes residual heat from the reactor coolant system via the turbine bypass system. 
 
The main condenser receives up to 40 percent of VWO main steam flow through the
 
turbine bypass valves. If the condenser is not available to receive steam via the turbine bypass system, the reactor coolant system can be safely cooled down by discharging steam through the atmospheric relief valves or the main steam
 
safety valves, as described in Section 10.3.
 
Circulating water leakage occurring within the condenser is detected by monitoring the condensate leaving each hotwell (six monitoring points altogether). This information permits determination of which tube bundle has
 
sustained the leakage. Steps may then be taken to isolate and dewater that
 
bundle and its water boxes and, subsequently, repair or plug the leaking tubes. 
 
Section 10.4.6 describes the contaminants allowed in the condensate and the length of time the condenser may operate with degraded conditions without affecting the condensate/feedwater quality for safe operation. 
 
During normal operation and shutdown, the main condenser has a negligible
 
inventory of radioactive contaminants. Radioactive
 
10.4-3 Rev. 13 WOLF CREEK contaminants may enter through a steam generator tube leak. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated
 
operating concentrations of radioactive contaminants, is included in Chapter 11.0. No hydrogen buildup in the main condenser is anticipated.
 
The failure of the main condenser and the resulting flooding will not preclude 
 
operation of any essential system because the limited safety related 
 
components, instruments and cabling associated with the main steam dumps and turbine trip/reactor trip signals are located well above the expected flood level in the turbine building, and the water cannot reach the equipment located
 
in the auxiliary building. Refer to Section 10.4.5.
 
10.4.1.3  Safety Evaluation
 
The main condenser serves no safety-related function.
 
10.4.1.4  Tests and Inspections The condenser shells are hydrostatically tested after erection.
 
The condenser waterboxes, tubesheets, and tubes are hydrostatically tested as a
 
unit.
The extent of inservice inspection of the main condenser includes the following:
: 1. Monitor condensate conductivity, temperature, and dissolved oxygen level.
: 2. When an expansion joint water seal is in service in times when it is expected that the vacuum seal has been breached, check water level in the condenser/turbine connection expansion joint water seal for seal leak detection.
 
The frequency of these inspections will depend on past condenser operating
 
experience and the type of problems identified in the previously described
 
inspections.
 
10.4.1.5  Instrument Applications The main condenser hotwells are equipped with level control devices for
 
automatic control of condensate makeup and rejection. Local and remote
 
indicating devices are provided for monitoring the water level in the condenser shells. High, low, and low-low hotwell water level alarms are provided in the control room.
 
A sensor is provided to monitor condenser back-pressure. A high back-pressure
 
alarm is activated at approximately 5 inches Hg absolute (Hga), and turbine
 
trip is activated at 7.5 inches Hga.
 
10.4-4 Rev. 29 WOLF CREEK Conductivity and sodium content of the condensate from each condenser shell is monitored to provide an indication of condenser tube leakage.
 
Turbine exhaust hood temperature is monitored and controlled with water sprays supplied from the condensate pump discharge.
 
10.4.2  MAIN CONDENSER EVACUATION SYSTEM
 
Main condenser evacuation is performed by the main condenser air removal system (MCARS). The MCARS removes noncondensable gases and air from the main
 
condenser during plant startup, cooldown, and normal operation.
 
10.4.2.1  Design Bases 10.4.2.1.1  Safety Design Bases  
 
The MCARS serves no safety function and has no safety design bases.
10.4.2.1.2  Power Generation Design Bases  
 
POWER GENERATION DESIGN BASIS ONE - The MCARS is designed to remove air and  
 
noncondensable gases from the condenser during plant startup, cooldown, and  
 
normal operation.
POWER GENERATION DESIGN BASIS TWO - The MCARS establishes and maintains a  
 
vacuum in the condenser during startup and normal operation by the use of  
 
mechanical vacuum pumps.  
 
10.4.2.2  System Description 10.4.2.2.1  General Description  


The MCARS, as shown in Figure 10.4-3, consists of three mechanical vacuum pumps which remove air and noncondensable gases from the main condenser during normal operation and provide condenser hogging during startup.  
The MCARS, as shown in Figure 10.4-3, consists of three mechanical vacuum pumps which remove air and noncondensable gases from the main condenser during normal operation and provide condenser hogging during startup.  


The seal water cooler uses service water so that the seal water is kept cooler than the saturation temperature of the condenser at its operating pressure. As described in Section 9.4.4, air inleakage and noncondensable gases that are removed from the condenser and discharged from the pumps are processed through the charcoal adsorption train and monitored for radioactivity prior to discharge to the unit vent.  
The seal water cooler uses service water so that the seal water is kept cooler  
 
than the saturation temperature of the condenser at its operating pressure. As described in Section 9.4.4, air inleakage and noncondensable gases that are removed from the condenser and discharged from the pumps are processed through  
 
the charcoal adsorption train and monitored for radioactivity prior to  
 
discharge to the unit vent.
 
10.4-5 Rev. 13 WOLF CREEK The noncondensable gases and vapor mixture discharged to the atmosphere from the system is not normally radioactive. However, it is possible for the mixture
 
discharged to become contaminated in the event of primary-to-secondary system leakage. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated release from the system, is included in Chapter 11.0.
 
As long as the MCARS is functional, its operation does not affect the reactor coolant system. Should the air removal system fail completely, a gradual
 
reduction in condenser vacuum would result from the buildup of noncondensable
 
gases. This reduction in vacuum would cause a lowering of turbine cycle
 
efficiency which requires an increase in reactor power to maintain the demanded electrical power generation level. The reactor power is limited by the reactor control system, as described in Section 7.7. The reactor protection system, described in Section 7.2, independently guarantees that the reactor is maintained within safe operation limits.
 
If the MCARS remains inoperable, condenser vacuum decreases to the turbine trip setpoint and a turbine trip is initiated. A loss of condenser vacuum incident
 
is discussed in Section 15.2.5.
 
10.4.2.2.2  Component Description MECHANICAL VACUUM PUMPS - The mechanical vacuum pumps are 150 hp motor-driven
 
pumps which operate at 435 rpm.
 
SEAL WATER COOLERS - The seal water coolers are shell and tube heat exchangers.
Mechanical vacuum pump seal water flows through the shell side of the coolers, and service water flows through the tubes.
 
Piping and valves are carbon steel. All piping is designed to ANSI B31.1. The
 
design parameters of the system are provided in Table 10.4-2.
10.4.2.2.3  System Operation
 
During normal plant operation, noncondensable gases are removed from the
 
condenser, and the condenser vacuum is automatically maintained by the condenser vacuum pumps. The vacuum pumps are run as needed to ensure adequate capacity to remove noncondensable gases. Non-running pumps are normally in standby and automatically start on low vacuum.
During startup operation, air is rapidly removed from the condenser by three condenser mechanical vacuum pumps.
 
During normal operation, the condenser vacuum pump suction header can be lined up as an alternate vacuum source for the Demineralized Water Storage and Transfer System (DWSTS) degasifier tank.
 
10.4-6 Rev. 11 WOLF CREEK 10.4.2.3  Safety Evaluation The main condenser evacuation system has no safety-related function.
10.4.2.4  Tests and Inspections Testing and inspection of the system is performed prior to plant operation.
 
Components of the system are continuously monitored during operation to ensure satisfactory operation. Periodic inservice tests and inspections of the
 
evacuation system are performed in conjunction with the scheduled maintenance
 
outages.
10.4.2.5  Instrumentation Applications Local indicating devices such as pressure, temperature, and flow indicators are
 
provided as required for monitoring the system operation. Pressure switches
 
are provided for automatic operation of the standby mechanical vacuum pump during normal operation.  


10.4-5 Rev. 13 WOLF CREEK The noncondensable gases and vapor mixture discharged to the atmosphere from the system is not normally radioactive. However, it is possible for the mixture discharged to become contaminated in the event of primary-to-secondary system leakage. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated release from the system, is included in Chapter 11.0.
Volumetric flow indication is provided locally to monitor the quantity of  
As long as the MCARS is functional, its operation does not affect the reactor coolant system. Should the air removal system fail completely, a gradual reduction in condenser vacuum would result from the buildup of noncondensable gases. This reduction in vacuum would cause a lowering of turbine cycle efficiency which requires an increase in reactor power to maintain the demanded electrical power generation level. The reactor power is limited by the reactor control system, as described in Section 7.7. The reactor protection system, described in Section 7.2, independently guarantees that the reactor is maintained within safe operation limits.
If the MCARS remains inoperable, condenser vacuum decreases to the turbine trip setpoint and a turbine trip is initiated. A loss of condenser vacuum incident is discussed in Section 15.2.5.


10.4.2.2.2  Component Description  MECHANICAL VACUUM PUMPS - The mechanical vacuum pumps are 150 hp motor-driven pumps which operate at 435 rpm.  
exhausted noncondensable gases.  


SEAL WATER COOLERS - The seal water coolers are shell and tube heat exchangers. Mechanical vacuum pump seal water flows through the shell side of the coolers, and service water flows through the tubes.
A radiation detector is provided in the turbine building HVAC system to monitor the discharge of the condenser mechanical vacuum pumps. The radiation detector
Piping and valves are carbon steel. All piping is designed to ANSI B31.1. The design parameters of the system are provided in Table 10.4-2. 10.4.2.2.3  System Operation


During normal plant operation, noncondensable gases are removed from the condenser, and the condenser vacuum is automatically maintained by the condenser vacuum pumps. The vacuum pumps are run as needed to ensure adequate    capacity to remove noncondensable gases. Non-running pumps are normally in   standby and automatically start on low vacuum. During startup operation, air is rapidly removed from the condenser by three condenser mechanical vacuum pumps.
is indicated and alarmed in the control room.  
During normal operation, the condenser vacuum pump suction header can be lined  up as an alternate vacuum source for the Demineralized Water Storage and  Transfer System (DWSTS) degasifier tank.  


10.4-6 Rev. 11 WOLF CREEK 10.4.2.3  Safety Evaluation  The main condenser evacuation system has no safety-related function. 10.4.2.4  Tests and Inspections  Testing and inspection of the system is performed prior to plant operation.
10.4.3  TURBINE GLAND SEALING SYSTEM The turbine gland sealing system (TGSS) prevents the escape of steam from the  
Components of the system are continuously monitored during operation to ensure satisfactory operation. Periodic inservice tests and inspections of the evacuation system are performed in conjunction with the scheduled maintenance outages.
10.4.2.5  Instrumentation Applications  Local indicating devices such as pressure, temperature, and flow indicators are provided as required for monitoring the system operation. Pressure switches are provided for automatic operation of the standby mechanical vacuum pump during normal operation.
Volumetric flow indication is provided locally to monitor the quantity of exhausted noncondensable gases.
A radiation detector is provided in the turbine building HVAC system to monitor the discharge of the condenser mechanical vacuum pumps. The radiation detector is indicated and alarmed in the control room.


10.4.3  TURBINE GLAND SEALING SYSTEM  The turbine gland sealing system (TGSS) prevents the escape of steam from the turbine shaft/casing penetrations and valve stems and prevents air inleakage to subatmospheric turbine glands.
turbine shaft/casing penetrations and valve stems and prevents air inleakage to  
10.4.3.1  Design Bases  10.4.3.1.1  Safety Design Basis


The TGSS serves no safety function and has no safety design basis. 10.4.3.1.2  Power Generation Design Bases
subatmospheric turbine glands.  


POWER GENERATION DESIGN BASIS ONE - The TGSS is designed to prevent atmospheric air leakage into the turbine casings and to minimize steam leakage out of the casings of the turbine-generator and steam generator feedwater pump turbines.   
10.4.3.1  Design Bases 10.4.3.1.1 Safety Design Basis


10.4-7 Rev. 0 WOLF CREEK POWER GENERATION DESIGN BASIS TWO - The TGSS returns the condensed steam to the condenser and exhausts the noncondensable gases to the atmosphere.
The TGSS serves no safety function and has no safety design basis.
POWER GENERATION DESIGN BASIS THREE - The TGSS has a capacity to handle steam and air flows resulting from twice the normal packing clearances.
10.4.3.1.2  Power Generation Design Bases
10.4.3.2  System Description  10.4.3.2.1 General Description  The TGSS is shown in Figure 10.4-4. It consists of steam seal inlet and exhaust headers, feed and unloading valves, steam packing exhauster, blowers, and associated piping and valves. 10.4.3.2.2  System Operation


The annular space through which the turbine shaft penetrates the casing is sealed by steam supplied to shaft packings. Where the packing seals against positive pressure, the sealing steam connection acts as a leakoff. Where the packing seals against vacuum, the sealing steam either is drawn into the casing or leaks outward to a vent annulus that is maintained at a slight vacuum. The vent annulus also receives air leakage from the outside. The air-steam mixture is drawn to the steam packing exhauster. Sealing steam is distributed to the turbine shaft seals through the steam-seal header. Steam flow to the header is controlled by the steam-seal feed valve which responds to maintain steam-seal header pressure. In case of low steam-seal header pressure, a pressure regulator signal opens the feed valves to admit steam from the main steam piping upstream of the turbine stop valves, from the auxiliary steam headers, or from ninth stage turbine extraction. In case of high pressure, the steam packing unloading valve automatically opens to bypass excess steam directly to the main condenser.
POWER GENERATION DESIGN BASIS ONE - The TGSS is designed to prevent atmospheric
During the startup phase of turbine-generator operation or at low turbine loads, steam is supplied to the turbine gland sealing system from the main steam piping or auxiliary steam header. During low-load operation, turbine-generator sealing steam is supplied from the main steam system through the steam-seal feed valve to maintain the necessary steam flow to the steam-seal header. As the turbine-generator load is increased, steam leakage from the control valve packings and turbine high-pressure packings increases, and enters the steam-seal header. When this leakage is sufficient to maintain steam-seal header pressure, sealing steam  
 
air leakage into the turbine casings and to minimize steam leakage out of the casings of the turbine-generator and steam generator feedwater pump turbines.
 
10.4-7 Rev. 0 WOLF CREEK POWER GENERATION DESIGN BASIS TWO - The TGSS returns the condensed steam to the condenser and exhausts the noncondensable gases to the atmosphere.
 
POWER GENERATION DESIGN BASIS THREE - The TGSS has a capacity to handle steam and air flows resulting from twice the normal packing clearances.
 
10.4.3.2  System Description 10.4.3.2.1  General Description The TGSS is shown in Figure 10.4-4. It consists of steam seal inlet and exhaust headers, feed and unloading valves, steam packing exhauster, blowers, and associated piping and valves.
10.4.3.2.2  System Operation
 
The annular space through which the turbine shaft penetrates the casing is  
 
sealed by steam supplied to shaft packings. Where the packing seals against positive pressure, the sealing steam connection acts as a leakoff. Where the packing seals against vacuum, the sealing steam either is drawn into the casing  
 
or leaks outward to a vent annulus that is maintained at a slight vacuum. The  
 
vent annulus also receives air leakage from the outside. The air-steam mixture is drawn to the steam packing exhauster.
Sealing steam is distributed to the turbine shaft seals through the steam-seal  
 
header. Steam flow to the header is controlled by the steam-seal feed valve  
 
which responds to maintain steam-seal header pressure. In case of low steam-
 
seal header pressure, a pressure regulator signal opens the feed valves to admit steam from the main steam piping upstream of the turbine stop valves, from the auxiliary steam headers, or from ninth stage turbine extraction. In  
 
case of high pressure, the steam packing unloading valve automatically opens to  
 
bypass excess steam directly to the main condenser.  
 
During the startup phase of turbine-generator operation or at low turbine loads, steam is supplied to the turbine gland sealing system from the main  
 
steam piping or auxiliary steam header. During low-load operation, turbine-generator sealing steam is supplied from the main steam system through the  
 
steam-seal feed valve to maintain the necessary steam flow to the steam-seal header. As the turbine-generator load is increased, steam leakage from the control valve packings and turbine high-pressure packings increases, and enters  
 
the steam-seal header. When this leakage is sufficient to maintain steam-seal  
 
header pressure, sealing steam  
 
10.4-8 Rev. 0 WOLF CREEK to all turbine seals, including the low-pressure turbine casings and the main feedwater pump turbine, is supplied entirely from these high-pressure packings. 


10.4-8 Rev. 0 WOLF CREEK to all turbine seals, including the low-pressure turbine casings and the main feedwater pump turbine, is supplied entirely from these high-pressure packings.
At full load, more steam leaks from the high-pressure packings than is required by vacuum packings, and excess steam is discharged directly to the main condenser. Steam leak-off from the turbine stop valves feeds into the high-pressure turbine exhaust.  
At full load, more steam leaks from the high-pressure packings than is required by vacuum packings, and excess steam is discharged directly to the main condenser. Steam leak-off from the turbine stop valves feeds into the high-pressure turbine exhaust.  


The outer ends of all glands are provided with collection piping which routes the mixture of air and excess seal steam to the steam packing exhauster. The steam packing exhauster is a shell and tube heat exchanger; the steam-air mixture passes into the shell side, and service water flows through the tube side. The steam packing exhauster is maintained at a slight vacuum by a motor-operated blower, which discharges to the atmosphere. There are two blowers mounted in parallel which provide 100-percent redundancy. Condensate from the steam-air mixture drains to the main condensers, while noncondensables are exhausted to the atmosphere.
The outer ends of all glands are provided with collection piping which routes the mixture of air and excess seal steam to the steam packing exhauster. The steam packing exhauster is a shell and tube heat exchanger; the steam-air  
 
mixture passes into the shell side, and service water flows through the tube  


The mixture of noncondensable gases discharged to the atmosphere by the steam packing exhauster blower is not normally radioactive; however, in the event of significant primary-to-secondary system leakage due to a steam generator tube leak, it is possible for the mixture discharged to be radioactively contaminated. Primary-to-secondary system leakage is detected by the radiation monitors in either the main steam sample system or the condenser air removal system. A full discussion of the radiological aspects of primary-to-secondary system leakage is included in Chapter 11.0.
side. The steam packing exhauster is maintained at a slight vacuum by a motor-


In the absence of primary-to-secondary leakage, failure of the turbine gland seal system will result in no leakage of radioactivity to the atmosphere. A failure of this system would, however, result in a loss of condenser vacuum.
operated blower, which discharges to the atmosphere. There are two blowers mounted in parallel which provide 100-percent redundancy. Condensate from the steam-air mixture drains to the main condensers, while noncondensables are
10.4.3.3  Safety Evaluation  The TGSS has no safety-related function. 10.4.3.4  Tests and Inspections  The system was tested, in accordance with written procedures, during the initial testing and operation program. Since the TGSS is in constant use during normal plant operation, the satisfactory operation of the system components is evident.


10.4-9 Rev. 13 WOLF CREEK 10.4.3.5  Instrumentation Applications  A pressure controller is provided to maintain steam-seal header pressure by providing signals to the steam-seal feed valve. Local and remote indicators, as well as alarm devices, are provided for monitoring the operation of the system.
exhausted to the atmosphere.  
10.4.4  TURBINE BYPASS SYSTEM The turbine bypass system (TBS) has the capability to bypass main steam from the steam generators to the main condenser in a controlled manner to minimize transient effects on the reactor coolant system of startup, hot shutdown and cooldown, step load reductions in generator load, and cycling the main turbine stop and control valves. The TBS is also called the steam dump system.
10.4.4.1  Design Bases  10.4.4.1.1  Safety Design Bases The TBS serves no safety function and has no safety design basis.
10.4.4.1.2  Power Generation Design Bases  POWER GENERATION DESIGN BASIS ONE - The TBS has the capacity to bypass 40 percent of the VWO main steam flow to the main condenser.  


POWER GENERATION DESIGN BASIS TWO - The TBS is designed to bypass steam to the main condenser during plant startup and to permit a normal manual cooldown of the reactor coolant system from a hot shutdown condition to a point consistent with the initiation of residual heat removal system operation.
The mixture of noncondensable gases discharged to the atmosphere by the steam packing exhauster blower is not normally radioactive; however, in the event of significant primary-to-secondary system leakage due to a steam generator tube
POWER GENERATION DESIGN BASIS THREE - The TBS will permit a 50-percent electrical step-load reduction without reactor trip. The system will also allow a turbine and reactor trip from full power without lifting the main steam safety valves. 10.4.4.2  System Description 10.4.4.2.1  General Description The TBS is shown on Figure 10.3-1, Main Steam System. The system consists of a manifold connected to the main steam lines upstream   


10.4-10 Rev. 18 WOLF CREEK of the turbine stop valves and lines from the manifold with regulating valves to each condenser shell. The system is designed to bypass 40 percent of the VWO main steam flow directly to the condenser. The capacity of the system, combined with the capacity of the RCS to accept a 10-percent step-load change, provides the capability to shed 50 percent of the turbine-generator rated load without reactor trip and without the operation of relief and safety valves. A load rejection in excess of 50 percent is expected to result in reactor trip and operation of the main steam atmospheric relief valves. The operation of the main steam, atmospheric, relief valves and spring-loaded safety valves prevents overpressurization of the main steam system.
leak, it is possible for the mixture discharged to be radioactively  
There are 12 turbine bypass valves. Seven valves discharge into the low pressure condenser, four valves discharge into the intermediate condenser, and a single valve discharges into the high pressure condenser. The system is arranged in this manner to allow for the differences in the heat sink capacities of the three condenser shells. The heat sink capacity of any one condenser shell is limited by the administrative limit of 5.5 inches Hga (for 100% power operation) condenser pressure imposed on turbine operation by the turbine-generator manufacturer. The low pressure condenser is the largest heat sink, since it normally operates at the lowest pressure.
The steam bypassed to the main condenser is not normally radioactive. In the event of primary-to-secondary leakage, it is possible for the bypassed steam to become radioactively contaminated. A full discussion of the radiological aspects of primary-to-secondary leakage is contained in Chapter 11.0.
10.4.4.2.2  Component Description The TBS contains 12 air-actuated carbon steel, 8 inch, 1,500 pound globe valves. The valves are pilot-operated, spring-opposed, and fail closed upon loss of air or loss of power to the control system. Sparger piping distributes the steam within the condenser. Isolation valves permit maintenance of the bypass valve while the plant is in operation.


10.4.4.2.3  System Operation The TBS, during normal operating transients for which the plant is designed, is automatically regulated by the reactor coolant temperature control system to maintain the programmed coolant temperature. The programmed coolant temperature is derived from the high pressure turbine first stage pressure, which is a load   
contaminated. Primary-to-secondary system leakage is detected by the radiation


10.4-11 Rev. 28 WOLF CREEK reference signal. The difference between programmed reactor coolant average temperature and measured reactor coolant average temperature is used to activate the steam dump system under automatic control. The system operates in two fundamental modes. In one mode, two groups of six valves each trip open sequentially in approximately 3 seconds. This operational mode is activated during a large reactor-to-turbine power mismatch. In the second mode, four groups of three valves each modulate open sequentially in approximately 10 seconds. A logic diagram is shown in Figure 7.2-1 (Sheet 10). When the plant is at no load (and there is no turbine load reference), while cycling the main turbine stop and control valves, and during plant cooldown the system is operated in a pressure control mode. The measured main steam system pressure is compared against the pressure set by the operator in the control room. The valves to any one condenser shell are prevented from opening when the pressure in that shell reaches 5.0 in Hga. The turbine bypass control system can malfunction in either the open or closed mode. The effects of both these potential failure modes on the NSSS and turbine system are addressed in Chapter 15.0. If the bypass valves fail open, additional heat load is placed on the condenser. If this load is great enough, the turbine is tripped on high-high condenser pressure. Ultimate overpressure protection for the condenser is provided by rupture discs. If the bypass valves fail closed, the atmospheric relief valves permit controlled cooldown of the reactor.
monitors in either the main steam sample system or the condenser air removal system. A full discussion of the radiological aspects of primary-to-secondary system leakage is included in Chapter 11.0.  
10.4.4.3  Safety Evaluation  The TBS serves no safety function and has no safety design basis. There is no safety-related equipment in the vicinity of the TBS. All high energy lines of the TBS are located in the turbine building.
10.4.4.4  Inspection and Testing Requirements  Before the system is placed in service, all turbine bypass valves are tested for operability. The steam lines are hydrostatically tested to confirm leaktightness. The bypass valves may be tested while the unit is in operation. System piping and valves are accessible for inspection.
The turbine bypass system includes the capability to inservice test the turbine bypass valves by closing the upstream manual isolation valves and cycling the turbine bypass valves from the control room. Turbine bypass valves are cycled during normal plant operation at least annually.  


10.4-12 Rev. 11 WOLF CREEK 10.4.4.5  Instrumentation Applications The turbine bypass control system is described in Section 7.7. Hand switches in the main control room are provided for selection of the system operating mode. Pressure controllers and valve position lights are also located in the main control room.  
In the absence of primary-to-secondary leakage, failure of the turbine gland
 
seal system will result in no leakage of radioactivity to the atmosphere. A failure of this system would, however, result in a loss of condenser vacuum.
 
10.4.3.3  Safety Evaluation The TGSS has no safety-related function.
10.4.3.4  Tests and Inspections The system was tested, in accordance with written procedures, during the
 
initial testing and operation program. Since the TGSS is in constant use during normal plant operation, the satisfactory operation of the system components is evident.
 
10.4-9 Rev. 13 WOLF CREEK 10.4.3.5  Instrumentation Applications A pressure controller is provided to maintain steam-seal header pressure by providing signals to the steam-seal feed valve.
Local and remote indicators, as well as alarm devices, are provided for
 
monitoring the operation of the system.
 
10.4.4  TURBINE BYPASS SYSTEM
 
The turbine bypass system (TBS) has the capability to bypass main steam from
 
the steam generators to the main condenser in a controlled manner to minimize
 
transient effects on the reactor coolant system of startup, hot shutdown and cooldown, step load reductions in generator load, and cycling the main turbine stop and control valves. The TBS is also called the steam dump system.
 
10.4.4.1  Design Bases 10.4.4.1.1  Safety Design Bases
 
The TBS serves no safety function and has no safety design basis.
 
10.4.4.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The TBS has the capacity to bypass 40
 
percent of the VWO main steam flow to the main condenser.
 
POWER GENERATION DESIGN BASIS TWO - The TBS is designed to bypass steam to the main condenser during plant startup and to permit a normal manual cooldown of the reactor coolant system from a hot shutdown condition to a point consistent
 
with the initiation of residual heat removal system operation.
 
POWER GENERATION DESIGN BASIS THREE - The TBS will permit a 50-percent electrical step-load reduction without reactor trip. The system will also allow a turbine and reactor trip from full power without lifting the main steam
 
safety valves.
10.4.4.2  System Description
 
10.4.4.2.1  General Description
 
The TBS is shown on Figure 10.3-1, Main Steam System. The system consists of a manifold connected to the main steam lines upstream 
 
10.4-10 Rev. 18 WOLF CREEK of the turbine stop valves and lines from the manifold with regulating valves to each condenser shell. The system is designed to bypass 40 percent of the VWO
 
main steam flow directly to the condenser.
The capacity of the system, combined with the capacity of the RCS to accept a
 
10-percent step-load change, provides the capability to shed 50 percent of the
 
turbine-generator rated load without reactor trip and without the operation of
 
relief and safety valves. A load rejection in excess of 50 percent is expected to result in reactor trip and operation of the main steam atmospheric relief valves. The operation of the main steam, atmospheric, relief valves and spring-loaded safety valves prevents overpressurization of the main steam
 
system.
There are 12 turbine bypass valves. Seven valves discharge into the low pressure condenser, four valves discharge into the intermediate condenser, and
 
a single valve discharges into the high pressure condenser. The system is
 
arranged in this manner to allow for the differences in the heat sink
 
capacities of the three condenser shells. The heat sink capacity of any one condenser shell is limited by the administrative limit of 5.5 inches Hga (for 100% power operation) condenser pressure imposed on turbine operation by the turbine-generator manufacturer. The low pressure condenser is the largest heat sink, since it normally operates at the lowest pressure.
 
The steam bypassed to the main condenser is not normally radioactive. In the event of primary-to-secondary leakage, it is possible for the bypassed steam to
 
become radioactively contaminated. A full discussion of the radiological
 
aspects of primary-to-secondary leakage is contained in Chapter 11.0.
 
10.4.4.2.2  Component Description
 
The TBS contains 12 air-actuated carbon steel, 8 inch, 1,500 pound globe
 
valves. The valves are pilot-operated, spring-opposed, and fail closed upon
 
loss of air or loss of power to the control system. Sparger piping distributes the steam within the condenser. Isolation valves permit maintenance of the bypass valve while the plant is in operation.
 
10.4.4.2.3  System Operation
 
The TBS, during normal operating transients for which the plant is designed, is automatically regulated by the reactor coolant temperature control system to
 
maintain the programmed coolant temperature. The programmed coolant
 
temperature is derived from the high pressure turbine first stage pressure, which is a load 
 
10.4-11 Rev. 28 WOLF CREEK reference signal. The difference between programmed reactor coolant average temperature and measured reactor coolant average temperature is used to
 
activate the steam dump system under automatic control. The system operates in two fundamental modes. In one mode, two groups of six valves each trip open sequentially in approximately 3 seconds. This operational mode is activated during a large reactor-to-turbine power mismatch. In the second mode, four
 
groups of three valves each modulate open sequentially in approximately 10
 
seconds. A logic diagram is shown in Figure 7.2-1 (Sheet 10).
When the plant is at no load (and there is no turbine load reference), while
 
cycling the main turbine stop and control valves, and during plant cooldown the
 
system is operated in a pressure control mode. The measured main steam system
 
pressure is compared against the pressure set by the operator in the control room. The valves to any one condenser shell are prevented from opening when the pressure in that shell reaches 5.0 in Hga.
The turbine bypass control system can malfunction in either the open or closed
 
mode. The effects of both these potential failure modes on the NSSS and turbine system are addressed in Chapter 15.0. If the bypass valves fail open, additional heat load is placed on the condenser. If this load is great enough, the turbine is tripped on high-high condenser pressure. Ultimate overpressure
 
protection for the condenser is provided by rupture discs. If the bypass
 
valves fail closed, the atmospheric relief valves permit controlled cooldown of the reactor.
 
10.4.4.3  Safety Evaluation The TBS serves no safety function and has no safety design basis. There is no safety-related equipment in the vicinity of the TBS. All high energy lines of the TBS are located in the turbine building.
 
10.4.4.4  Inspection and Testing Requirements Before the system is placed in service, all turbine bypass valves are tested for operability. The steam lines are hydrostatically tested to confirm leaktightness. The bypass valves may be tested while the unit is in operation.
System piping and valves are accessible for inspection.
 
The turbine bypass system includes the capability to inservice test the turbine bypass valves by closing the upstream manual isolation valves and cycling the
 
turbine bypass valves from the control room. Turbine bypass valves are cycled
 
during normal plant operation at least annually.
 
10.4-12 Rev. 11 WOLF CREEK 10.4.4.5  Instrumentation Applications The turbine bypass control system is described in Section 7.7. Hand switches in the main control room are provided for selection of the system operating mode.
Pressure controllers and valve position lights are also located in the main control room.
 
10.4.5  CIRCULATING WATER SYSTEM The circulating water system (CWS) within the standard power block consists of
 
the circulating water piping, on-line condenser tube cleaning system, and water box venting subsystem.
The circulating water for cycle heat rejection from the main condenser is provided by an open circulating water system using a man-made cooling lake.
 
10.4.5.1  Design Bases 10.4.5.1.1  Safety Design Bases
 
The CWS serves no safety-related function.
 
10.4.5.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The CWS supplies cooling water at a
 
sufficient flow rate to condense the steam in the condenser, as required by the
 
turbine cycle heat balance.
 
POWER GENERATION DESIGN BASIS TWO - Two out of three operating circulating water pumps are automatically secured in the event of gross leakage into the condenser pit to prevent flooding of the turbine building.  


10.4.5  CIRCULATING WATER SYSTEM  The circulating water system (CWS) within the standard power block consists of the circulating water piping, on-line condenser tube cleaning system, and water box venting subsystem. The circulating water for cycle heat rejection from the main condenser is provided by an open circulating water system using a man-made cooling lake.
10.4.5.1  Design Bases  10.4.5.1.1  Safety Design Bases The CWS serves no safety-related function.
10.4.5.1.2  Power Generation Design Bases  POWER GENERATION DESIGN BASIS ONE - The CWS supplies cooling water at a sufficient flow rate to condense the steam in the condenser, as required by the turbine cycle heat balance.
POWER GENERATION DESIGN BASIS TWO - Two out of three operating circulating water pumps are automatically secured in the event of gross leakage into the condenser pit to prevent flooding of the turbine building.
POWER GENERATION DESIGN BASIS THREE - The cooling lake removes the design heat load from the circulating water during all design weather conditions.  
POWER GENERATION DESIGN BASIS THREE - The cooling lake removes the design heat load from the circulating water during all design weather conditions.  


10.4-13 Rev. 13 WOLF CREEK 10.4.5.2  System Description 10.4.5.2.1  General Description The CWS consists of the main condenser, circulating water screenhouse, traveling screens, circulating water pumps, water box venting pumps, water box venting tanks, piping, valves, seal tanks, and instrumentation, as shown in Sheets 1 through 4 of Figure 10.4-1. The physical arrangement of the circulating water screenhouse is shown in Sheets 4 and 5 of Figure 10.4-1. The major components of the CWS are shown in Table 10.4-3. The CWS provides cooling water for the removal of heat from the main condensers and rejects heat to a heat sink. The water box venting subsystem helps to fill the condenser water boxes during startup and removes accumulated air and other gases from the water boxes during normal operation.  
10.4-13 Rev. 13 WOLF CREEK 10.4.5.2  System Description 10.4.5.2.1  General Description The CWS consists of the main condenser, circulating water screenhouse, traveling screens, circulating water pumps, water box venting pumps, water box venting tanks, piping, valves, seal tanks, and instrumentation, as shown in Sheets 1 through 4 of Figure 10.4-1. The physical arrangement of the circulating water screenhouse is shown in Sheets 4 and 5 of Figure 10.4-1. The major components of the CWS are shown in Table 10.4-3.
The CWS provides cooling water for the removal of heat from the main condensers  
 
and rejects heat to a heat sink. The water box venting subsystem helps to fill the condenser water boxes during startup and removes accumulated air and other gases from the water boxes during normal operation.
 
10.4.5.2.2  Component Description
 
Codes and standards applicable to the CWS are listed in Table 3.2-1. The system is designed and constructed in accordance with quality group D
 
specifications. Table 10.4-3 provides the design parameters for major
 
components in the circulating water system.
Three one-third capacity motor-driven, vertical, wet-pit circulating water pumps pump the circulating water from the cooling lake to the main condenser. 
 
They are designed to operate through the expected range of cooling lake levels. 
 
The heated water discharged from the condenser is returned to the cooling lake
 
through a CWS discharge structure. The main circulating water pipes from the circulating water screenhouse to the power block and from the power block to the discharge structure have an inside diameter of 144 inches.
Expected circulating water inlet temperature range is 32 to 95 degrees F. The temperature rise across the condenser is about 32.5 degrees F at full power, three circulating water pump operation.
Freeze protection to prevent ice blockage at the circulating water screenhouse is accomplished by a warming line that routes a portion of the circulating water condenser discharge to the inlet of the screenhouse pump bays.  


10.4.5.2.2  Component Description Codes and standards applicable to the CWS are listed in Table 3.2-1. The system is designed and constructed in accordance with quality group D specifications. Table 10.4-3 provides the design parameters for major components in the circulating water system. Three one-third capacity motor-driven, vertical, wet-pit circulating water pumps pump the circulating water from the cooling lake to the main condenser.
They are designed to operate through the expected range of cooling lake levels.
The heated water discharged from the condenser is returned to the cooling lake through a CWS discharge structure. The main circulating water pipes from the circulating water screenhouse to the power block and from the power block to the discharge structure have an inside diameter of 144 inches. Expected circulating water inlet temperature range is 32 to 95 degrees F. The temperature rise across the condenser is about 32.5 degrees F at full power, three circulating water pump operation. Freeze protection to prevent ice blockage at the circulating water screenhouse is accomplished by a warming line that routes a portion of the circulating water condenser discharge to the inlet of the screenhouse pump bays.
Provisions for intermittent biocide addition to reduce the buildup of slime and biological growth in the CWS are provided.  
Provisions for intermittent biocide addition to reduce the buildup of slime and biological growth in the CWS are provided.  


Anti-scale chemical feed equipment is provided to inject scale inhibitor/dispersant into the CWS to inhibit mineral scale and disperse suspended solids.    
Anti-scale chemical feed equipment is provided to inject scale inhibitor/dispersant into the CWS to inhibit mineral scale and disperse suspended solids.  
 
10.4-14 Rev. 13 WOLF CREEK Each circulating water pump is equipped with a discharge butterfly valve that permits a pump to be isolated while operating the system with the remaining
 
pumps. The condenser has a permanent tube cleaning system installed to improve plant efficiency. Sponge balls are circulated from the condenser outlet stand pipes to the condenser inlet stand pipes by a ball pump. A strainer screen located in the outlet stand pipes is used to catch the sponge balls and allow the ball pumps to circulate them back through the condenser tubes.
The CWS by design prevents any release of radioactive material from the steam
 
system into the circulating water. The circulating water passing through the
 
condenser is maintained at a higher pressure than the shell or condensing side.
Therefore, any leakage (such as from a condenser tube) is from the circulating water into the shell side of the condenser.


10.4-14 Rev. 13 WOLF CREEK Each circulating water pump is equipped with a discharge butterfly valve that permits a pump to be isolated while operating the system with the remaining pumps. The condenser has a permanent tube cleaning system installed to improve plant efficiency. Sponge balls are circulated from the condenser outlet stand pipes to the condenser inlet stand pipes by a ball pump. A strainer screen located in the outlet stand pipes is used to catch the sponge balls and allow the ball pumps to circulate them back through the condenser tubes. The CWS by design prevents any release of radioactive material from the steam system into the circulating water. The circulating water passing through the condenser is maintained at a higher pressure than the shell or condensing side. Therefore, any leakage (such as from a condenser tube) is from the circulating water into the shell side of the condenser.  
10.4.5.2.3  System Operation


10.4.5.2.3  System Operation The CWS operates continuously during power generation, including startup and shutdown. The isolation valves in the standard power block are controlled by locally mounted hand switches. There are motor operated butterfly valves on the discharge of each of the circulating water pumps that are controlled by local and main control board handswitches and the pump starting and stopping sequence. In addition, level switches are included in the condenser pit to stop 2 of 3 circulating water pumps and close their pump discharge valves to 25% open upon a high pit water level indication and thus reduce the water flow rate to the pit. In any case, one circulating water pump will remain in operation and must be manually secured. The level switch is set to stop all but one running circulating water pump at a water level of 5 feet above the bottom of the condenser pit. High water level in the sumps in the condenser pit is alarmed to the control room. The water level trip is set high to prevent inadvertent trips from unrelated failures, such as a sump overflow.
The CWS operates continuously during power generation, including startup and shutdown. The isolation valves in the standard power block are controlled by  
The CWS is filled by starting the service water system. The service water can fill the circulating water only to the tops of the circulating water discharge weirs (approximate El. 2000). The water box venting pumps are manually started to fill the remaining portion of the CWS. During normal operation, the venting pumps operate automatically to remove air and other noncondensable gases.


Approximately one-sixth of the tubes of each of the three condensers can be isolated by closing associated inlet and outlet water box isolation valves. Draining of any condenser water box that is selected is initiated by closing the condenser isolation valves and opening the drain connection and a vent valve on the water box. When the suction standpipe of the condenser drain pump is filled, the pump is manually started. A low level switch is provided in the standpipe, on the suction side of the drain pump. This switch automatically stops the pump in the event of low water level in the standpipe to protect the pump from cavitation.  
locally mounted hand switches. There are motor operated butterfly valves on the discharge of each of the circulating water pumps that are controlled by local and main control board handswitches and the pump starting and stopping sequence.
In addition, level switches are included in the condenser pit to stop 2 of 3 circulating water pumps and close their pump discharge valves to 25% open upon a high pit water level indication and thus reduce the water flow rate to the pit. In any case, one circulating water pump will remain in operation and must be manually secured. The level switch is set to stop all but one running circulating water pump at a water level of 5 feet above the bottom of the condenser pit. High water level in the sumps in the condenser pit is alarmed to the control room. The water level trip is set high to prevent inadvertent trips from unrelated failures, such as a sump overflow.  


10.4.5.3  Safety Evaluation  The CWS is not a safety-related system; however, a flooding analysis of the turbine building was performed on the CWS which
The CWS is filled by starting the service water system. The service water can


10.4-15 Rev. 13 WOLF CREEK postulated a complete rupture of a single expansion joint. It was assumed that the flow into the condenser pit consists of the water which can drain from both the upstream and downstream side of the break. For conservatism, it was assumed that the condenser circulating water isolation valves do not fully close, sump volumes in the condenser pit were neglected, and the sump pumps were not operable. A complete description of the CWS flooding analysis is provided in Appendix 3B. 10.4.5.4  Tests and Inspections  Preoperational testing is described in Chapter 14.0. The performance and structural and leak tight integrity of all system components are demonstrated by continuous operation. All active components of the system (except the main condenser and piping) are accessible for inspection during station operation.
fill the circulating water only to the tops of the circulating water discharge


Performance, hydrostatic, and leakage tests were conducted on the CWS butterfly valves in accordance with applicable codes as described in Chapter 14.0.
weirs (approximate El. 2000). The water box venting pumps are manually started to fill the remaining portion of the CWS. During normal operation, the venting pumps operate automatically to remove air and other noncondensable gases.  
10.4.5.5  Instrumentation Applications Temperature monitors are provided at the inlet and outlet water boxes of each condenser shell section. Indication is provided in the control room to identify open and closed positions of motor-operated circulating water pump discharge butterfly valves. 10.4.6  CONDENSATE CLEANUP SYSTEM  The condensate cleanup function is performed by the condensate demineralizer system (CDS). The CDS is designed to maintain the required purity of feedwater for the steam generators by filtration to remove corrosion products and by ion exchange to remove condenser leakage impurities. The secondary side water chemistry requirements are given in Section 10.3.5.  


10.4-16 Rev. 13 WOLF CREEK 10.4.6.1  Design Bases  10.4.6.1.1  Safety Design Bases  The CDS serves no safety function and has no safety design bases.
Approximately one-sixth of the tubes of each of the three condensers can be
10.4.6.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The CDS removes dissolved and suspended solids from the condensate prior to startup.


POWER GENERATION DESIGN BASIS TWO - The CDS removes impurities entering the secondary cycle from condenser leaks that would otherwise deposit or increase corrosion rates in the secondary cycle.
isolated by closing associated inlet and outlet water box isolation valves.
POWER GENERATION DESIGN BASIS THREE - The CDS removes corrosion products from the condensate and any drains returned to the condenser hotwell so as to limit any accumulation in the secondary cycle. POWER GENERATION DESIGN BASIS FOUR - The CDS limits the entry of dissolved solids into the feedwater system in the event of large condenser leaks, such as a tube break, to permit a reasonable amount of time for plant shutdown.
Draining of any condenser water box that is selected is initiated by closing
10.4.6.2  System Description 10.4.6.2.1  General Description  
 
the condenser isolation valves and opening the drain connection and a vent
 
valve on the water box. When the suction standpipe of the condenser drain pump
 
is filled, the pump is manually started. A low level switch is provided in the
 
standpipe, on the suction side of the drain pump. This switch automatically stops the pump in the event of low water level in the standpipe to protect the pump from cavitation.
 
10.4.5.3  Safety Evaluation The CWS is not a safety-related system; however, a flooding analysis of the turbine building was performed on the CWS which
 
10.4-15 Rev. 13 WOLF CREEK postulated a complete rupture of a single expansion joint. It was assumed that the flow into the condenser pit consists of the water which can drain from both
 
the upstream and downstream side of the break. For conservatism, it was assumed that the condenser circulating water isolation valves do not fully close, sump volumes in the condenser pit were neglected, and the sump pumps were not operable. A complete description of the CWS flooding analysis is provided in Appendix 3B.
10.4.5.4  Tests and Inspections Preoperational testing is described in Chapter 14.0. The performance and
 
structural and leak tight integrity of all system components are demonstrated
 
by continuous operation.
All active components of the system (except the main condenser and piping) are
 
accessible for inspection during station operation.
 
Performance, hydrostatic, and leakage tests were conducted on the CWS butterfly valves in accordance with applicable codes as described in Chapter 14.0.
 
10.4.5.5  Instrumentation Applications
 
Temperature monitors are provided at the inlet and outlet water boxes of each condenser shell section.
Indication is provided in the control room to identify open and closed
 
positions of motor-operated circulating water pump discharge butterfly valves.
10.4.6  CONDENSATE CLEANUP SYSTEM The condensate cleanup function is performed by the condensate demineralizer
 
system (CDS). The CDS is designed to maintain the required purity of feedwater for the steam generators by filtration to remove corrosion products and by ion exchange to remove condenser leakage impurities. The secondary side water chemistry requirements are given in Section 10.3.5.
 
10.4-16 Rev. 13 WOLF CREEK 10.4.6.1  Design Bases 10.4.6.1.1  Safety Design Bases The CDS serves no safety function and has no safety design bases.
 
10.4.6.1.2  Power Generation Design Bases
 
POWER GENERATION DESIGN BASIS ONE - The CDS removes dissolved and suspended solids from the condensate prior to startup.
 
POWER GENERATION DESIGN BASIS TWO - The CDS removes impurities entering the  
 
secondary cycle from condenser leaks that would otherwise deposit or increase corrosion rates in the secondary cycle.  
 
POWER GENERATION DESIGN BASIS THREE - The CDS removes corrosion products from the condensate and any drains returned to the condenser hotwell so as to limit  
 
any accumulation in the secondary cycle.
POWER GENERATION DESIGN BASIS FOUR - The CDS limits the entry of dissolved  
 
solids into the feedwater system in the event of large condenser leaks, such as  
 
a tube break, to permit a reasonable amount of time for plant shutdown.  
 
10.4.6.2  System Description 10.4.6.2.1  General Description  


The CDS consists of demineralizer vessels, regeneration tanks, pumps, piping, instrumentation, and controls, as shown in Figure 10.4-5. The CDS components are located in the turbine building at El. 2000.  
The CDS consists of demineralizer vessels, regeneration tanks, pumps, piping, instrumentation, and controls, as shown in Figure 10.4-5. The CDS components are located in the turbine building at El. 2000.  


10.4.6.2.2  Component Description Codes and standards applicable to the CDS are listed in Table 3.2-2. The system is designed and constructed in accordance with quality group D requirements. Design data for major components of the CDS are listed in Table 10.4-4.
10.4.6.2.2  Component Description  
CONDENSATE DEMINERALIZER VESSELS - The six 20-percent-capacity spherical vessels with deep-bed regenerable mixed strong acid cation/strong base anion resins, are constructed of carbon steel and lined with natural rubber. The design flowrate is approximately 53 gpm per square foot of bed, and the bed depth is approximately 36 inches. 


10.4-17 Rev. 12 WOLF CREEK REGENERATION TANKS - The three resin regeneration tanks are the resin separation and cation regeneration tank, anion regeneration tank, and the resin mixing and storage tank. All tanks are constructed of carbon steel and lined with natural rubber. MISCELLANEOUS EQUIPMENT - Miscellaneous equipment includes two sulfuric acid feed pumps (one standby), two caustic soda feed pumps (one standby), two sluice water pumps (one standby), one sulfuric acid day tank, one caustic soda day tank, one resin addition hopper with eductor, one caustic dilution hot water tank, one waste collection tank, piping, instrumentation, and controls. In addition, one sulfuric acid and one caustic feed pump, which take suction from their respective day tanks, are included to feed chemicals into the high TDS tanks for neutralization of pH adjustment. 10.4.6.2.3  System Operation The CDS is operated as necessary to maintain feed-water purity levels. The condensate demineralizers are capable of both hydrogen or ammonia/amine cycle operation in continuous or intermittent service.
Codes and standards applicable to the CDS are listed in Table 3.2-2. The system is designed and constructed in accordance with quality group D
The ammonia/amine cycle operation with negligible condenser leakage will allow an extended demineralizer run. Operation with large condenser leakage requires that the demineralizer beds be run in the hydrogen cycle to meet secondary side chemistry requirements. Allowable condenser inleakage is limited to levels that will not require continuous regeneration of a demineralizer bed more than once every 2 days.


Condensate flow is passed through up to five of the six demineralizer vessels, which are piped in parallel. The service run for each demineralizer vessel terminates by either high differential pressure across the vessel or high cation conductivity or sodium content in the demineralizer effluent water.
requirements. Design data for major components of the CDS are listed in Table
Alarms for each of these monitoring points are provided on the local control panel. The local control panel is equipped with the appropriate instruments and controls to allow the operators to perform the following operations:


a. Remove an exhausted demineralizer from service and   replace it with a standby unit 
10.4-4.
CONDENSATE DEMINERALIZER VESSELS - The six 20-percent-capacity spherical vessels with deep-bed regenerable mixed strong acid cation/strong base anion resins, are constructed of carbon steel and lined with natural rubber. The design flowrate is approximately 53 gpm per square foot of bed, and the bed depth is approximately 36 inches.


10.4-18 Rev. 14 WOLF CREEK b. Initiate resin transfer from the demineralizer vessel  into the cation regeneration tank  c. Initiate resin transfer from the resin mixing and   storage tank to the empty demineralizer vessel  d. Initiate a complete resin regeneration process e. Initiate a resin wash-air scrub process without chemical  regeneration On termination of a service run, the exhausted demineralizer vessel is taken out of service, and a standby unit is put in service by remote manual operation from the local control panel. The resin from the exhausted vessel is transferred to the cation regeneration tank. The anion and cation resins are hydraulically separated. The anion resin is transferred to the anion regeneration tank. Each resin is then backwashed, chemically regenerated, rinsed, and transferred to the resin mixing and storage tank for final rinsing and mixing.
10.4-17 Rev. 12 WOLF CREEK REGENERATION TANKS - The three resin regeneration tanks are the resin separation and cation regeneration tank, anion regeneration tank, and the resin  


The regeneration process used is a cation/anion separation process which facilitates ammonia cycle operation. The hydraulic process effectively separates and isolates the respective resin components; hence, the technique ensures complete conversion of both resins to the desired regenerated form. This eliminates the possibility of either sodium or sulfate leaching into the condensate stream. During the wash-air scrub process, there is no chemical regeneration involved. This process is used for crud removal when the resin bed has been exhausted by high differential pressure. A final rinse is performed on the demineralizer before it is placed in service. The rinse is monitored by conductivity analyzers, and the process is terminated when the required conductivity is obtained.
mixing and storage tank. All tanks are constructed of carbon steel and lined with natural rubber.
Regenerant chemicals are 66-degrees Baume sulfuric acid and 50-percent liquid caustic soda. Dilution of the sulfuric acid and caustic soda to the required application concentrations and temperatures is accomplished at the time of use in closed low-pressure systems employing in-line mixing tees.
MISCELLANEOUS EQUIPMENT - Miscellaneous equipment includes two sulfuric acid
Regenerant wastes are segregated by total dissolved solid (TDS) content and directed to the low or high TDS tanks in the secondary liquid waste  
 
feed pumps (one standby), two caustic soda feed pumps (one standby), two sluice
 
water pumps (one standby), one sulfuric acid day tank, one caustic soda day tank, one resin addition hopper with eductor, one caustic dilution hot water tank, one waste collection tank, piping, instrumentation, and controls. In
 
addition, one sulfuric acid and one caustic feed pump, which take suction from
 
their respective day tanks, are included to feed chemicals into the high TDS
 
tanks for neutralization of pH adjustment.
10.4.6.2.3  System Operation
 
The CDS is operated as necessary to maintain feed-water purity levels. The
 
condensate demineralizers are capable of both hydrogen or ammonia/amine cycle operation in continuous or intermittent service.
 
The ammonia/amine cycle operation with negligible condenser leakage will allow
 
an extended demineralizer run. Operation with large condenser leakage requires
 
that the demineralizer beds be run in the hydrogen cycle to meet secondary side chemistry requirements. Allowable condenser inleakage is limited to levels that will not require continuous regeneration of a demineralizer bed more than once every 2 days.
 
Condensate flow is passed through up to five of the six demineralizer vessels, which are piped in parallel. The service run for each demineralizer vessel terminates by either high differential pressure across the vessel or high
 
cation conductivity or sodium content in the demineralizer effluent water. 
 
Alarms for each of these monitoring points are provided on the local control
 
panel. The local control panel is equipped with the appropriate instruments and
 
controls to allow the operators to perform the following operations:
: a. Remove an exhausted demineralizer from service and  replace it with a standby unit
 
10.4-18 Rev. 14 WOLF CREEK b. Initiate resin transfer from the demineralizer vessel  into the cation regeneration tank
: c. Initiate resin transfer from the resin mixing and  storage tank to the empty demineralizer vessel
: d. Initiate a complete resin regeneration process
: e. Initiate a resin wash-air scrub process without chemical regeneration
 
On termination of a service run, the exhausted demineralizer vessel is taken
 
out of service, and a standby unit is put in service by remote manual operation from the local control panel. The resin from the exhausted vessel is transferred to the cation regeneration tank. The anion and cation resins are
 
hydraulically separated. The anion resin is transferred to the anion
 
regeneration tank. Each resin is then backwashed, chemically regenerated, rinsed, and transferred to the resin mixing and storage tank for final rinsing and mixing.
 
The regeneration process used is a cation/anion separation process which  
 
facilitates ammonia cycle operation. The hydraulic process effectively  
 
separates and isolates the respective resin components; hence, the technique ensures complete conversion of both resins to the desired regenerated form.
This eliminates the possibility of either sodium or sulfate leaching into the  
 
condensate stream. During the wash-air scrub process, there is no chemical regeneration involved. This process is used for crud removal when the resin bed has been exhausted by high differential pressure.
A final rinse is performed on the demineralizer before it is placed in service.
The rinse is monitored by conductivity analyzers, and the process is terminated  
 
when the required conductivity is obtained.  
 
Regenerant chemicals are 66-degrees Baume sulfuric acid and 50-percent liquid caustic soda. Dilution of the sulfuric acid and caustic soda to the required application concentrations and temperatures is accomplished at the time of use  
 
in closed low-pressure systems employing in-line mixing tees.  
 
Regenerant wastes are segregated by total dissolved solid (TDS) content and directed to the low or high TDS tanks in the secondary liquid waste
 
10.4-19 Rev. 12 WOLF CREEK system. Low TDS waste is generated in the initial backwash and during the final stages of resin rinsing following chemical regeneration. The backwash is
 
usually high in particulate content. The high TDS is generated from the chemical regeneration and the initial stages of the rinsing after chemical
 
regeneration. These values vary depending on how the system is operated.
 
The high and low TDS waste can be processed by either the wastewater treatment
 
facility as shown in Figs. 9.2-24 and 9.2-25, or the secondary liquid waste system as described in Section 10.4.10.
The demineralizer system includes all isolation valves, piping for vessels, post strainers, and equipment necessary for resin transfer. There is also a
 
recirculation line to the condenser for purging aerated water from any vessel being placed in service.


10.4-19 Rev. 12 WOLF CREEK system. Low TDS waste is generated in the initial backwash and during the final stages of resin rinsing following chemical regeneration. The backwash is usually high in particulate content. The high TDS is generated from the chemical regeneration and the initial stages of the rinsing after chemical regeneration. These values vary depending on how the system is operated.
The high and low TDS waste can be processed by either the wastewater treatment facility as shown in Figs. 9.2-24 and 9.2-25, or the secondary liquid waste system as described in Section 10.4.10. The demineralizer system includes all isolation valves, piping for vessels, post strainers, and equipment necessary for resin transfer. There is also a recirculation line to the condenser for purging aerated water from any vessel being placed in service.
10.4.6.2.4  Radioactivity  
10.4.6.2.4  Radioactivity  


Under normal operating conditions, there is insignificant radioactivity present in the steam and power conversion system. It is possible for the cycle to become contaminated through a steam generator tube leak. Based on a postulated primary-to-secondary leak rate, the equilibrium secondary system activities are developed in Chapter 11.0. The condensate demineralizers reduce the radioactivity level in the secondary cycle, as described in Chapter 11.0. Based on the condensate activity and the bed run times, the radioactivity that concentrates on the demineralizer beds will not reach a significant level. The small quantity of radioactive material introduced to the secondary liquid waste system is discussed in Section 10.4.10. Radiation levels near the demineralizers can be limited by increasing the frequency of regeneration of the beds to remove the radioactive material from the resin beds. Administrative controls can be implemented to limit personnel access, if required. 10.4.6.3  Safety Evaluation The CDS serves no safety function.  
Under normal operating conditions, there is insignificant radioactivity present in the steam and power conversion system. It is possible for the cycle to become contaminated through a steam generator tube leak. Based on a postulated  
 
primary-to-secondary leak rate, the equilibrium secondary system activities are  
 
developed in Chapter 11.0. The condensate demineralizers reduce the  
 
radioactivity level in the secondary cycle, as described in Chapter 11.0.
Based on the condensate activity and the bed run times, the radioactivity that concentrates on the demineralizer beds will not reach a significant level. The  
 
small quantity of radioactive material introduced to the secondary liquid waste  
 
system is discussed in Section 10.4.10.
Radiation levels near the demineralizers can be limited by increasing the  
 
frequency of regeneration of the beds to remove the radioactive material from  
 
the resin beds. Administrative controls can be implemented to limit personnel  
 
access, if required.
10.4.6.3  Safety Evaluation The CDS serves no safety function.  
 
10.4-20 Rev. 12 WOLF CREEK 10.4.6.4  Tests and Inspections Preoperational testing of the CDS, as described in Chapter 14.0, ensured the proper functioning of the equipment and instrumentation. The system operating parameters are monitored during power operation.
 
10.4.6.5  Instrumentation Applications Continuous, on-line instrumentation is provided to monitor equipment performance in service or during the regeneration cycle. Local and control room alarms annunciate trouble in the system. Systematic analysis of local samples is performed to monitor the accuracy of the automatic equipment. Flow
 
and differential pressure are continually monitored, in addition to ionic concentration for both influent and effluent streams. 


10.4-20 Rev. 12 WOLF CREEK 10.4.6.4  Tests and Inspections  Preoperational testing of the CDS, as described in Chapter 14.0, ensured the proper functioning of the equipment and instrumentation. The system operating parameters are monitored during power operation.
10.4.6.5  Instrumentation Applications  Continuous, on-line instrumentation is provided to monitor equipment performance in service or during the regeneration cycle. Local and control room alarms annunciate trouble in the system. Systematic analysis of local samples is performed to monitor the accuracy of the automatic equipment. Flow and differential pressure are continually monitored, in addition to ionic concentration for both influent and effluent streams.
10.4.7  CONDENSATE AND FEEDWATER SYSTEM  
10.4.7  CONDENSATE AND FEEDWATER SYSTEM  


The function of the condensate and feedwater system (CFS) is to receive condensate from the condenser hotwells and deliver feedwater, at required pressure and temperature, to the four steam generators.  
The function of the condensate and feedwater system (CFS) is to receive condensate from the condenser hotwells and deliver feedwater, at required pressure and temperature, to the four steam generators.  


10.4.7.1  Design Bases 10.4.7.1.1  Safety Design Bases The portion of the CFS from the steam generator to the steam generator isolation valves is safety related and is required to function following a DBA and to achieve and maintain the plant in a post accident safe shutdown condition.
10.4.7.1  Design Bases 10.4.7.1.1  Safety Design Bases The portion of the CFS from the steam generator to the steam generator isolation valves is safety related and is required to function following a DBA  
SAFETY DESIGN BASIS ONE - The safety-related portion of the CFS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2). SAFETY DESIGN BASIS TWO - The safety-related portion of the CFS is designed to remain functional after an SSE or to perform its intended function following postulated hazards such as internal missiles, or pipe break (GDC-4). SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).   
 
and to achieve and maintain the plant in a post accident safe shutdown condition.  
 
SAFETY DESIGN BASIS ONE - The safety-related portion of the CFS is protected  
 
from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).
SAFETY DESIGN BASIS TWO - The safety-related portion of the CFS is designed to  
 
remain functional after an SSE or to perform its intended function following  


10.4-21 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS FOUR - The CFS is designed such that the active components are capable of being tested during plant operation. Provisions are made to allow for inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code, Section XI. SAFETY DESIGN BASIS FIVE - The CFS is designed and fabricated to codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32.
postulated hazards such as internal missiles, or pipe break (GDC-4).
SAFETY DESIGN BASIS SIX - For a main feedwater line break inside the containment or an MSLB, the CFS is designed to limit high energy fluid to the broken loop and to provide a path for addition of auxiliary feedwater to the three intact loops.
SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-
SAFETY DESIGN BASIS SEVEN - For a main feedwater line break upstream of the main feedwater isolation valve (outside of the containment), the CFS is designed to prevent the blowdown of any steam generator and to provide a path for the addition of auxiliary feedwater.
 
SAFETY DESIGN BASIS EIGHT - The CFS is designed to provide a path to permit the addition of auxiliary feedwater for reactor cooldown under emergency shutdown conditions (GDC-34). 10.4.7.1.2  Power Generation Design Bases  
34).   
 
10.4-21 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS FOUR - The CFS is designed such that the active components are capable of being tested during plant operation. Provisions are made to  
 
allow for inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code, Section XI.
SAFETY DESIGN BASIS FIVE - The CFS is designed and fabricated to codes  
 
consistent with the quality group classification assigned by Regulatory Guide  
 
1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32.  
 
SAFETY DESIGN BASIS SIX - For a main feedwater line break inside the  
 
containment or an MSLB, the CFS is designed to limit high energy fluid to the  
 
broken loop and to provide a path for addition of auxiliary feedwater to the three intact loops.  
 
SAFETY DESIGN BASIS SEVEN - For a main feedwater line break upstream of the main feedwater isolation valve (outside of the containment), the CFS is  
 
designed to prevent the blowdown of any steam generator and to provide a path for the addition of auxiliary feedwater.  
 
SAFETY DESIGN BASIS EIGHT - The CFS is designed to provide a path to permit the  
 
addition of auxiliary feedwater for reactor cooldown under emergency shutdown  
 
conditions (GDC-34).
10.4.7.1.2  Power Generation Design Bases  
 
POWER GENERATION DESIGN BASIS ONE - The CFS is designed to provide a continuous
 
feedwater supply to the four steam generators at required pressure and temperature under anticipated steady-state and transient conditions.
POWER GENERATION DESIGN BASIS TWO - The CFS is designed to control the
 
dissolved oxygen content and pH in the turbine cycle and the steam generators.


POWER GENERATION DESIGN BASIS ONE - The CFS is designed to provide a continuous feedwater supply to the four steam generators at required pressure and temperature under anticipated steady-state and transient conditions. POWER GENERATION DESIGN BASIS TWO - The CFS is designed to control the dissolved oxygen content and pH in the turbine cycle and the steam generators.
POWER GENERATION DESIGN BASIS THREE - The CFS is designed to maintain feedwater flow following a 50-percent step reduction in electrical load.  
POWER GENERATION DESIGN BASIS THREE - The CFS is designed to maintain feedwater flow following a 50-percent step reduction in electrical load.  


POWER GENERATION DESIGN BASIS FOUR - The CFS is designed to provide heated feedwater to the steam generators during startup and shutdown to minimize thermal stresses and preclude steam generator feedwater nozzle cracking.   
POWER GENERATION DESIGN BASIS FOUR - The CFS is designed to provide heated  
 
feedwater to the steam generators during startup and shutdown to minimize thermal stresses and preclude steam generator feedwater nozzle cracking.  
 
10.4-22 Rev. 0 WOLF CREEK 10.4.7.2  System Description 10.4.7.2.l General Description The CFS, as shown in Figures 10.4-2 and 10.4-6, consists of three condensate pumps, two 67-percent capacity turbine-driven steam generator feedwater pumps, one 480 gpm capacity motor-driven feedwater pump, four stages of low-pressure
 
feedwater heaters, and three stages of high-pressure feedwater heaters, piping, valves, and instrumentation. The condensate pumps take suction from the condenser hotwell and discharge the condensate into one common header which
 
feeds the condensate demineralizers. The condensate demineralizers may be by-
 
passed. Downstream of the condensate demineralizers, the header branches into
 
three parallel trains. Each train contains four stages of low-pressure feedwater heaters. The trains join together at a common header which branches into two lines which go to the suction of the steam generator feedwater pumps. 
 
The turbine-driven feedwater pumps discharge the feedwater into two cross-connected parallel trains. Each of the two trains contains three stages of
 
high-pressure feedwater heaters. Another feedwater path is provided to allow the low pressure feedwater heaters and the turbine-driven feed pumps to be bypassed during start-up and shut-down. The motor-driven feedwater pump in
 
this path discharges into the common header downstream of the turbine-driven


10.4-22 Rev. 0 WOLF CREEK 10.4.7.2  System Description  10.4.7.2.l  General Description  The CFS, as shown in Figures 10.4-2 and 10.4-6, consists of three condensate pumps, two 67-percent capacity turbine-driven steam generator feedwater pumps, one 480 gpm capacity motor-driven feedwater pump, four stages of low-pressure feedwater heaters, and three stages of high-pressure feedwater heaters, piping, valves, and instrumentation. The condensate pumps take suction from the condenser hotwell and discharge the condensate into one common header which feeds the condensate demineralizers. The condensate demineralizers may be by-passed. Downstream of the condensate demineralizers, the header branches into three parallel trains. Each train contains four stages of low-pressure feedwater heaters. The trains join together at a common header which branches into two lines which go to the suction of the steam generator feedwater pumps.
feed pumps and upstream of the high-pressure feedwater heaters. Downstream of  
The turbine-driven feedwater pumps discharge the feedwater into two cross-connected parallel trains. Each of the two trains contains three stages of high-pressure feedwater heaters. Another feedwater path is provided to allow the low pressure feedwater heaters and the turbine-driven feed pumps to be bypassed during start-up and shut-down. The motor-driven feedwater pump in this path discharges into the common header downstream of the turbine-driven feed pumps and upstream of the high-pressure feedwater heaters. Downstream of the high-pressure feedwater heaters, the two trains are then joined into a common header, which divides into four lines which connect to the four steam generators. Each of the four lines contains a main feedwater control valve and main feedwater bypass control valve, a feedwater flow element, a power-operated main feedwater isolation valve (MFIV), an auxiliary feedwater connection, a chemical injection connection, and a check valve. The condensate and feedwater chemical injection system, as shown in Figure 10.4-7, is provided to inject an oxygen control chemical and the pH control chemical into the condensate pump discharge downstream of the condensate demineralizers and additional oxygen and pH control chemicals into the four main feedwater lines connecting with the four steam generators. Injection points are shown in Figure 10.4-6.


During normal power operation, the continuous addition of oxygen and pH control chemicals to the condensate system is under automatic control, with manual control optional. As discussed in Section 10.3 5, the addition of the pH control chemical and oxygen control chemical establishes the design pH according to the condensate and feedwater system chemistry requirements and establishes a constant initial oxygen control chemical residual in the feed-water system so that oxygen inleakage can be scavenged.  
the high-pressure feedwater heaters, the two trains are then joined into a common header, which divides into four lines which connect to the four steam generators. Each of the four lines contains a main feedwater control valve and
 
main feedwater bypass control valve, a feedwater flow element, a power-operated
 
main feedwater isolation valve (MFIV), an auxiliary feedwater connection, a
 
chemical injection connection, and a check valve.
The condensate and feedwater chemical injection system, as shown in Figure
 
10.4-7, is provided to inject an oxygen control chemical and the pH control
 
chemical into the condensate pump discharge downstream of the condensate
 
demineralizers and additional oxygen and pH control chemicals into the four main feedwater lines connecting with the four steam generators. Injection points are shown in Figure 10.4-6.
 
During normal power operation, the continuous addition of oxygen and pH control  
 
chemicals to the condensate system is under automatic control, with manual control optional. As discussed in Section 10.3 5, the addition of the pH control chemical and oxygen control chemical establishes the design pH  
 
according to the condensate and feedwater system chemistry requirements and  
 
establishes a constant initial oxygen control chemical residual in the feed-
 
water system so that oxygen inleakage can be scavenged.  


10.4-23 Rev. 23 WOLF CREEK The following measures have been taken to protect personnel from any toxic effects of chemicals:
10.4-23 Rev. 23 WOLF CREEK The following measures have been taken to protect personnel from any toxic effects of chemicals:
a. The pH control chemical and oxygen control chemical solution  and measuring tanks are provided with a 5-psig nitrogen  blanket to minimize vapors in the general atmosphere of the  turbine building. b. The concentrated ammonium hydroxide and hydrazine are  diluted to less than a 17-percent chemical solution. c. Corrosion-resistant construction materials (stainless steels) are used throughout the storage and injection equipment.
: a. The pH control chemical and oxygen control chemical solution  and measuring tanks are provided with a 5-psig nitrogen  blanket to minimize vapors in the general atmosphere of the  turbine building.
d. Chemical mixing is accomplished by closed-loop recirculation with centrifugal recirculation pumps. No external tank mixers are used to agitate tank contents. e. Ammonium hydroxide and hydrazine drum unloading is accomplished with air-driven drum bung pumps, which are nonsparking and pose no electrical hazard to personnel. The manually controlled feedwater chemical addition system is provided for special plant conditions, such as hydrostatic test, hot standby, layup, etc. These conditions require high levels of pH and oxygen control chemical residual to minimize corrosion in the steam generators.
: b. The concentrated ammonium hydroxide and hydrazine are  diluted to less than a 17-percent chemical solution.
Component failures within the CFS which affect the final feedwater temperature or flow have a direct effect on the reactor coolant system and are listed in Table 10.4-5. Occurrences which produce an increase in feedwater flow or a decrease in feedwater temperature result in increased heat removal from the reactor coolant system, which is compensated for by control system action, as described in Section 7.7. Events which produce the opposite effect, i.e., decreased feedwater flow or increased feedwater temperature, result in reduced heat transfer in the steam generators. Normally, automatic control system action is available to adjust feedwater flow and reactor power to prevent excess energy accumulation in the reactor coolant system, and the increasing reactor coolant temperature provides a negative reactivity feedback which tends to reduce reactor power. In the absence of normal control action, either the high outlet temperature or high  
: c. Corrosion-resistant construction materials (stainless steels) are used throughout the storage and injection equipment.
: d. Chemical mixing is accomplished by closed-loop recirculation with centrifugal recirculation pumps. No external tank mixers are used to agitate tank contents.
: e. Ammonium hydroxide and hydrazine drum unloading is accomplished with air-driven drum bung pumps, which are nonsparking and pose no electrical hazard to personnel.
The manually controlled feedwater chemical addition system is provided for special plant conditions, such as hydrostatic test, hot standby, layup, etc.
These conditions require high levels of pH and oxygen control chemical residual to minimize corrosion in the steam generators.  
 
Component failures within the CFS which affect the final feedwater temperature or flow have a direct effect on the reactor coolant system and are listed in  
 
Table 10.4-5. Occurrences which produce an increase in feedwater flow or a decrease in feedwater temperature result in increased heat removal from the  
 
reactor coolant system, which is compensated for by control system action, as described in Section 7.7. Events which produce the opposite effect, i.e., decreased feedwater flow or increased feedwater temperature, result in reduced  
 
heat transfer in the steam generators. Normally, automatic control system  
 
action is available to adjust feedwater flow and reactor power to prevent  
 
excess energy accumulation in the reactor coolant system, and the increasing reactor coolant temperature provides a negative reactivity feedback which tends to reduce reactor power. In the absence of normal control action, either the  
 
high outlet temperature or high  
 
10.4-24 Rev. 12 WOLF CREEK pressure trips of the reactor by the reactor protection system are available to assure reactor safety. Loss of all feedwater, the most severe transient of
 
this type, is examined in Chapter 15.0.
Refer to Section 5.4 for a discussion of steam generator design features to
 
preclude fluid flow instabilities, such as water hammer. The feedwater
 
connection on each of the steam generators is the highest point of each
 
feedwater line downstream of the MFIV. The feedwater lines contain no high point pockets which, if present, could trap steam and lead to water hammer.
The horizontal run length from the feedwater nozzle of each steam generator is
 
minimized. The routing of the main feedwater lines is shown in Figures 1.2-12, 1.2-15, and 1.2-17.
 
During refuel 5, temporary non-safety related instrumentation was added for monitoring the temperature stratification occurring inside the Feedwater
 
piping. The non-safety auxiliary feedwater pump (NSAFP) minimum recirculation discharges to the condensate reject line to the Condensate Storage Tank as shown in Figure 10.4-2.
 
10.4.7.2.2  Component Description
 
Codes and standards applicable to the CFS are listed in Table 3.2-1. The CFS is designed and constructed in accordance with quality group B and seismic
 
Category I requirements from the steam generator out to the torsional restraint
 
upstream of the main feedwater isolation valves. The remaining piping of the
 
CFS meets ANSI B31.1 requirements. Branch lines out to and including isolation valves for the auxiliary feedwater and chemical injection are designed and constructed in accordance with quality group B and seismic Category I
 
requirements. Refer to Tables 10.1-1 and 10.4-6 for design data. Safety-
 
related feedwater piping materials are discussed in Section 10.3.6.
 
MAIN FEEDWATER PIPING - Feedwater is supplied to the four steam generators by four 14-inch carbon steel lines. Each of the lines is anchored at the
 
containment wall and has sufficient flexibility to provide for relative
 
movement of the steam generators due to thermal expansion. The main feedwater
 
line and associated branch lines between the containment penetration and the torsional restraint upstream of the MFIV are designed to meet the "no break zone" criteria, as described in NRC BTP MEB-3-1 (refer to Section 3.6).
 
MAIN FEEDWATER ISOLATION VALVES - One main feedwater isolation valve (MFIV) is
 
installed in each of the four main feedwater lines outside the containment and downstream of the feedwater control valve. The MFIVs are installed to prevent uncontrolled blowdown from more than one steam generator in the event of a
 
feedwater pipe rupture in the turbine building. The main feedwater check valve
 
provides backup isolation. The MFIVs isolate the nonsafety-related portions
 
from the safety-related portions of the system. In the event of a secondary
 
cycle pipe rupture inside the containment, the MFIV limits the quantity of high energy fluid that 
 
10.4-25 Rev. 27 WOLF CREEK enters the containment through the broken loop and provides a pressure boundary for the controlled addition of auxiliary feedwater to the three intact loops. 
 
The valves are bi-directional, double disc, parallel slide gate valves. The valves are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or clsoe) is accomplished through a series of six electric solenoid pilot valves, which direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves are divided into two trains that are independently powered and controlled.
Either train can independently perform the safety function to fast close the valve. Electrical solenoids are energized from separate Class 1E sources.
MAIN FEEDWATER CONTROL VALVES AND CONTROL BYPASS VALVES - The MF control valves are air-operated angle valves which automatically control feedwater between 30
 
percent and full power. The bypass control valves are air-operated globe valves, which are used during startup up to 25-percent power. The MF control valves and bypass control valves are located in the turbine building.
In the event of a secondary cycle pipe rupture inside the containment, the main
 
feedwater control valve (and associated bypass valve) provide a diverse backup
 
to the MFIV to limit the quantity of high energy fluid that enters the
 
containment through the broken loop. For emergency closure, either of two separate solenoids, when de-energized, results in valve closure. Electrical solenoids are energized from separate Class 1E sources.
 
MAIN FEEDWATER CHECK VALVES - The Main Feedwater check valves are located in
 
Area 5 inside the auxiliary building, upstream of the auxiliary feedwater connection and downstream of the main feedwater isolation valves. In the event of a secondary cycle pipe rupture outside containment, the main feedwater check
 
valves provide a diverse backup to the MFIV to ensure the pressure boundary of
 
any intact loop not receiving auxiliary feedwater.
 
In the event of a feedwater line rupture outside containment in the turbine building the feedwater check valve will close and terminate blowdown from the


10.4-24 Rev. 12 WOLF CREEK pressure trips of the reactor by the reactor protection system are available to assure reactor safety. Loss of all feedwater, the most severe transient of this type, is examined in Chapter 15.0. Refer to Section 5.4 for a discussion of steam generator design features to preclude fluid flow instabilities, such as water hammer. The feedwater connection on each of the steam generators is the highest point of each feedwater line downstream of the MFIV. The feedwater lines contain no high point pockets which, if present, could trap steam and lead to water hammer. The horizontal run length from the feedwater nozzle of each steam generator is minimized. The routing of the main feedwater lines is shown in Figures 1.2-12, 1.2-15, and 1.2-17.
steam generator.  
During refuel 5, temporary non-safety related instrumentation was added for monitoring the temperature stratification occurring inside the Feedwater piping. The non-safety auxiliary feedwater pump (NSAFP) minimum recirculation discharges to the condensate reject line to the Condensate Storage Tank as shown in Figure 10.4-2.
10.4.7.2.2  Component Description Codes and standards applicable to the CFS are listed in Table 3.2-1. The CFS is designed and constructed in accordance with quality group B and seismic Category I requirements from the steam generator out to the torsional restraint upstream of the main feedwater isolation valves. The remaining piping of the CFS meets ANSI B31.1 requirements. Branch lines out to and including isolation valves for the auxiliary feedwater and chemical injection are designed and constructed in accordance with quality group B and seismic Category I requirements. Refer to Tables 10.1-1 and 10.4-6 for design data. Safety-related feedwater piping materials are discussed in Section 10.3.6.
MAIN FEEDWATER PIPING - Feedwater is supplied to the four steam generators by four 14-inch carbon steel lines. Each of the lines is anchored at the containment wall and has sufficient flexibility to provide for relative movement of the steam generators due to thermal expansion. The main feedwater line and associated branch lines between the containment penetration and the torsional restraint upstream of the MFIV are designed to meet the "no break zone" criteria, as described in NRC BTP MEB-3-1 (refer to Section 3.6).  


MAIN FEEDWATER ISOLATION VALVES - One main feedwater isolation valve (MFIV) is installed in each of the four main feedwater lines outside the containment and downstream of the feedwater control valve. The MFIVs are installed to prevent uncontrolled blowdown from more than one steam generator in the event of a feedwater pipe rupture in the turbine building. The main feedwater check valve provides backup isolation. The MFIVs isolate the nonsafety-related portions from the safety-related portions of the system. In the event of a secondary cycle pipe rupture inside the containment, the MFIV limits the quantity of high energy fluid that 
CHEMICAL ADDITION LINE CHECK VALVES AND ISOLATION VALVES - The check valves are located downstream from the isolation valves in the chemical addition lines.
The check valves provide a diverse backup to the isolation valves to ensure the  


10.4-25 Rev. 27 WOLF CREEK enters the containment through the broken loop and provides a pressure boundary for the controlled addition of auxiliary feedwater to the three intact loops.
pressure boundary. The normally closed isolation valves are air-operated valves which fail closed.  
The valves are bi-directional, double disc, parallel slide gate valves. The valves are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or clsoe) is accomplished through a series of six electric solenoid pilot valves, which direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves are divided into two trains that are independently powered and controlled. Either train can independently perform the safety function to fast close the valve. Electrical solenoids are energized from separate Class 1E sources. MAIN FEEDWATER CONTROL VALVES AND CONTROL BYPASS VALVES - The MF control valves are air-operated angle valves which automatically control feedwater between 30 percent and full power. The bypass control valves are air-operated globe valves, which are used during startup up to 25-percent power. The MF control valves and bypass control valves are located in the turbine building. In the event of a secondary cycle pipe rupture inside the containment, the main feedwater control valve (and associated bypass valve) provide a diverse backup to the MFIV to limit the quantity of high energy fluid that enters the containment through the broken loop. For emergency closure, either of two separate solenoids, when de-energized, results in valve closure. Electrical solenoids are energized from separate Class 1E sources.  


MAIN FEEDWATER CHECK VALVES - The Main Feedwater check valves are located in Area 5 inside the auxiliary building, upstream of the auxiliary feedwater connection and downstream of the main feedwater isolation valves. In the event of a secondary cycle pipe rupture outside containment, the main feedwater check valves provide a diverse backup to the MFIV to ensure the pressure boundary of any intact loop not receiving auxiliary feedwater.
10.4-26 Rev. 24 WOLF CREEK CONDENSATE PUMPS - The three condensate pumps are motor driven and operate in parallel. Valving is provided to allow individual pumps to be removed from  
In the event of a feedwater line rupture outside containment in the turbine building the feedwater check valve will close and terminate blowdown from the steam generator.


CHEMICAL ADDITION LINE CHECK VALVES AND ISOLATION VALVES - The check valves are located downstream from the isolation valves in the chemical addition lines. The check valves provide a diverse backup to the isolation valves to ensure the pressure boundary. The normally closed isolation valves are air-operated valves which fail closed.
service. Pump capacity is sufficient to meet full power requirements with two of the three pumps in operation.
LOW-PRESSURE FEEDWATER HEATERS - Parallel strings of closed feedwater heaters


10.4-26 Rev. 24 WOLF CREEK CONDENSATE PUMPS - The three condensate pumps are motor driven and operate in parallel. Valving is provided to allow individual pumps to be removed from service. Pump capacity is sufficient to meet full power requirements with two of the three pumps in operation. LOW-PRESSURE FEEDWATER HEATERS - Parallel strings of closed feedwater heaters are located in the condenser necks. The No. 1, 2, 3 and 4 heaters have integral drain coolers, and their drains are cascaded to the next lower stage feedwater heater in each case. The drains from No. 1 heaters are dumped to the main condenser. Feedwater leaving the No. 4 heaters is headered and goes to the steam generator feed pumps. The heater shells are carbon steel, and the tubes are stainless steel.
are located in the condenser necks. The No. 1, 2, 3 and 4 heaters have  
HIGH-PRESSURE FEEDWATER HEATERS - Parallel strings of three high-pressure feedwater heaters with integral drain coolers in heaters 6 and 7 are used. The No. 7 heaters are drained to the No. 6 heaters which, in turn, drain to the heater drain tank. The No. 5 heaters drain directly to the heater drain tank.
The heater shells are carbon steel, and the tubes are stainless steel. A  bypass line around the parallel strings of high-pressure feedwater heaters may  be used to lower the temperature of the feedwater inlet to the steam generators  such that reactor thermal power can be maximized within the licensed limit. Isolation valves and bypasses are provided which allow each string of high-pressure and low-pressure heaters to be removed from service. System operability is maintained at reduced power with the parallel heaters and bypass  line.


Provisions are made in all heater drain lines, except No. 5, which drains via the heater drain tank, to allow direct discharge to the condenser in the event the normal drain path is blocked.
integral drain coolers, and their drains are cascaded to the next lower stage feedwater heater in each case. The drains from No. 1 heaters are dumped to the main condenser. Feedwater leaving the No. 4 heaters is headered and goes to
HEATER DRAIN TANK - A single heater drain tank drains the shells of No. 5 and No. 6 feedwater heaters and provides reservoir capacity for drain pumping. The heater drain tank is installed in such a way that the No. 5 heaters drain freely by gravity flow. The drain level is maintained within the tank by a level controller in conjunction with a heater drain pump.  
 
the steam generator feed pumps. The heater shells are carbon steel, and the
 
tubes are stainless steel.
 
HIGH-PRESSURE FEEDWATER HEATERS - Parallel strings of three high-pressure feedwater heaters with integral drain coolers in heaters 6 and 7 are used. The
 
No. 7 heaters are drained to the No. 6 heaters which, in turn, drain to the heater drain tank. The No. 5 heaters drain directly to the heater drain tank. 
 
The heater shells are carbon steel, and the tubes are stainless steel. A bypass line around the parallel strings of high-pressure feedwater heaters may be used to lower the temperature of the feedwater inlet to the steam generators such that reactor thermal power can be maximized within the licensed limit.
Isolation valves and bypasses are provided which allow each string of high-pressure and low-pressure heaters to be removed from service. System operability is maintained at reduced power with the parallel heaters and bypass line.
 
Provisions are made in all heater drain lines, except No. 5, which drains via the heater drain tank, to allow direct discharge to the condenser in the event the normal drain path is blocked.  
 
HEATER DRAIN TANK - A single heater drain tank drains the shells of No. 5 and  
 
No. 6 feedwater heaters and provides reservoir capacity for drain pumping. The heater drain tank is installed in such a way that the No. 5 heaters drain freely by gravity flow. The drain level is maintained within the tank by a  
 
level controller in conjunction with a heater drain pump.
 
The heater drain tank is provided with an alternate drain line to the main condenser for automatic dumping upon high level. The alternate drain line is also used during startup and shutdown when it is desirable to bypass the drain
 
piping for feedwater quality purposes.  


The heater drain tank is provided with an alternate drain line to the main condenser for automatic dumping upon high level. The alternate drain line is also used during startup and shutdown when it is desirable to bypass the drain piping for feedwater quality purposes.
HEATER DRAIN PUMPS - Two motor-driven heater drain pumps operate in parallel, taking suction from the heater drain tank and discharging it into the suction of the steam generator feed pumps.  
HEATER DRAIN PUMPS - Two motor-driven heater drain pumps operate in parallel, taking suction from the heater drain tank and discharging it into the suction of the steam generator feed pumps.  


10.4-27 Rev. 11 WOLF CREEK The piping arrangement allows each heater drain pump to be individually removed from service while operating the remaining pump.
10.4-27 Rev. 11 WOLF CREEK The piping arrangement allows each heater drain pump to be individually removed from service while operating the remaining pump.  
STEAM GENERATOR FEEDWATER PUMPS - The steam generator feedwater pumps (SGFP) operate in parallel and discharge to the high-pressure feedwater heaters. The pumps take suction following the No. 4, low-pressure feedwater heaters and discharge through the high-pressure feedwater heaters. Each pump is turbine driven with independent speed-control units. Steam for the turbines is supplied from the main steam header at low loads and from the moisture separator reheater outlet during normal operation.  
 
STEAM GENERATOR FEEDWATER PUMPS - The steam generator feedwater pumps (SGFP) operate in parallel and discharge to the high-pressure feedwater heaters. The pumps take suction following the No. 4, low-pressure feedwater heaters and  
 
discharge through the high-pressure feedwater heaters. Each pump is turbine  
 
driven with independent speed-control units. Steam for the turbines is supplied from the main steam header at low loads and from the moisture separator reheater outlet during normal operation.  
 
Isolation valves are provided which allow each steam generator feed pump to be
 
individually removed from service, while continuing operations at reduced capacity.
 
PUMP RECIRCULATION SYSTEMS - Minimum-flow control systems are provided to allow all pumps in the main condensate and feedwater trains to pump at the
 
manufacturer's recommended minimum flow rate to prevent damage.
MOTOR-DRIVEN FEEDWATER PUMP - One motor-driven feedwater pump (MDFP) is
 
provided to feed heated feedwater to the steam generators during start-up and
 
shutdown conditions. The pump takes suction from the steam generator blowdown


Isolation valves are provided which allow each steam generator feed pump to be individually removed from service, while continuing operations at reduced capacity.
regenerative heat exchanger and discharges through the high-pressure feedwater heaters.
PUMP RECIRCULATION SYSTEMS - Minimum-flow control systems are provided to allow all pumps in the main condensate and feedwater trains to pump at the manufacturer's recommended minimum flow rate to prevent damage. MOTOR-DRIVEN FEEDWATER PUMP - One motor-driven feedwater pump (MDFP) is provided to feed heated feedwater to the steam generators during start-up and shutdown conditions. The pump takes suction from the steam generator blowdown regenerative heat exchanger and discharges through the high-pressure feedwater heaters.
10.4.7.2.3  System Operation  
10.4.7.2.3  System Operation  


STARTUP OPERATION - Feedwater can be provided to the steam generators using the condensate and feedwater system or the auxiliary feedwater system. Feedwater preheating requires the normal feedwater system in operation. Feedwater preheating is used to minimize thermal stresses on the feedwater piping and steam generator feedwater nozzles. At low pressures the condensate pumps can provide sufficient pressure to provide flow to the generators. Above condensate pressure a feedwater pump must also be used. A motor-driven feedwater pump (MDFP) is provided that may be used to provide feedwater at low powers(~1.5%) until there is adequate steam flow to operate the main feedwater pumps. The condensate system is used to provide a suction source for the MDFP. If the MDFP is used, the condensate flow path to this pump will bypass the low-pressure feedwater heaters. This condensate is directed to the steam generator blowdown regenerative heat exchanger, where it will be heated by the discharge from the steam generator blowdown flash tank if the steam generator blowdown (SGBD) system is in service. The feedwater flowpath then is directed through the high pressure feedwater system to the steam generators. The vapor from the SGBD flash tank is normally routed to the heater drain tank. The vapor in the heater drain tank enters the No. 5 high-pressure heaters which in turn will heat the feedwater for the steam generators. Additional heating can be provided from main steam using portions of the auxiliary steam and the extraction steam systems to the No. 6 high-pressure heaters. Main steam can also be used to the No. 6 and 7 high-pressure heaters using additional portions of the main steam system and controls. During this time, two condenser steam dumps, AB UV-34 and AB UV-35, will be isolated. This feedwater preheating is removed from service prior to 25% thermal power. The feedwater is generally operated to maintain feedwater temperature to within 250oF of the steam generator temperature.
STARTUP OPERATION - Feedwater can be provided to the steam generators using the condensate and feedwater system or the auxiliary feedwater system. Feedwater preheating requires the normal feedwater system in operation. Feedwater preheating is used to minimize thermal stresses on the feedwater piping and steam generator feedwater nozzles. At low pressures the condensate pumps can provide sufficient pressure to provide flow to the generators. Above condensate pressure a feedwater pump must also be used. A motor-driven feedwater pump (MDFP) is provided that may be used to provide feedwater at low powers(~1.5%) until there is adequate steam flow to operate the main feedwater pumps. The condensate system is used to provide a suction source for the MDFP.
10.4-28 Rev. 15 WOLF CREEK SHUTDOWN OPERATION - During shutdown operation several possible paths can be used. First the condensate system may be used alone when steam generator pressure is low. At higher required feedwater pressure the MDFP or the main feedwater pumps will be used. The feedwater may be preheated using the SGBD system through the regenerative heat exchanger when the SGBD system is in service. Additional heating can be utilized from the steam generator flash tank vapor. The steam generator flash tank is normally aligned to the heater drain tank where the vapor flows up to the No. 5 high-pressure heaters adding heat to the feedwater system. When below 25%, main steam can be used to heat the feedwater by using portions of the auxiliary steam system and the extraction steam system to the No. 5 high-pressure heaters. The feedwater is preheated to minimize thermal stresses on the feedwater piping and steam generator feedwater nozzles. This system generally maintains feedwater temperature to within 250oF of the steam generator temperature. If these systems are not available, then auxiliary feedwater will be used. Auxiliary feedwater does not provide preheating to the feedwater.  
If the MDFP is used, the condensate flow path to this pump will bypass the low-pressure feedwater heaters. This condensate is directed to the steam generator blowdown regenerative heat exchanger, where it will be heated by the discharge from the steam generator blowdown flash tank if the steam generator blowdown (SGBD) system is in service. The feedwater flowpath then is directed through the high pressure feedwater system to the steam generators. The vapor from the SGBD flash tank is normally routed to the heater drain tank. The vapor in the heater drain tank enters the No. 5 high-pressure heaters which in turn will heat the feedwater for the steam generators.
Additional heating can be provided from main steam using portions of the auxiliary steam and the extraction steam systems to the No. 6 high-pressure heaters. Main steam can also be used to the No. 6 and 7 high-pressure heaters using additional portions of the main steam system and controls. During this time, two condenser steam dumps, AB UV-34 and AB UV-35, will be isolated. This feedwater preheating is removed from service prior to 25% thermal power. The feedwater is generally operated to maintain feedwater temperature to within 250 o F of the steam generator temperature.  


NORMAL OPERATION - Under normal operating conditions, system operation is automatic. Automatic level control systems control the levels in all feedwater heaters, the heater drain tank, and the condenser hotwells. Feedwater heater levels are controlled by modulating drain valves. Control valves in the discharges of the heater drain pumps control heater drain pump flows in reaction to the level in the heater drain tank. A bypass line around the parallel strings of high-pressure feedwater heaters may be used to lower the temperature of the feedwater inlet to the steam generators such that reactor thermal power can be maximized within the licensed limit. Three valves, two in the makeup line to the condenser from the condensate storage tank and another valve in the return line to the condensate storage tank, control the level in the condenser.
10.4-28 Rev. 15 WOLF CREEK SHUTDOWN OPERATION - During shutdown operation several possible paths can be used. First the condensate system may be used alone when steam generator  
At very low power levels, feedwater is supplied by the motor-driven feedwater pump. Once sufficient steam pressure has been established, an SGFP turbine is started, and from this low power level, to approximately 20-percent power, feedwater flow is under the control of the feedwater bypass control valves and their control system. At between 20 and 30 percent power, feedwater flow is being transferred from the feedwater bypass control valves to the main feedwater control valves. SGFP turbine speed is under manual control.
At greater than 30-percent power, feedwater flow is controlled by the main feedwater control valves, and SGFP turbine speed is automatically controlled. The steam generator feedwater pump turbines are controlled by a speed signal from the feed pump speed control system. The control system utilizes measurements of steam generator steam flow, feedwater pressure, and steam pressure to produce this signal. The pump speed is increased or decreased in accordance with the speed signal by modulating the flow of steam admitted to the pump turbine drivers. The feedwater flow to each steam generator is controlled by a three-element feedwater flow control system to maintain a programmed water level in the steam generator. The feedwater controllers regulate the feedwater control valves and feedwater pump speed by continuously comparing steam generator water level with the programmed level and feedwater flow with the pressure-compensated steam flow signal.


10.4-29 Rev. 21 WOLF CREEK Ten-percent step load and 5-percent per minute ramp changes are accommodated without major effect in the CFS. The system is capable of accepting a 50-percent step load rejection. Under this transient, heater drain pump flow is lost, and the high pressure feedwater heater drain flows are dumped to the condenser via the heater drain tank. The condensate pumps pass full feedwater flow until heater drain pump flow is restored.  
pressure is low. At higher required feedwater pressure the MDFP or the main feedwater pumps will be used. The feedwater may be preheated using the SGBD system through the regenerative heat exchanger when the SGBD system is in service. Additional heating can be utilized from the steam generator flash


EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, or a DBA occurs which results in a feedwater isolation signal, the MFIV and other valves associated with the main feedwater lines are closed.
tank vapor. The steam generator flash tank is normally aligned to the heater
Coordinated operation of the auxiliary feedwater system (refer to Section 10.4.9) and the main steam supply system (refer to Section 10.3) is employed to remove decay heat. 10.4.7.3  Safety Evaluation  Safety evaluations are numbered to correspond to the safety design bases of Section 10.4.7.1.1. SAFETY EVALUATION ONE - The safety-related portions of the CFS are located in the reactor and auxiliary buildings. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.


SAFETY EVALUATION TWO - The safety-related portions of the CFS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as out-lined in Section 7.4, can be achieved and maintained.
drain tank where the vapor flows up to the No. 5 high-pressure heaters adding heat to the feedwater system. When below 25%, main steam can be used to heat the feedwater by using portions of the auxiliary steam system and the


SAFETY EVALUATION THREE - The CFS safety functions are accomplished by redundant means, as indicated by Table 10.4-7. No single failure compromises the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.  
extraction steam system to the No. 5 high-pressure heaters. The feedwater is
 
preheated to minimize thermal stresses on the feedwater piping and steam
 
generator feedwater nozzles. This system generally maintains feedwater temperature to within 250 o F of the steam generator temperature. If these systems are not available, then auxiliary feedwater will be used. Auxiliary feedwater does not provide preheating to the feedwater.
 
NORMAL OPERATION - Under normal operating conditions, system operation is automatic. Automatic level control systems control the levels in all feedwater heaters, the heater drain tank, and the condenser hotwells. Feedwater heater
 
levels are controlled by modulating drain valves. Control valves in the
 
discharges of the heater drain pumps control heater drain pump flows in
 
reaction to the level in the heater drain tank.
A bypass line around the parallel strings of high-pressure feedwater heaters
 
may be used to lower the temperature of the feedwater inlet to the steam
 
generators such that reactor thermal power can be maximized within the licensed
 
limit. Three valves, two in the makeup line to the condenser from the condensate
 
storage tank and another valve in the return line to the condensate storage
 
tank, control the level in the condenser.
 
At very low power levels, feedwater is supplied by the motor-driven feedwater pump. Once sufficient steam pressure has been established, an SGFP turbine is
 
started, and from this low power level, to approximately 20-percent power, feedwater flow is under the control of the feedwater bypass control valves and
 
their control system. At between 20 and 30 percent power, feedwater flow is being transferred from the feedwater bypass control valves to the main feedwater control valves. SGFP turbine speed is under manual control.
 
At greater than 30-percent power, feedwater flow is controlled by the main
 
feedwater control valves, and SGFP turbine speed is automatically controlled.
The steam generator feedwater pump turbines are controlled by a speed signal from the feed pump speed control system. The control system utilizes
 
measurements of steam generator steam flow, feedwater pressure, and steam
 
pressure to produce this signal. The pump speed is increased or decreased in
 
accordance with the speed signal by modulating the flow of steam admitted to
 
the pump turbine drivers.
The feedwater flow to each steam generator is controlled by a three-element
 
feedwater flow control system to maintain a programmed water level in the steam
 
generator. The feedwater controllers regulate the feedwater control valves and
 
feedwater pump speed by continuously comparing steam generator water level with the programmed level and feedwater flow with the pressure-compensated steam flow signal.
 
10.4-29 Rev. 21 WOLF CREEK Ten-percent step load and 5-percent per minute ramp changes are accommodated without major effect in the CFS. The system is capable of accepting a 50-
 
percent step load rejection. Under this transient, heater drain pump flow is lost, and the high pressure feedwater heater drain flows are dumped to the condenser via the heater drain tank. The condensate pumps pass full feedwater flow until heater drain pump flow is restored.
 
EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, or a DBA occurs which results in a feedwater isolation signal, the MFIV and other valves associated with the main feedwater lines are closed.
 
Coordinated operation of the auxiliary feedwater system (refer to Section
 
10.4.9) and the main steam supply system (refer to Section 10.3) is employed to
 
remove decay heat.
10.4.7.3  Safety Evaluation Safety evaluations are numbered to correspond to the safety design bases of
 
Section 10.4.7.1.1.
SAFETY EVALUATION ONE - The safety-related portions of the CFS are located in
 
the reactor and auxiliary buildings. These buildings are designed to withstand
 
the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.
 
SAFETY EVALUATION TWO - The safety-related portions of the CFS are designed to
 
remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as out-lined in Section 7.4, can be achieved and maintained.
 
SAFETY EVALUATION THREE - The CFS safety functions are accomplished by redundant means, as indicated by Table 10.4-7. No single failure compromises the system's safety functions. All vital power can be supplied from either  
 
onsite or offsite power systems, as described in Chapter 8.0.  


SAFETY EVALUATION FOUR - Preoperational testing of the CFS is performed as described in Chapter 14.0. Periodic inservice functional testing is done in accordance with Section 10.4.7.4.  
SAFETY EVALUATION FOUR - Preoperational testing of the CFS is performed as described in Chapter 14.0. Periodic inservice functional testing is done in accordance with Section 10.4.7.4.  


Section 6.6 provides the ASME Boiler and Pressure Vessel Code Section XI requirements that are appropriate for the CFS. SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.4-6 shows that the components meet the design and fabrication codes given in Section 3.2. All the power supplies and controls necessary for the safety-related functions of the CFS are Class 1E, as described in Chapters 7.0 and 8.0.
Section 6.6 provides the ASME Boiler and Pressure Vessel Code Section XI  
SAFETY EVALUATION SIX - For a main feedwater line break inside the containment or an MSLB, the MFIVs located in the auxiliary building and the main feedwater control valves located in the turbine building are automatically closed upon receipt of a feedwater isolation signal or low-low steam generator level signal. For each intact loop, the MFIV and main feedwater control valve.   
 
requirements that are appropriate for the CFS.
SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of  
 
this system and supporting systems. Table 10.4-6 shows that the components  
 
meet the design and fabrication codes given in Section 3.2. All the power  
 
supplies and controls necessary for the safety-related functions of the CFS are Class 1E, as described in Chapters 7.0 and 8.0.  
 
SAFETY EVALUATION SIX - For a main feedwater line break inside the containment  
 
or an MSLB, the MFIVs located in the auxiliary building and the main feedwater  
 
control valves located in the turbine building are automatically closed upon receipt of a feedwater isolation signal or low-low steam generator level signal. For each intact loop, the MFIV and main feedwater control valve. 
 
10.4-30 Rev. 19 WOLF CREEK and associated redundant isolation of the chemical addition line will close, forming a pressure boundary to permit auxiliary feedwater addition. The
 
auxiliary feedwater system is described in Section 10.4.9.
SAFETY EVALUATION SEVEN - For a main feedwater line break upstream of the MFIV, the MFIVs are supplied with redundant power supplies and power trains to ensure
 
their closure to isolate safety and nonsafety-related portions of the system.   


10.4-30 Rev. 19 WOLF CREEK and associated redundant isolation of the chemical addition line will close, forming a pressure boundary to permit auxiliary feedwater addition. The auxiliary feedwater system is described in Section 10.4.9. SAFETY EVALUATION SEVEN - For a main feedwater line break upstream of the MFIV, the MFIVs are supplied with redundant power supplies and power trains to ensure their closure to isolate safety and nonsafety-related portions of the system.
Branch lines downstream of the MFIVs contain normally closed, power-operated valves which close on a feedwater isolation signal. These valves fail closed on loss of power.  
Branch lines downstream of the MFIVs contain normally closed, power-operated valves which close on a feedwater isolation signal. These valves fail closed on loss of power.  


Releases of radioactivity from the CFS due to the main feedwater line break are minimal because of the negligible amount of radioactivity in the system under normal operating conditions. Additionally, following a steam generator tube rupture, the main steam isolation system provides controls for reducing accidental releases, as discussed in Section 10.3 and Chapter 15.0. Detection of radioactive leakage into and out of the system is facilitated by area radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).  
Releases of radioactivity from the CFS due to the main feedwater line break are  
 
minimal because of the negligible amount of radioactivity in the system under normal operating conditions. Additionally, following a steam generator tube rupture, the main steam isolation system provides controls for reducing  
 
accidental releases, as discussed in Section 10.3 and Chapter 15.0. Detection of radioactive leakage into and out of the system is facilitated by area  
 
radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).  


SAFETY EVALUATION EIGHT - In the event of loss of offsite power, loss of the steam generator feedwater pumps, or other situations which may result in a loss of main feedwater, the feedwater isolation signal automatically isolates the feedwater system and permit the addition of auxiliary feedwater to allow a controlled reactor cooldown under emergency shutdown conditions. The auxiliary feedwater system is described in Section 10.4.9.
SAFETY EVALUATION EIGHT - In the event of loss of offsite power, loss of the  
10.4.7.4  Tests and Inspections 10.4.7.4.1  Preservice Valve Testing  
 
steam generator feedwater pumps, or other situations which may result in a loss of main feedwater, the feedwater isolation signal automatically isolates the feedwater system and permit the addition of auxiliary feedwater to allow a  
 
controlled reactor cooldown under emergency shutdown conditions. The auxiliary  
 
feedwater system is described in Section 10.4.9.  
 
10.4.7.4  Tests and Inspections 10.4.7.4.1  Preservice Valve Testing  
 
The MFIVs and feedwater control valves were checked for closing time prior to initial startup.


The MFIVs and feedwater control valves were checked for closing time prior to initial startup.
10.4.7.4.2  Preoperational System Testing  
10.4.7.4.2  Preoperational System Testing  


Preoperational testing of the CFS was performed as described in Chapter 14.0. 10.4.7.4.3  Inservice Inspections  
Preoperational testing of the CFS was performed as described in Chapter 14.0.
10.4.7.4.3  Inservice Inspections  


The performance and structural and leaktight integrity of all system components are demonstrated by continuous operation. The feedwater flow venturi is inspected for fouling and cleaned, as necessary, once every 18 months.  
The performance and structural and leaktight integrity of all system components  
 
are demonstrated by continuous operation.
The feedwater flow venturi is inspected for fouling and cleaned, as necessary, once every 18 months.  


10.4-31 Rev. 13 WOLF CREEK The redundant actuator power trains of each MFIV are subjected to the following tests:
10.4-31 Rev. 13 WOLF CREEK The redundant actuator power trains of each MFIV are subjected to the following tests:
a. Closure time - The valves are checked for closure time  at each refueling.
: a. Closure time - The valves are checked for closure time  at each refueling.  
Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is presented in Section 6.6. 10.4.7.5  Instrumentation Applications The main feedwater instrumentation, as described in Table 10.4-8, is designed to facilitate automatic operation, remote control, and continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the secondary cycle pipe rupture protection system.  


The feedwater flow to each steam generator is controlled by a three-element feedwater flow control system to maintain a programmed water level in the steam generator. The three-element feedwater controllers regulate the feedwater control valves by continuously comparing the feedwater flow and steam generator water level with the programmed level and the pressure-compensated steam flow signal (refer to Section 7.7).
Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is presented in Section 6.6.
The steam generator feedwater pump turbine speed is varied to maintain a programmed pressure differential between the steam header and the feed pump discharge header. The pump speed is increased or decreased in accordance with the speed signal by modulating the steam pressure at the inlet of the pump turbine drivers. Both SGFP turbines are tripped upon any one of the following:
10.4.7.5  Instrumentation Applications


a. High-high level in any one steam generator b. Feedwater isolation signal from the engineered safety  features actuation system
The main feedwater instrumentation, as described in Table 10.4-8, is designed


c. Any condition which actuates safety injection (refer to Section 7.3) 
to facilitate automatic operation, remote control, and continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the secondary cycle pipe rupture protection system.


10.4-32 Rev. 24 WOLF CREEK d. Trip of all condensate pump motors  e. High feedwater system pressure  One turbine trips when any one of the following directly affects it:
The feedwater flow to each steam generator is controlled by a three-element


a. Low lube oil pressure b. Turbine overspeed c. Low vacuum
feedwater flow control system to maintain a programmed water level in the steam generator. The three-element feedwater controllers regulate the feedwater control valves by continuously comparing the feedwater flow and steam generator


d. Thrust bearing wear   e. Hydraulic Pressure Unit (HPU) header pressure   f. Turbine trip header oil pressure A flow element with a transmitter is installed on the discharge of each of the condensate and heater drain pumps. The transmitters provide the automatic signals to open the minimum flow valves for the pumps.  
water level with the programmed level and the pressure-compensated steam flow
 
signal (refer to Section 7.7).
 
The steam generator feedwater pump turbine speed is varied to maintain a programmed pressure differential between the steam header and the feed pump discharge header. The pump speed is increased or decreased in accordance with
 
the speed signal by modulating the steam pressure at the inlet of the pump
 
turbine drivers.
Both SGFP turbines are tripped upon any one of the following:
: a. High-high level in any one steam generator
: b. Feedwater isolation signal from the engineered safety  features actuation system
: c. Any condition which actuates safety injection (refer to Section 7.3)
 
10.4-32 Rev. 24 WOLF CREEK d. Trip of all condensate pump motors
: e. High feedwater system pressure One turbine trips when any one of the following directly affects it:
: a. Low lube oil pressure
: b. Turbine overspeed
: c. Low vacuum
: d. Thrust bearing wear
: e. Hydraulic Pressure Unit (HPU) header pressure
: f. Turbine trip header oil pressure A flow element with a transmitter is installed on the discharge of each of the condensate and heater drain pumps. The transmitters provide the automatic  
 
signals to open the minimum flow valves for the pumps.  


A flow element is installed on the suction of each of the steam generator feedwater pumps to provide the control signal to open the minimum recirculation valves for the steam generator feedwater pumps.  
A flow element is installed on the suction of each of the steam generator feedwater pumps to provide the control signal to open the minimum recirculation valves for the steam generator feedwater pumps.  


Pressure transmitters are located in the main feedwater header to provide the feedwater system pressure to the speed-control system for the steam generator feedwater pump turbines. A flow element with two flow transmitters is located on the inlet to each of the four steam generators to provide signals for the three-element feedwater control system.  
Pressure transmitters are located in the main feedwater header to provide the feedwater system pressure to the speed-control system for the steam generator feedwater pump turbines. A flow element with two flow transmitters is located on the inlet to each of the four steam generators to provide signals for the  
 
three-element feedwater control system.  
 
The total water volume in the condensate and feedwater system is maintained through automatic makeup and rejection of condensate to the condensate storage tank. The system makeup and rejection are controlled by the condenser hotwell
 
level controllers.
 
The system water quality is automatically maintained through the injection of an oxygen control chemical and a pH control chemical into the condensate system. The pH control chemical and oxygen control chemical injection is
 
controlled by pH and the oxygen control chemical residual in the system, which
 
is continuously monitored by the process sampling system.
 
10.4-33 Rev. 27 WOLF CREEK Instrumentation, including pressure indicators, flow indicators, and temperature indicators, required for monitoring the system is provided in the
 
control room.
10.4.8  STEAM GENERATOR BLOWDOWN SYSTEM
 
The steam generator blowdown system (SGBS) helps to maintain the steam
 
generator secondary side water within the chemical specifications prescribed by the NSSS supplier. Heat is recovered from the blowdown and returned to the feedwater system. Blowdown is then either treated to remove impurities before
 
being returned to the condenser, or discharged to the lake.
 
10.4.8.1  Design Bases 10.4.8.1.1  Safety Design Basis
 
Portions of the SGBS are safety-related and are required to function following
 
a DBA and to achieve and maintain the plant in a post accident safe shutdown condition. The following safety design bases have been met:
 
SAFETY DESIGN BASIS ONE - The safety-related portion of the SGBS is protected
 
from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).
SAFETY DESIGN BASIS TWO - The safety-related portion of the SGBS remains
 
functional after an SSE or performs its intended function following a
 
postulated hazard, such as internal missile, or pipe break (GDC-4).
SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).
SAFETY DESIGN BASIS FOUR - The active components of the SGBS are capable of being tested during plant operation. Provisions are made to permit inservice inspection of components at appropriate times specified in the ASME Boiler and


The total water volume in the condensate and feedwater system is maintained through automatic makeup and rejection of condensate to the condensate storage tank. The system makeup and rejection are controlled by the condenser hotwell level controllers.  
Pressure Vessel Code, Section XI.  


The system water quality is automatically maintained through the injection of an oxygen control chemical and a pH control chemical into the condensate system. The pH control chemical and oxygen control chemical injection is controlled by pH and the oxygen control chemical residual in the system, which is continuously monitored by the process sampling system.  
SAFETY DESIGN BASIS FIVE - The SGBS is designed and fabricated to codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power


10.4-33 Rev. 27 WOLF CREEK Instrumentation, including pressure indicators, flow indicators, and temperature indicators, required for monitoring the system is provided in the control room. 10.4.8  STEAM GENERATOR BLOWDOWN SYSTEM The steam generator blowdown system (SGBS) helps to maintain the steam generator secondary side water within the chemical specifications prescribed by the NSSS supplier. Heat is recovered from the blowdown and returned to the feedwater system. Blowdown is then either treated to remove impurities before being returned to the condenser, or discharged to the lake.  
supply and control functions are in accordance with Regulatory Guide 1.32.  


10.4.8.1  Design Bases  10.4.8.1.1  Safety Design Basis Portions of the SGBS are safety-related and are required to function following a DBA and to achieve and maintain the plant in a post accident safe shutdown condition. The following safety design bases have been met:
10.4-34 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SIX - The capability of isolating components or piping of the SGBS is provided. This includes isolation of components to deal with
SAFETY DESIGN BASIS ONE - The safety-related portion of the SGBS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2). SAFETY DESIGN BASIS TWO - The safety-related portion of the SGBS remains functional after an SSE or performs its intended function following a postulated hazard, such as internal missile, or pipe break (GDC-4). SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).
SAFETY DESIGN BASIS FOUR - The active components of the SGBS are capable of being tested during plant operation. Provisions are made to permit inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code, Section XI.


SAFETY DESIGN BASIS FIVE - The SGBS is designed and fabricated to codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32.  
leakage or malfunctions and isolation of nonsafety-related portions of the system. An isolation valve is provided in each main line which automatically closes to isolate the secondary side of the steam generator in the event of a DBA.  


10.4-34 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SIX - The capability of isolating components or piping of the SGBS is provided. This includes isolation of components to deal with leakage or malfunctions and isolation of nonsafety-related portions of the system. An isolation valve is provided in each main line which automatically closes to isolate the secondary side of the steam generator in the event of a DBA.
SAFETY DESIGN BASIS SEVEN - The containment isolation valves for the steam generator drain line are selected, tested, and located in accordance with the requirements of 10 CFR 50, Appendix A, General Design Criteria 54 and 56, and


SAFETY DESIGN BASIS SEVEN - The containment isolation valves for the steam generator drain line are selected, tested, and located in accordance with the requirements of 10 CFR 50, Appendix A, General Design Criteria 54 and 56, and 10 CFR 50, Appendix J, Type C testing.  
10 CFR 50, Appendix J, Type C testing.
 
10.4.8.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The SGBS is designed to ensure that
 
blowdown treatment is compatible with the condensate and feedwater to ensure an effective secondary system water chemistry control program.
 
POWER GENERATION DESIGN BASIS TWO - The SGBS is designed to accommodate flows up to 44,000 pounds per hour (nominally 90 gpm) per steam generator, while
 
returning to the feedwater system a sizable portion of the heat removed from
 
the steam generators.
 
POWER GENERATION DESIGN BASIS THREE - During normal operation without primary-to-secondary leakage, the SGBS is designed to process blowdown to meet the
 
chemical composition limits for release to the environment or for return to the
 
condenser hotwell/condensate storage tank.  


10.4.8.1.2  Power Generation Design Bases  POWER GENERATION DESIGN BASIS ONE - The SGBS is designed to ensure that blowdown treatment is compatible with the condensate and feedwater to ensure an effective secondary system water chemistry control program.
POWER GENERATION DESIGN BASIS TWO - The SGBS is designed to accommodate flows up to 44,000 pounds per hour (nominally 90 gpm) per steam generator, while returning to the feedwater system a sizable portion of the heat removed from the steam generators.
POWER GENERATION DESIGN BASIS THREE - During normal operation without primary-to-secondary leakage, the SGBS is designed to process blowdown to meet the chemical composition limits for release to the environment or for return to the condenser hotwell/condensate storage tank.
POWER GENERATION DESIGN BASIS FOUR - During periods of abnormal operation with a primary-to-secondary steam generator leak, the SGBS maintains the plant effluent within the radiological specification for plant discharge.  
POWER GENERATION DESIGN BASIS FOUR - During periods of abnormal operation with a primary-to-secondary steam generator leak, the SGBS maintains the plant effluent within the radiological specification for plant discharge.  


POWER GENERATION DESIGN BASIS FIVE - Portions of the SGBS use design and fabrication codes consistent with quality group D (augmented) as assigned by Regulatory Guide 1.143 for radioactive waste management systems.  
POWER GENERATION DESIGN BASIS FIVE - Portions of the SGBS use design and fabrication codes consistent with quality group D (augmented) as assigned by Regulatory Guide 1.143 for radioactive waste management systems.  


10.4.8.2  System Description 10.4.8.2.1  General Description The SGBS is shown in Figure 10.4-8. The system consists of a flash tank, a regenerative heat exchanger, a nonregenerative heat exchanger, filters, demineralizers, a surge tank, and discharge and drain pumps.  
10.4.8.2  System Description 10.4.8.2.1  General Description The SGBS is shown in Figure 10.4-8. The system consists of a flash tank, a regenerative heat exchanger, a nonregenerative heat exchanger, filters, demineralizers, a surge tank, and discharge and drain pumps.  
 
10.4-35 Rev. 3 WOLF CREEK The SGBS is designed to control the secondary side water chemistry, in conjunction with the condensate and feedwater chemical addition system and the
 
condensate demineralizer system, to meet water chemistry specifications. The SGBS serves to remove impurities in the blowdown that originate from sources such as primary-to-secondary leakage, main condenser leakage, sodium carry-over from deep-bed condensate demineralizers, and the corrosion and wear of other
 
secondary cycle components and piping.
 
Each of the four steam generators has its own blowdown and sample lines. The total continuous blowdown range of 60-360 gpm is provided to administratively
 
permit blowdown to match the variable and cyclic nature of the sources of
 
contamination.
 
The steam generator blowdown fluid (blowdown) is extracted from the steam generators through a blowdown sparger ring located in the shell side of the
 
steam generator just above the tube sheet, where impurities are expected to accumulate.
 
The blowdown flow rate from each steam generator is controlled manually using throttling valves just upstream of the blowdown flash tank. The flashed vapor
 
from the flash tank is sent to the number five feedwater heater (or to the
 
condenser or atmosphere during startup).
 
The liquid effluent from the flash tank is first cooled in the regenerative heat exchanger (heat recovery medium is a portion of the condensate flow) and
 
then further cooled by the nonregenerative heat exchanger (cooling medium is
 
service water). The fluid may then be filtered and/or demineralized before
 
being returned to the condenser or before being discharged.
The operator has the option of discharging the blowdown to the environment or returning the blowdown to the condenser. Any limitations on discharges from the plant are within the limits defined by the Offsite Dose Calculation Manual (ODCM). Leak detection from the SGBS is provided by visual examination and by the floor drain system described in Section 9.3.3.
 
Section 3.6 provides an evaluation that demonstrates that the pipe routing is physically separated from essential systems to the maximum extent practical.
Protection mechanisms that may be required to mitigate the dynamic effects of
 
piping ruptures are also discussed in Section 3.6.
 
10.4-36 Rev. 18 WOLF CREEK 10.4.8.2.2  Component Description
 
Codes and standards applicable to the SGBS are listed in Tables 3.2-1 and 10.4-
: 9. The SGBS is designed and constructed in accordance with the following quality group requirements:  Steam generator blowdown lines from the steam generators to the outer SGBS isolation valve are quality group B and are
 
seismic Category I. The flash tank, regenerative heat exchanger, and
 
nonregenerative heat exchangers, which contain minimal radioactivity, are located in the turbine building; all other components are located in seismically designed buildings. Components downstream of the outer SGB
 
isolation valve are quality group D (augmented). Design data for the SGBS
 
components are listed in Table 10.4-9.
 
STEAM GENERATOR BLOWDOWN FLASH TANK - The flash tank pressure is maintained between 185 and 135 psia. This causes the high-temperature high-pressure
 
blowdown liquid to be flashed (i.e., reduced in temperature and pressure). The four steam generator blowdown lines enter the flash tank tangentially at
 
equally spaced distances around the tank.
STEAM GENERATOR REGENERATIVE BLOWDOWN HEAT EXCHANGERS - The heat exchanger
 
cools the blowdown from the flash tank. The heat exchanger is of shell and
 
welded tube design. The cooling medium is condensate water.
 
STEAM GENERATOR NONREGENERATIVE HEAT EXCHANGER - The heat exchanger cools the blowdown from the flash tank or the regenerative heat exchanger to 120&deg; F
 
before it flows to the demineralizers. The heat exchanger is of shell and
 
welded tube design. The cooling medium is service water.
 
STEAM GENERATOR BLOWDOWN FILTER - This filter removes particulate matter from the steam generator blowdown fluid before it flows to the demineralizers. This serves to extend the operating life of the demineralizer resins. Unfiltered blowdown is normally discharged to the lake.
STEAM GENERATOR BLOWDOWN MIXED-BED DEMINERALIZERS - Two sets of two parallel, 50-percent capacity, mixed-bed demineralizers normally operated one set at a
 
time are provided in the blowdown treatment train. Conductivity monitors are located downstream of the demineralizers to signal exhaustion of the upstream bed. When the in-service set of demineralizers is exhausted, the set of demineralizers with the fresh resin is placed into service. The exhausted set of demineralizers is then removed from service, the resin replaced and this
 
freshly recharged set of demineralizers is left in standby until the in-service
 
demineralizer set exhausts. Blowdown that is not demineralized is normally discharged to the lake.
 
10.4-37 Rev. 18 WOLF CREEK STEAM GENERATOR BLOWDOWN SURGE TANK - The surge tank collects the blowdown water prior to discharge from the system, and provides the necessary suction
 
head for the discharge pumps.
STEAM GENERATOR BLOWDOWN BYPASS DISCHARGE PIPING - The bypass piping allows for the option to direct blowdown flow to the lake without using the surge tank or the discharge pumps. The piping is connected to the inlet line to the surge tank and reconnected to the blow down discharge line upstream of BMFO0054.
STEAM GENERATOR BLOWDOWN DISCHARGE PUMP - The inline centrifugal pumps are
 
provided to pump the treated blowdown water from the surge tank to the plant
 
discharge, or recycle the blowdown water through the demineralizer train. One
 
pump is normally in service unless bypassed. A second pump serves as a backup.
 
STEAM GENERATOR DRAIN PUMP - Two inline centrifugal pumps are provided to pump
 
the blowdown to the process train or the secondary cycle to drain a steam


10.4-35 Rev. 3 WOLF CREEK The SGBS is designed to control the secondary side water chemistry, in conjunction with the condensate and feedwater chemical addition system and the condensate demineralizer system, to meet water chemistry specifications. The SGBS serves to remove impurities in the blowdown that originate from sources such as primary-to-secondary leakage, main condenser leakage, sodium carry-over from deep-bed condensate demineralizers, and the corrosion and wear of other secondary cycle components and piping.
generator.  
Each of the four steam generators has its own blowdown and sample lines. The total continuous blowdown range of 60-360 gpm is provided to administratively permit blowdown to match the variable and cyclic nature of the sources of contamination.
The steam generator blowdown fluid (blowdown) is extracted from the steam generators through a blowdown sparger ring located in the shell side of the steam generator just above the tube sheet, where impurities are expected to accumulate.
The blowdown flow rate from each steam generator is controlled manually using throttling valves just upstream of the blowdown flash tank. The flashed vapor from the flash tank is sent to the number five feedwater heater (or to the condenser or atmosphere during startup).
The liquid effluent from the flash tank is first cooled in the regenerative heat exchanger (heat recovery medium is a portion of the condensate flow) and then further cooled by the nonregenerative heat exchanger (cooling medium is service water). The fluid may then be filtered and/or demineralized before being returned to the condenser or before being discharged. The operator has the option of discharging the blowdown to the environment or returning the blowdown to the condenser. Any limitations on discharges from the plant are within the limits defined by the Offsite Dose Calculation Manual (ODCM). Leak detection from the SGBS is provided by visual examination and by the floor drain system described in Section 9.3.3.
Section 3.6 provides an evaluation that demonstrates that the pipe routing is physically separated from essential systems to the maximum extent practical. Protection mechanisms that may be required to mitigate the dynamic effects of piping ruptures are also discussed in Section 3.6.  


10.4-36 Rev. 18 WOLF CREEK 10.4.8.2.2  Component Description Codes and standards applicable to the SGBS are listed in Tables 3.2-1 and 10.4-9. The SGBS is designed and constructed in accordance with the following quality group requirements:  Steam generator blowdown lines from the steam generators to the outer SGBS isolation valve are quality group B and are seismic Category I. The flash tank, regenerative heat exchanger, and nonregenerative heat exchangers, which contain minimal radioactivity, are located in the turbine building; all other components are located in seismically designed buildings. Components downstream of the outer SGB isolation valve are quality group D (augmented). Design data for the SGBS components are listed in Table 10.4-9.
BLOWDOWN LINES - Blowdown from each of the four steam generators is conveyed to the SGB flash tank by four 4-inch lines. Each of the lines is anchored at the  
STEAM GENERATOR BLOWDOWN FLASH TANK - The flash tank pressure is maintained between 185 and 135 psia. This causes the high-temperature high-pressure blowdown liquid to be flashed (i.e., reduced in temperature and pressure). The four steam generator blowdown lines enter the flash tank tangentially at equally spaced distances around the tank. STEAM GENERATOR REGENERATIVE BLOWDOWN HEAT EXCHANGERS - The heat exchanger cools the blowdown from the flash tank. The heat exchanger is of shell and welded tube design. The cooling medium is condensate water.
STEAM GENERATOR NONREGENERATIVE HEAT EXCHANGER - The heat exchanger cools the blowdown from the flash tank or the regenerative heat exchanger to 120&deg; F before it flows to the demineralizers. The heat exchanger is of shell and welded tube design. The cooling medium is service water.
STEAM GENERATOR BLOWDOWN FILTER - This filter removes particulate matter from the steam generator blowdown fluid before it flows to the demineralizers. This serves to extend the operating life of the demineralizer resins. Unfiltered blowdown is normally discharged to the lake. STEAM GENERATOR BLOWDOWN MIXED-BED DEMINERALIZERS - Two sets of two parallel, 50-percent capacity, mixed-bed demineralizers normally operated one set at a time are provided in the blowdown treatment train. Conductivity monitors are located downstream of the demineralizers to signal exhaustion of the upstream bed. When the in-service set of demineralizers is exhausted, the set of demineralizers with the fresh resin is placed into service. The exhausted set of demineralizers is then removed from service, the resin replaced and this freshly recharged set of demineralizers is left in standby until the in-service demineralizer set exhausts. Blowdown that is not demineralized is normally discharged to the lake. 


10.4-37 Rev. 18 WOLF CREEK STEAM GENERATOR BLOWDOWN SURGE TANK - The surge tank collects the blowdown water prior to discharge from the system, and provides the necessary suction head for the discharge pumps. STEAM GENERATOR BLOWDOWN BYPASS DISCHARGE PIPING - The bypass piping allows for the option to direct blowdown flow to the lake without using the surge tank or the discharge pumps. The piping is connected to the inlet line to the surge tank and reconnected to the blow down discharge line upstream of BMFO0054. STEAM GENERATOR BLOWDOWN DISCHARGE PUMP - The inline centrifugal pumps are provided to pump the treated blowdown water from the surge tank to the plant discharge, or recycle the blowdown water through the demineralizer train. One pump is normally in service unless bypassed. A second pump serves as a backup.
containment wall and has sufficient flexibility to provide for relative  
STEAM GENERATOR DRAIN PUMP - Two inline centrifugal pumps are provided to pump the blowdown to the process train or the secondary cycle to drain a steam generator.
BLOWDOWN LINES - Blowdown from each of the four steam generators is conveyed to the SGB flash tank by four 4-inch lines. Each of the lines is anchored at the containment wall and has sufficient flexibility to provide for relative movement of the steam generators due to thermal expansion. The blowdown line and associated branch lines between the reactor building penetration and the first torsional restraint, past the blowdown isolation valve (BIV) are designed to meet the "no break zone" criteria, as described in NRC BTP MEB 3-1.


BLOWDOWN ISOLATION VALVES - One BIV is installed in each of the four blowdown lines outside the containment. The BIVs are installed to prevent uncontrolled blowdown from more than one steam generator. Failure of the blowdown isolation valve for an unaffected steam generator after an MSLB results in blowdown from that steam generator to the blowdown flash tank. This steam loss has less effect on the primary system than does the steam lost as a result of other failures discussed in Section 15.1.5. The valves isolate the nonsafety-related portions from the safety-related portions of the system. The valves are air-operated globe valves which fail closed. For emergency closure, either of two safety-related solenoids is deenergized to dump air supplied to the valve actuator. The electrical solenoids are energized from separate Class 1E sources and are tripped upon receipt of a SGBSIS (AFAS) signal. An additional nonsafety-related solenoid is provided which is de-energized to close the BIV upon receipt of a high radiation level signal or other system-related trip signals.
movement of the steam generators due to thermal expansion. The blowdown line
SAMPLE ISOLATION VALVES - Three safety-related sample isolation valves (SIV) are installed in each of the four sample lines. Two are inside the containment (one from each sample point), and one is outside. The SIVs are installed to prevent uncontrolled blow-down from more than one steam generator. The valves isolate the 


10.4-38 Rev. 23 WOLF CREEK nonsafety-related portions from the safety-related portions of the system. The valves are solenoid operated, are energized from separate Class 1E sources, and tripped upon receipt of a SGBSIS (AFAS) signal. An additional nonsafety-related solenoid valve is provided outside the containment which is de-energized to close upon receipt of a high radiation level signal or other system-related trip signal.
and associated branch lines between the reactor building penetration and the first torsional restraint, past the blowdown isolation valve (BIV) are designed to meet the "no break zone" criteria, as described in NRC BTP MEB 3-1.  
INSULATION - Portions of the sample lines associated with the containment penetration and the safety related portions of the drain lines have insulation designed to withstand the effects of a loss-of-coolant accident or other high energy line break. The purpose of the insulation is to mitigate the thermal transfer of heat into the water due to containment heat-up following a LOCA/HELB, and limit the potential build-up of internal pressure in the pipe due to the expansion of the water. The insulation is designed not to lose its insulation capability during and after the event.
10.4.8.2.3 System Operation  During full power operation, the SGBS can be operated in one of several different modes, depending upon the type and level of contamination in the blowdown. The operator determines, based on prior knowledge of secondary cycle water chemistry conditions and radioactivity levels in conjunction with ODCM limitations and state and local discharge permit restrictions, the extent of processing required by the blowdown system.  


NORMAL OPERATION WITH FULL SYSTEM PROCESSING - Normally, the SGBS is operated, utilizing the full processing capability of the system with heat recovery. Figure 10.4-8 shows valve positions aligned to process the blowdown fluid through the demineralizer processing portion of the system and then to the secondary cycle.
BLOWDOWN ISOLATION VALVES - One BIV is installed in each of the four blowdown  
The blowdown flash tank pressure is normally maintained from 185 psia to a minimum of 135 psia (corresponding to No. 5 feedwater heater pressure at approximately 80-percent power) by a backpressure control valve in the flash tank vent line. Depending upon station load, approximately 23 to 30 percent of the blowdown flow will be flashed into vapor. This flow, containing about half of the total blowdown heat energy, is returned to the feedwater system via the No. 5 feedwater heater shell.


The remaining saturated fluid from the flash tank is first cooled by the regenerative heat exchanger to an intermediate temperature ( 190&deg;F) and then further cooled by the nonregenerative heat exchanger to 120&deg;F. Level control valves in each of the processing flow paths (to the condenser, condensate storage tank, and blowdown surge tank) maintain a level in the flash tank that provides an elevation head on the fluid entering the heat exchangers for suppression of further fluid flashing.
lines outside the containment. The BIVs are installed to prevent uncontrolled blowdown from more than one steam generator. Failure of the blowdown isolation valve for an unaffected steam generator after an MSLB results in blowdown from  
Additional heat recovery is attained with the regenerative heat exchanger which uses a portion of the condensate flow (less than 2 percent of VWO flow) for cooling water. This condensate flow is diverted from the condensate system downstream of the condensate 


10.4-39 Rev. 14 WOLF CREEK demineralizers and is returned to the heater drain tank. The outlet temperature from the regenerative heat exchanger is normally maintained at  190F with the temperature control valve provided in the line to the heater drain tank to control the condensate flow through the regenerative heat exchanger. During periods of low blowdown flow rates, a lower regenerative outlet temperature can be obtained. Cooling water for the nonregenerative heat exchanger is service water. A three-way temperature control valve is provided in the bypass line around the nonregenerative heat exchanger to maintain a high service water flow rate through the shell side of the heat exchanger, during periods of low service water temperatures and low blowdown flow rates.
that steam generator to the blowdown flash tank. This steam loss has less
The high service water flow rates are required to minimize particle deposition within the heat exchanger and thereby reduce the fouling tendency of the heat exchanger. Following the flash tank and heat exchangers, the liquid portion of the blowdown is directed through a radiation monitor prior to processing through two filters in parallel and two sets of two parallel 50-percent capacity demineralizers operated in series. In addition, strainers are provided upstream of each filter and downstream of each demineralizer. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam generator tube failure. The processing system is designed to operate continuously provided the resin beds are periodically replaced. The effluent water normally meets the specifications for water purity and radioactivity for return to the condenser hotwell. Resin bed exhaustion is signaled by a high conductivity alarm from either of two conductivity meters; the first is located in the common line downstream of the first set of parallel demineralizers, and the second is located in the common line downstream of the second set of parallel demineralizers. A high conductivity alarm indicates exhaustion of the upstream beds. After replacing the resin in the exhausted beds, the order of flow through the parallel beds in series is reversed.


The processed blowdown can be sent either to the condenser or discharged to the environment. If the blowdown is to be discharged directly to the environment, the fluid is directed into the steam generator blowdown surge tank or to the steam generator blowdown bypass discharge piping. From the surge tank, the fluid is pumped by the discharge pumps to the radwaste building discharge line through a radiation monitor. The surge tank level is controlled by a level valve in the discharge line from the pumps. Level instrumentation is provided on the surge tank to prevent damage to the discharge pumps on loss of level. The steam generator blowdown bypass discharge piping will allow blowdown fluid to be taken off up stream of the surge tank, which will allow the surge tank and the discharge pumps to be bypassed. This will allow the option to use the system pressure to discharge the blowdown fluid to the lake without the discharge pumps or surge tank.   
effect on the primary system than does the steam lost as a result of other


10.4-40 Rev. 23 WOLF CREEK Upon indication of high activity by the radiation monitors, the blowdown discharge valve is closed and the discharge pumps are stopped, automatically terminating discharge, and the blowdown isolation valve in each blowdown line is closed, thereby automatically terminating blowdown. High level in the surge tank terminates blowdown by automatically closing the blowdown isolation valves and the flash tank level control to the blowdown surge tank. In addition, discharge of blowdown to the environment is automatically terminated on a low dilution water flow signal. A flow path can be established to allow the fluid in the surge tank to be reprocessed through the processing portion of the blowdown system.
failures discussed in Section 15.1.5. The valves isolate the nonsafety-related portions from the safety-related portions of the system. The valves are air-operated globe valves which fail closed. For emergency closure, either of two


During periods of primary-to-secondary leakage, the blowdown fluid is purified by the processing portion of the blowdown system to limit any radioactive contamination of the secondary system.
safety-related solenoids is deenergized to dump air supplied to the valve
OPERATION WITHOUT BLOWDOWN PROCESSING - As permitted by the type and level of the contaminants in the blowdown fluid, the operator can determine the extent of system processing required to meet the chemistry requirements for either discharge or return to the condenser. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam generator tube failure, and alarms only when the operator should be made aware that processing may be required. A bypass flow path can be established from a point downstream of the heat exchangers to either the condenser or the surge tank for periods of operation where processing within the blowdown system is not desired.
During normal operating conditions with no significant radioactive contaminants in the system and where the chemistry of the blowdown fluid meets the ODCM limitations for release restrictions, the processing portion of the system can be bypassed and the fluid can be discharged. When discharging, the fluid is directed to the surge tank and through the radiation monitor to the environment.


Also, during periods of normal plant operation with the condensate demineralizers in service and with insignificant radioactive contaminants in the system, the processing portion of the blowdown system (i.e. filters and demineralizers) can be bypassed and the fluid can be returned directly to the condenser, provided that the feedwater remains within the chemistry specifications. OPERATION WITH REGENERATIVE HEAT EXCHANGER OUT OF SERVICE - During periods of operation when the regenerative heat exchanger is out of service, a bypass line is provided to permit continued oper- 
actuator. The electrical solenoids are energized from separate Class 1E


10.4-41 Rev. 23 WOLF CREEK ation. The maximum blowdown rate is then limited by the nonregenerative heat exchanger's capacity for reducing the fluid temperature to less than 120F. System operation downstream of the heat exchangers continues to be based on the processing requirements to maintain the chemistry specifications.
sources and are tripped upon receipt of a SGBSIS (AFAS) signal.
OPERATION WITH THE NONREGENERATIVE HEAT EXCHANGER OUT OF SERVICE - In this mode, three-way temperature control valve in the bypass line around the nonregenerative heat exchangers is manually maintained open. The temperature control valve which maintains blowdown fluid outlet temperature from the regenerative heat exchanger is set for approximately 150&#xf8;F. This temperature setting may require that the demineralizers be bypassed in order to prolong resin life and preclude the possibility of eluting the radioactivity that has been adsorbed by the resin. With the flash tank venting to the condenser, the total steam generator blowdown then is limited to about 50,000 lbs/hr.
An additional nonsafety-related solenoid is provided which is de-energized to  
USE OF THE STEAM GENERATOR BLOWDOWN DEMINERALIZERS BY THE SECONDARY LIQUID WASTE (SLWS) - As a backup to the SLWS demineralizer, interties have been provided between the SLWS and the steam generator blowdown system to allow the processing of SLWS low TDS waste by either of the two sets of two parallel steam generator blowdown demineralizers. The system is designed so that blowdown can be processed by the set of demineralizers not being used for processing the low TDS waste. SAMPLING - The blowdown system sample points are arranged to provide selectively extracted samples from each of the steam generator drums, each individual blowdown line, and the surge tank. The nuclear sample connection from the blowdown lines is located as close to the steam generator as possible to minimize transit time from the steam generator water mass to the point of use and to ensure maximum sample quality.


The process sampling system is normally used to continuously determine the chemical composition of the liquid in each of the steam generators. The process sample extraction points are located in the turbine building. 
close the BIV upon receipt of a high radiation level signal or other system-


10.4-42 Rev. 14 WOLF CREEK A continuous inline radioactivity monitor is provided to detect the presence of activity which would indicate a primary-to-secondary leak. Anytime the unprocessed blowdown activity level exceeds 1.0 x 10-5  Ci/gm (excluding tritium), periodic samples are taken at the nuclear sampling station and analyzed in the hot lab to ascertain the affected steam generator and to monitor any increase in primary-to-secondary leakage. The nuclear sampling system is capable of receiving intermittent or continuous samples from either each of the steam generator drums or each of the individual blowdown lines. The chemical composition is continuously monitored by the process sampling system.  
related trip signals.  


STARTUP AND SHUTDOWN OPERATION - The startup and shutdown operations of the blowdown system are the same as for normal operation, except that the secondary cycle is not able to receive the flash tank vent fluid. When feedwater is not flowing through the No. 5 feedwater heater, the flash tank vent is directed to the condenser. If condenser vacuum is not being maintained, the vent is directed to the atmosphere. In the event that the condensate pumps (which would provide condensate cooling flow for the regenerative heat exchanger) or the heater drain tank are unavailable, it is possible for the liquid blowdown to be returned to the environment or the condensate storage tank rather than the condenser. Under these conditions, the total steam generator blowdown flow is limited by the capability of the nonregenerative heat exchanger to maintain cooled blowdown below the required limits. When demineralization or discharge to the environment is required, a 120&deg;F limit is maintained. If the blowdown is being directed to the condensate storage tank, the blowdown is cooled to a maximum of 120F. During shutdown with the steam generator depressurized, the steam generator drain pumps may be employed to drain and dispose of or process steam generator water. A connection is available to the suction side of the condensate pumps for processing of the liquid through the condensate demineralizers and bypassing the condenser. Wet layup capabilities are provided to protect the steam generators from corrosive attack during inactive periods. This is achieved by ensuring the exclusion of oxygen and controlling the pH of the water mass inside the steam generators. EMERGENCY OPERATION - The isolation valves of the blowdown and sample systems are closed automatically by the signal from system radiation monitors, by the condenser air removal exhaust monitor, and/or by the SGBSIS (AFAS) signal. All of these valves are capable of being remotely closed from the control room. 
SAMPLE ISOLATION VALVES - Three safety-related sample isolation valves (SIV) are installed in each of the four sample lines. Two are inside the containment (one from each sample point), and one is outside. The SIVs are installed to


10.4-43 Rev. 10 WOLF CREEK Following a radiation monitor alarm, or start of the auxiliary feedwater system, the sample system isolation valves may be reopened from the control room. This capability permits identification, and subsequent isolation, of the steam generator responsible for fission product transfer from the primary to the secondary system. After reset of the AFAS, the blowdown system isolation valves may be reopened from the control room. 
prevent uncontrolled blow-down from more than one steam generator. The valves  


10.4.8.3  Radioactive Releases In the event radioactivity is transmitted to the secondary side of the steam generator, it will show up in the blowdown fluid. For conditions of primary-to-secondary leakage, all blowdown fluid is processed and returned to the main condenser. Any discharge of radioactive fluid from this system is considered unlikely.
isolate the  
If the blowdown fluid is being discharged to the environment and the activity level in the discharged fluid approaches the limit defined by the ODCM, the radiation monitor in the discharge line alarms and automatically terminates discharge and blowdown. In addition, blowdown discharge to the environment is automatically terminated on a low dilution water flow signal.


When discharging to the environment, the discharge temperature is between 60-120&deg;F, exit pressure is 35-150 psig, and the flow rate is a maximum of 270 gpm. The operating criteria for the secondary side blowdown system are dictated by the need for limiting the secondary side build-up of dissolved solids. The equilibrium radioactive concentrations based on a assumed primary-to-secondary leakrate are given in Chapter 11.0 for the steam generators. 10.4.8.4  Safety Evaluation  Safety evaluations are numbered to correspond to the safety design bases in Section 10.4.8.1. SAFETY EVALUATION ONE - The safety-related portions of the SGBS are located in the reactor and auxiliary buildings. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.
10.4-38 Rev. 23 WOLF CREEK nonsafety-related portions from the safety-related portions of the system. The valves are solenoid operated, are energized from separate Class 1E sources, and  


10.4-44 Rev. 26 WOLF CREEK SAFETY EVALUATION TWO - The safety-related portions of the SGBS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) and (N) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.
tripped upon receipt of a SGBSIS (AFAS) signal.
An additional nonsafety-related solenoid valve is provided outside the containment which is de-energized to close upon receipt of a high radiation


SAFETY EVALUATION THREE - The component and system description for the SGBS shows that complete redundancy is provided and, as indicated by Table 10.4-10, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.  
level signal or other system-related trip signal.  


SAFETY EVALUATION FOUR - Periodic inservice functional testing is done in accordance with Section 10.4.8.5. Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI requirements that are appropriate for the SGBS.
INSULATION - Portions of the sample lines associated with the containment penetration and the safety related portions of the drain lines have insulation


SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.4-9 shows that the components meet the design and fabrication codes given in Section 3.2. All the power supplies and control function necessary for the safety functions of the system are Class 1E, as described in Chapters 7.0 and 8.0. SAFETY EVALUATION SIX - Section 10.4.8.2 describes provisions made to identify and isolate leakage or malfunction and to isolate the steam generator water inventory from the nonsafety-related portions of the system.
designed to withstand the effects of a loss-of-coolant accident or other high
SAFETY EVALUATION SEVEN - Sections 6.2.4 and 6.2.6 provide the safety evaluation for the system containment isolation arrangement and testability for the steam generator drain line penetration.


10.4.8.5  Tests and Inspections The performance and structural and leaktight integrity of all system components is demonstrated by continuous operation. The SGBS is testable through the full operational sequence that brings the system into operation for reactor shutdown and for DBAs, including operation of applicable portions of the protection system and transfer between normal and standby power.
energy line break. The purpose of the insulation is to mitigate the thermal


10.4-45 Rev. 19 WOLF CREEK The safety-related components are located to permit preservice and inservice inspections.
transfer of heat into the water due to containment heat-up following a LOCA/HELB, and limit the potential build-up of internal pressure in the pipe due to the expansion of the water. The insulation is designed not to lose its
10.4.8.6  Instrumentation Applications  The SGBS instrumentation, as described in Table 10.4-11, is designed to facilitate automatic operation, remote control, and continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the protection system.
The process radiation monitors provided downstream of the steam generator blowdown flash tank and in the plant discharge line are discussed in Section 11.5. 10.4.9  AUXILIARY FEEDWATER SYSTEM


The auxiliary feedwater system (AFS) is a reliable source of water for the steam generators. The AFS, in conjunction with safety valves in the main steam lines, is a safety-related system, the function of which is to remove thermal energy from the reactor coolant system by releasing secondary steam to the atmosphere. The AFS also provides emergency water following a secondary side line rupture. Removal of heat in this manner prevents the reactor coolant pressure from increasing and causing release of reactor coolant through the pressurizer relief and/or safety valves.
insulation capability during and after the event.  
The auxiliary feedwater system may also be used following a reactor shutdown in conjunction with the condenser dump valves or atmospheric relief valves, to cool the reactor coolant system. 10.4.9.1  Design Bases  10.4.9.1.1  Safety Design Bases SAFETY DESIGN BASIS ONE - The AFS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).  


SAFETY DESIGN BASIS TWO - The AFS is designed to remain functional after an SSE or to perform its intended function following a postulated hazard, such as internal missile, or pipe break (GDC-4).  
10.4.8.2.3  System Operation During full power operation, the SGBS can be operated in one of several


10.4-46 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS THREE - The safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power. The system requirements may be met with a complete loss of ac power (GDC-34). SAFETY DESIGN BASIS FOUR - The AFS is designed so that the active components are capable of being tested during plant operation. Provisions are made to allow for inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code, Section XI. SAFETY DESIGN BASIS FIVE - The AFS is designed and fabricated consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32. SAFETY DESIGN BASIS SIX - The AFS, in conjunction with the condensate storage tank (classified as special scope) or essential service water system, provides feedwater to maintain sufficient steam generator level to ensure heat removal from the reactor coolant system in order to achieve a safe shutdown following a main feedwater line break, a main steamline break, or an abnormal plant situation requiring shutdown. The auxiliary feedwater system is capable of delivering full flow when required, after detection of any accident requiring auxiliary feedwater (refer to Chapter 15.0).
different modes, depending upon the type and level of contamination in the  
SAFETY DESIGN BASIS SEVEN - The capability to isolate components or piping is provided, if required, so that the AFS safety function is not compromised.
This includes isolation of components to deal with leakage or malfunctions and to isolate portions of the system that may be directing flow to a broken secondary side loop. SAFETY DESIGN BASIS EIGHT - The AFS has the capacity to be operated locally as an alternate, redundant means of feedwater control, in the unlikely event that the control room must be evacuated. 10.4.9.1.2  Power Generation Design Bases The AFS has no power generation design bases. The condensate and feedwater system is designed to provide a continuous feedwater supply to the steam generators during startup normal plant operation, and shutdown. Refer to Section 10.4.7. 


10.4-47 Rev. 16 WOLF CREEK 10.4.9.2  System Description  10.4.9.2.1  General Description  The system consists of two motor-driven pumps, one steam turbine-driven pump, and associate piping, valves, instruments, and controls, as shown on Figure 10.4-9 and described in Table 10.4-12. Figure 10.4-10 shows the piping and instrumentation for the steam turbine. Each motor-driven auxiliary feedwater pump will supply 100 percent of the feedwater flow required for removal of decay heat from the reactor. The turbine-driven pump is sized to supply up to twice the capacity of a motor-driven pump. This capacity is sufficient to remove decay heat and to provide adequate feedwater for cooldown of the reactor coolant system at 50&#xba;F/hr within 1 hour of a reactor trip from full power.
blowdown. The operator determines, based on prior knowledge of secondary cycle


Normal flow is from the condensate storage tank (CST) to the auxiliary feedwater pumps. Two redundant safety-related back-up sources of water from the essential service water system (ESWS) are provided for the pumps. For a more detailed description of the automatic sequence of events, refer to Section 10.4.9.2.3.  
water chemistry conditions and radioactivity levels in conjunction with ODCM limitations and state and local discharge permit restrictions, the extent of processing required by the blowdown system.  


Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the safety grade water source.
NORMAL OPERATION WITH FULL SYSTEM PROCESSING - Normally, the SGBS is operated, utilizing the full processing capability of the system with heat recovery.
Figure 10.4-8 shows valve positions aligned to process the blowdown fluid


The condensate storage tank has sufficient capacity to allow the plant to remain at hot standby for 4 hours and then cool down the primary system at an average rate of 50&deg;F per hour to a temperature of 350&deg;F. Initially, sensible and decay heat is removed from the reactor coolant system to reduce the temperature from a full-power operation average temperature of 588&deg;F to a nominal hot standby temperature of 500&deg;F. Subsequently, the reactor is brought down to 350&deg;F at 50&deg;F/hr. Refer to Section 9.2.6 for a description of the condensate storage system.
through the demineralizer processing portion of the system and then to the  


The non-safety auxiliary feedwater pump (NSAFP), installed in the Condensate Storage and Transfer System (CSTS), functions to provide an alternate source of cooling water to the steam generators through the Auxiliary Feedwater system as shown in Figure 10.4-9. The NSAFP is powered from the Station Blackout Diesel Generators (SBO DGs) as described in section 8.3.1.1.1.3. The SBO DGs and NSAFP will be manually aligned as deemed necessary. Hose connections are available for connection of a portable auxiliary feedwater pump in the event of an extended loss of all AC power. These connections support implementation of beyond-design-basis external event Phase 2 coping strategies to maintain or restore core cooling as described in Appendix 3D.  
secondary cycle.  


In order to remove decay heat by the steam generators, auxiliary feedwater must be supplied to the steam generators in the event that the normal source of feedwater is lost. The minimum required flow rate is 470 gpm for decay heat removal during plant normal cooldown. The single active failure for Chapter 15 events that take credit for auxiliary feedwater flow for decay heat removal assumes one of the two motor-driven auxiliary feedwater pumps is operable. The overall minimum auxiliary feedwater flow rate is 563 gpm to fulfill the acceptance criteria for the feedline break analysis in Section 15.2.8.
The blowdown flash tank pressure is normally maintained from 185 psia to a minimum of 135 psia (corresponding to No. 5 feedwater heater pressure at


Provisions are incorporated in the AFS design to allow for periodic operation to demonstrate performance and structural and leaktight integrity. Leak detection is provided by visual examination and in the floor drain system described in Section 9.3.3.
approximately 80-percent power) by a backpressure control valve in the flash
10.4-48 Rev. 30 WOLF CREEK 10.4.9.2.2  Component Description Codes and standards applicable to the AFS are listed in Tables 3.2-1 and 10.4-12. The AFS is designed and constructed in accordance with quality groups B and C and seismic Category I requirements.
MOTOR-DRIVEN PUMPS - Two auxiliary feedwater pumps are driven by ac-powered electric motors supplied with power from independent Class 1E switchgear busses. Each horizontal centrifugal pump takes suction from the condensate storage tank, or alternatively, from the ESWS. Pump design capacity includes continuous minimum flow recirculation, which is controlled by restriction orifices.
TURBINE-DRIVEN PUMP - A turbine-driven pump provides system redundancy of auxiliary feedwater supply and diversity of motive pumping power. The pump is a horizontal centrifugal unit. Pump bearings are cooled by the pumped fluid. Pump design capacity includes continuous minimum flow recirculation. Power for all controls, valve operators, and other support systems is independent of ac power sources.
Steam supply piping to the turbine driver is taken from two of the four main steam lines between the containment penetrations and the main steam isolation valves. Each of the steam supply lines to the turbine is equipped with a locked-open gate valve, normally closed air-operated globe valve with air-operated globe bypass to keep the line warm, and two nonreturn valves. Air-operated globe valves are equipped with dc-powered solenoid valves. These steam supply lines join to form a header which leads to the turbine through a normally closed, dc motor-operated mechanical trip and throttle valve. The main steam system is described in Section 10.3. The steam lines contain provisions to prevent the accumulation of condensate.
The turbine driver is designed to operate with steam inlet pressures ranging from 92 to 1,290 psia. Exhaust steam from the turbine driver is vented to the atmosphere above the auxiliary boiler building roof. Refer to Safety  Evaluation Two for a discussion of the design provisions for the exhaust line.
PIPING AND VALVES - All piping in the AFS is seamless carbon steel. Welded joints are used throughout the system, except for flanged connections at the pumps.
The piping from the ESWS to the suction of each of the auxiliary feedwater pumps is equipped with a motor-operated butterfly valve, an isolation valve, and a nonreturn valve. Each line from the condensate storage tank is equipped with a motor-operated gate 


10.4-49 Rev. 11 WOLF CREEK valve and a nonreturn valve. Each motor-driven pump discharges through a nonreturn valve and a locked-open isolation valve to feed two steam generators through individual sets of a locked open isolation valve, a normally open, motor-operated control valve, a check valve followed by a flow restriction orifice, and a locked-open globe valve. The turbine-driven pump discharges through a nonreturn valve, a locked-open gate valve to each of the four steam generators through individual sets of a locked-open isolation valve, a normally open air-operated control valve, followed by a nonreturn valve, a flow restriction orifice, and a locked-open globe valve.
tank vent line. Depending upon station load, approximately 23 to 30 percent of  
The turbine-driven pump discharge control valves are positionable, air operated valves. At each connection to the four main feedwater lines, the auxiliary feedwater lines are equipped with check valves. The system design precludes the occurrence of water hammer in the main feedwater inlet to the steam generators. For a description of prevention of water hammer, refer to Section 10.4.7.2.1.
TANKS - Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the safety grade water source. 10.4.9.2.3  System Operation  NORMAL PLANT OPERATION - The AFS is not required during normal power generation. The pumps are placed in standby, lined up with the condensate storage tank, and are available if needed. EMERGENCY OPERATION - In addition to remote manual-actuation capabilities, the AFS is aligned to be placed into service automatically in the event of an emergency. See section 7.3.6.1.1 for a description of this operation.
The common water supply header from the condensate storage tank contains a locked-open, 12-inch, butterfly isolation valve. Correct valve position is verified by periodic surveillance. In the case of a failure of the water supply from the condensate storage tank, the normally closed, motor-operated butterfly valves from the ESWS are automatically opened on low suction header pressure. Valve opening time and pump start time are coordinated to ensure adequate suction pressure with either onsite or offsite power available.
If a motor-driven pump supplying two of the three intact steam generators fails to function, the turbine-driven pump automatically starts when a low-low level is reached in two of the four steam generators. During all of the above emergency conditions, the normally open control valves are remote manually operated.


During all of the above emergency conditions, the motor-driven pump normally open control valves are automatically operated to limit runout flow under all secondary side pressure conditions. This is required to prevent pump suction cavitation at high flow rates. The turbine-driven pump design includes a lower NPSH requirement. Therefore, the turbine-driven pump control valves are remote manually operated.  
the blowdown flow will be flashed into vapor. This flow, containing about half of the total blowdown heat energy, is returned to the feedwater system via the No. 5 feedwater heater shell.  


10.4-50 Rev. 25 WOLF CREEK Low pump discharge pressure alarms assists alerting in the operator to a secondary side break. The operator then determines which Steam Generator is faulted, and closes the appropriate discharge control valves. For a postulated unisolable double-ended secondary system pipe rupture, refer to Chapter 15.0 for further information on the required operator actions and times assumed in the applicable accident analysis.
The remaining saturated fluid from the flash tank is first cooled by the regenerative heat exchanger to an intermediate temperature ( 190&deg;F) and then further cooled by the nonregenerative heat exchanger to 120&deg;F. Level control valves in each of the processing flow paths (to the condenser, condensate


10.4.9.3  Safety Evaluation Safety evaluations are numbered to correspond to the safety design bases in Section 10.4.9.1.1.
storage tank, and blowdown surge tank) maintain a level in the flash tank that


SAFETY EVALUATION ONE - The AFS is located in the auxiliary building, except for the Turbine Driven Auxiliary Feedwater Pump exhaust pipe and the section of pump recirculation piping mentioned in the note below. This building is designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of the auxiliary building.  (See the discussion in Safety Evaluation Two, pertaining to the exhaust steam from the turbine driver during a SSE.)
provides an elevation head on the fluid entering the heat exchangers for suppression of further fluid flashing.  
NOTE: To avoid pump damage due to overheating while operating with no delivered flow, the Motor Driven Auxiliary Feedwater Pumps (MDAFWPs) and the Turbine Driven Auxiliary Feedwater Pump (TDAFWP) require minimum flows of 75 gpm and 120 gpm respectively. To satisfy this requirement, each pump has a recirculation line that joins to common header ALO45DBC-3" and returns to the condensate storage tank (CST). The common recirculation line transitions from safety-related to non-safety related/non-seismic at the Auxiliary Feedwater System to CST pipe chase, becoming line ALO46DBC-3". The CST pipe chase and the CST are not seismically qualified.
If a hazard (i.e. tornadoes, floods, missiles, pipe breaks, fires, and seismic events) resulted in the non-safety related portion of the recirculation header becoming crimped such that recirculation flow was restricted in conjunction with an AFS actuation signal, the potential for pump damage could exist.
To eliminate that potential, an alternate flow path has been designed such that even in the event of a recirculation line obstruction, sufficient cooling flow will be available.
The AFW system is designed to remain functional after a tornado missile impact. As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the driver is routed from the auxiliary building wall through the auxiliary boiler building. The portion of the turbine driver exhaust stack that exits the auxiliary building has been analyzed and is not expected to crimp and inhibit the ability of the TDAFWP to deliver design flow rates. The impact from a credible missile will cause the exhaust line to sever by any of the postulated tornado missile scenarios thus not inhibiting the function of the exhaust line.
SAFETY EVALUATION TWO - The AFS is designed to remain functional after a SSE.
Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained. For a more complete description of motor qualification, refer to Sections 3.10(B) and 3.11(B).  


10.4-51 Rev. 30 WOLF CREEK  As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the turbine driver is routed from the auxiliary building wall through the auxiliary boiler building, which is designed to UBC seismic requirements and is not expected to fail during a seismic event. If the auxiliary boiler building were to catastrophically fail and the exhaust line were sheared off completely, the AFP turbine would operate properly. Even if the exhaust line were to crimp significantly, the AFP turbine driven pump would still deliver design flow rates. The back pressure on the turbine may be increased significantly before the required flow rates are not available. The TDAFWP is capable of delivering design flow even with a local constriction of 50 percent of the free area of the exhaust line. This type of failure is not considered to be credible. However, the exhaust line and its support are re-classified as special scope, II/I, to assure they will not be degraded and thus affect the operation of the Auxiliary Feedwater Pump Turbine.
Additional heat recovery is attained with the regenerative heat exchanger which  


Breaks in seismic Category I piping are not postulated during a seismic event. Thus an MSLB or MFLB inside containment or in the steam tunnel are not postulated following a seismic event and the design of the exhaust line does not enter into the evaluation of these breaks.
uses a portion of the condensate flow (less than 2 percent of VWO flow) for


For a seismically induced MSLB in the turbine building, various single failures can be postulated, none of which result in adverse conditions even if the AFP turbine is inoperable. If an MSLIV fails to close, one steam generator blows down; however, two motor driven AFW pumps are available to feed three intact steam generators. If one motor driven pump train fails for any reason, the other motor driven pump feeds two steam generators as required. In this case, the break has been isolated by the MSLIV, and all four steam generators are intact.
cooling water. This condensate flow is diverted from the condensate system downstream of the condensate 


SAFETY EVALUATION THREE - Complete redundancy is provided and, as indicated by Table 10.4-13, no single failure compromises the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.  
10.4-39 Rev. 14 WOLF CREEK demineralizers and is returned to the heater drain tank. The outlet temperature from the regenerative heat exchanger is normally maintained at  190 F with the temperature control valve provided in the line to the heater drain tank to control the condensate flow through the regenerative heat exchanger. During periods of low blowdown flow rates, a lower regenerative outlet temperature can be obtained.
Cooling water for the nonregenerative heat exchanger is service water. A


The turbine-driven pump is energized by steam drawn from two main steam lines between the containment penetrations and the main steam isolation valves. All valves and controls necessary for the function of the turbine-driven pump are energized by the Class 1E dc power supplies. Turbine bearing lube oil is circulated by an integral shaft-driven pump. Turbine and pump bearing oil is cooled by pumped auxiliary feedwater.
three-way temperature control valve is provided in the bypass line around the  
SAFETY EVALUATION FOUR - The AFS is initially tested with the program given in Chapter 14.0. Periodic operational testing is done in accordance with Section 10.4.9.4.


Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI requirements that are appropriate for the AFS. SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to this system and supporting systems. Table 10.4-12 shows that the components meet the design and fabrication codes given in Section 3.2. All the power supplies and control functions necessary for safe function of the AFS are Class 1E, as described in Chapters 7.0 and 8.0.
nonregenerative heat exchanger to maintain a high service water flow rate


10.4-52 Rev. 30 WOLF CREEK  SAFETY EVALUATION SIX - The AFS provides a means of pumping sufficient feedwater to prevent damage to the reactor following a main feedwater line break inside the containment, or a main steamline break incident, as well as to cool down the reactor coolant system at a rate of 50F per hour to a temperature of 350F, at which point the residual heat removal system can operate. Pump capacities, as shown in Table 10.4-12, and start times are such that these objectives are met. Restriction orifices located in the pump  discharge lines and automatic flow control valves for the motor-driven pumps limit the flow to the broken loop so that adequate cooldown flow (470 gpm) can be provided to the other steam generators for removal of reactor decay heat and so that containment design pressure is not exceeded. Pump discharge head is sufficient to establish the minimum necessary flowrate against a steam generator pressure corresponding to the lowest pressure setpoint of the main steam safety valves. The maximum time period required to start the electric motors and the steam turbine which drive the auxiliary feedwater pumps is chosen so that sufficient flowrates are established within the required time for primary system protection. Refer to Chapter 15.0.  
through the shell side of the heat exchanger, during periods of low service water temperatures and low blowdown flow rates.  


SAFETY EVALUATION SEVEN - As discussed in Sections 10.4.9.2 and 10.4.9.5 and Chapter 15.0, adequate instrumentation and control capability is provided to permit the plant operator to quickly identify and isolate the auxiliary feedwater flow to a broken secondary side loop. Isolation from nonsafety-related portions of the system, including the condensate storage tank, is provided as described in Section 10.4.9.2. SAFETY EVALUATION EIGHT - The AFS can be controlled from either the main control room or the auxiliary shutdown panel. Refer to Section 7.4 for the control description.
The high service water flow rates are required to minimize particle deposition within the heat exchanger and thereby reduce the fouling tendency of the heat
10.4.9.4  Tests and Inspections Preoperational testing is described in Chapter 14.0. The performance and structural and leaktight integrity of system components is demonstrated by periodic operation. The AFS is testable through the full operational sequence that brings the system into operation for reactor shutdown and for DBA, including operation of applicable portions of the protection system and the transfer between normal and standby power sources. The safety-related components, i.e., pumps, valves, piping, and turbine, are designed and located to permit preservice and inservice inspection.


10.4.9.5  Instrumentation Applications The AFS instrumentation is designed to facilitate automatic operation and remote control of the system and to provide continuous indication of system parameters.
exchanger.
Redundant condensate storage tank level indication and alarms are provided in the control room. The backup indication and alarms use auxiliary feedwater pump suction pressure by converting it to available tank level. Both alarms provide at least 20 minutes for operator action (e.g., refill the tank),
Following the flash tank and heat exchangers, the liquid portion of the  
assuming that the largest capacity auxiliary feedwater pump is operating.
10.4-53 Rev. 30 WOLF CREEK  Pressure transmitters are provided in the discharge and suction lines of the auxiliary feedwater pumps. Auxiliary feedwater flow to each steam generator is indicated by flow indicators provided in the control room. If the condensate supply from the storage tank fails, the resulting reduction of pressure at the pump suction is indicated in the control room. Flow transmitters and control valves with remote control stations are provided on the auxiliary feedwater lines to each steam generator to indicate and allow control of flow at the auxiliary shutdown panel and in the control room. Flow controllers for the motor-driven pump control valves position the valves to 


limit the flow to a preset value throughout the full range of downstream operating pressures.
blowdown is directed through a radiation monitor prior to processing through
Position indication in the control room is provided on the ESFAS status panel for the manual isolation valve in the auxiliary feedwater pump suction header from the condensate storage tank. A flow element and indicator is provided in each auxiliary feedwater pump minimum recirculation line to facilitate periodic performance testing.


Table 10.4-14 summarizes AFS controls, alarms, indication of status, etc. 10.4.10  SECONDARY LIQUID WASTE SYSTEM
two filters in parallel and two sets of two parallel 50-percent capacity


The function of the secondary liquid waste system (SLWS) is to process condensate demineralizer regeneration wastes and potentially radioactive liquid waste collected in the turbine building. Processed liquid waste may be reused in the plant or discharged to the environment.
demineralizers operated in series. In addition, strainers are provided upstream of each filter and downstream of each demineralizer. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam


10.4.10.1  Design Bases  10.4.10.1.1  Safety Design Bases The SLWS is not a safety-related system, and its failure does not compromise any safety-related system or prevent a safe shutdown of the reactor.
generator tube failure. The processing system is designed to operate
10.4.10.1.2  Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - During normal plant operation, the SLWS is utilized to the extent required to meet chemical composition limits for release to the environment or for recyle of processed fluids back to the condenser. POWER GENERATION DESIGN BASIS TWO - The SLWS processes recyclable turbine building waste during normal operation with the radioactivity levels identified in Appendix 11.1A.


POWER GENERATION DESIGN BASIS THREE - During abnormal operation, the SLWS has provisions to receive from nonradioactive turbine building sumps liquids that may be radioactively contaminated. This condition could occur if, for example, condensation from the turbine building air coolers contained radioactive contamination or if during maintenance a major component's normal drainage path was not available.  
continuously provided the resin beds are periodically replaced. The effluent
 
water normally meets the specifications for water purity and radioactivity for return to the condenser hotwell. Resin bed exhaustion is signaled by a high conductivity alarm from either of two conductivity meters; the first is located
 
in the common line downstream of the first set of parallel demineralizers, and the second is located in the common line downstream of the second set of
 
parallel demineralizers. A high conductivity alarm indicates exhaustion of the upstream beds. After replacing the resin in the exhausted beds, the order of flow through the parallel beds in series is reversed.
 
The processed blowdown can be sent either to the condenser or discharged to the
 
environment. If the blowdown is to be discharged directly to the environment, the fluid is directed into the steam generator blowdown surge tank or to the steam generator blowdown bypass discharge piping. From the surge tank, the fluid is pumped by the discharge pumps to the radwaste building discharge line through a radiation monitor. The surge tank level is controlled by a level
 
valve in the discharge line from the pumps. Level instrumentation is provided on the surge tank to prevent damage to the discharge pumps on loss of level.
The steam generator blowdown bypass discharge piping will allow blowdown fluid to be taken off up stream of the surge tank, which will allow the surge tank and the discharge pumps to be bypassed. This will allow the option to use the system pressure to discharge the blowdown fluid to the lake without the discharge pumps or surge tank. 
 
10.4-40 Rev. 23 WOLF CREEK Upon indication of high activity by the radiation monitors, the blowdown discharge valve is closed and the discharge pumps are stopped, automatically terminating discharge, and the blowdown isolation valve in each blowdown line is closed, thereby automatically terminating blowdown. High level in the surge tank terminates blowdown by automatically closing the blowdown isolation valves and the flash tank level control to the blowdown surge tank. In addition, discharge of blowdown to the environment is automatically terminated on a low
 
dilution water flow signal. A flow path can be established to allow the fluid in the surge tank to be reprocessed through the processing portion of the blowdown system.
 
During periods of primary-to-secondary leakage, the blowdown fluid is purified
 
by the processing portion of the blowdown system to limit any radioactive contamination of the secondary system.
 
OPERATION WITHOUT BLOWDOWN PROCESSING - As permitted by the type and level of
 
the contaminants in the blowdown fluid, the operator can determine the extent of system processing required to meet the chemistry requirements for either discharge or return to the condenser. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam generator tube
 
failure, and alarms only when the operator should be made aware that processing
 
may be required. A bypass flow path can be established from a point downstream
 
of the heat exchangers to either the condenser or the surge tank for periods of operation where processing within the blowdown system is not desired.
 
During normal operating conditions with no significant radioactive contaminants
 
in the system and where the chemistry of the blowdown fluid meets the ODCM
 
limitations for release restrictions, the processing portion of the system can be bypassed and the fluid can be discharged. When discharging, the fluid is directed to the surge tank and through the radiation monitor to the environment.
 
Also, during periods of normal plant operation with the condensate demineralizers in service and with insignificant radioactive contaminants in the system, the processing portion of the blowdown system (i.e. filters and
 
demineralizers) can be bypassed and the fluid can be returned directly to the
 
condenser, provided that the feedwater remains within the chemistry
 
specifications.
OPERATION WITH REGENERATIVE HEAT EXCHANGER OUT OF SERVICE - During periods of
 
operation when the regenerative heat exchanger is out of service, a bypass line
 
is provided to permit continued oper- 
 
10.4-41 Rev. 23 WOLF CREEK ation. The maximum blowdown rate is then limited by the nonregenerative heat exchanger's capacity for reducing the fluid temperature to less than 120 F. System operation downstream of the heat exchangers continues to be based on the processing requirements to maintain the chemistry specifications.
 
OPERATION WITH THE NONREGENERATIVE HEAT EXCHANGER OUT OF SERVICE - In this
 
mode, three-way temperature control valve in the bypass line around the nonregenerative heat exchangers is manually maintained open. The temperature control valve which maintains blowdown fluid outlet temperature from the
 
regenerative heat exchanger is set for approximately 150&#xf8;F. This temperature
 
setting may require that the demineralizers be bypassed in order to prolong
 
resin life and preclude the possibility of eluting the radioactivity that has been adsorbed by the resin. With the flash tank venting to the condenser, the total steam generator blowdown then is limited to about 50,000 lbs/hr.
 
USE OF THE STEAM GENERATOR BLOWDOWN DEMINERALIZERS BY THE SECONDARY LIQUID WASTE (SLWS) - As a backup to the SLWS demineralizer, interties have been provided between the SLWS and the steam generator blowdown system to allow the processing of SLWS low TDS waste by either of the two sets of two parallel steam generator blowdown demineralizers. The system is designed so that blowdown can be processed by the set of demineralizers not being used for
 
processing the low TDS waste.
SAMPLING - The blowdown system sample points are arranged to provide
 
selectively extracted samples from each of the steam generator drums, each
 
individual blowdown line, and the surge tank. The nuclear sample connection
 
from the blowdown lines is located as close to the steam generator as possible to minimize transit time from the steam generator water mass to the point of use and to ensure maximum sample quality.
 
The process sampling system is normally used to continuously determine the chemical composition of the liquid in each of the steam generators. The process sample extraction points are located in the turbine building.
 
10.4-42 Rev. 14 WOLF CREEK A continuous inline radioactivity monitor is provided to detect the presence of activity which would indicate a primary-to-secondary leak. Anytime the
 
unprocessed blowdown activity level exceeds 1.0 x 10
-5  Ci/gm (excluding tritium), periodic samples are taken at the nuclear sampling station and analyzed in the hot lab to ascertain the affected steam generator and to monitor any increase in primary-to-secondary leakage. The nuclear sampling
 
system is capable of receiving intermittent or continuous samples from either
 
each of the steam generator drums or each of the individual blowdown lines.
The chemical composition is continuously monitored by the process sampling system.
 
STARTUP AND SHUTDOWN OPERATION - The startup and shutdown operations of the
 
blowdown system are the same as for normal operation, except that the secondary cycle is not able to receive the flash tank vent fluid. When feedwater is not flowing through the No. 5 feedwater heater, the flash tank vent is directed to
 
the condenser. If condenser vacuum is not being maintained, the vent is directed to the atmosphere. In the event that the condensate pumps (which
 
would provide condensate cooling flow for the regenerative heat exchanger) or the heater drain tank are unavailable, it is possible for the liquid blowdown to be returned to the environment or the condensate storage tank rather than
 
the condenser. Under these conditions, the total steam generator blowdown flow
 
is limited by the capability of the nonregenerative heat exchanger to maintain
 
cooled blowdown below the required limits. When demineralization or discharge to the environment is required, a 120&deg;F limit is maintained. If the blowdown is being directed to the condensate storage tank, the blowdown is cooled to a maximum of 120 F. During shutdown with the steam generator depressurized, the steam generator drain pumps may be employed to drain and dispose of or process steam generator water. A connection is available to the suction side of the condensate pumps
 
for processing of the liquid through the condensate demineralizers and bypassing the condenser.
Wet layup capabilities are provided to protect the steam generators from
 
corrosive attack during inactive periods. This is achieved by ensuring the
 
exclusion of oxygen and controlling the pH of the water mass inside the steam
 
generators.
EMERGENCY OPERATION - The isolation valves of the blowdown and sample systems
 
are closed automatically by the signal from system radiation monitors, by the
 
condenser air removal exhaust monitor, and/or by the SGBSIS (AFAS) signal. All
 
of these valves are capable of being remotely closed from the control room.
 
10.4-43 Rev. 10 WOLF CREEK Following a radiation monitor alarm, or start of the auxiliary feedwater system, the sample system isolation valves may be reopened from the control
 
room. This capability permits identification, and subsequent isolation, of the steam generator responsible for fission product transfer from the primary to the secondary system. After reset of the AFAS, the blowdown system isolation valves may be reopened from the control room. 
 
10.4.8.3  Radioactive Releases In the event radioactivity is transmitted to the secondary side of the steam
 
generator, it will show up in the blowdown fluid. For conditions of primary-to-secondary leakage, all blowdown fluid is processed and returned to the main condenser. Any discharge of radioactive fluid from this system is considered unlikely.
 
If the blowdown fluid is being discharged to the environment and the activity
 
level in the discharged fluid approaches the limit defined by the ODCM, the
 
radiation monitor in the discharge line alarms and automatically terminates discharge and blowdown. In addition, blowdown discharge to the environment is automatically terminated on a low dilution water flow signal.
 
When discharging to the environment, the discharge temperature is between 60-
 
120&deg;F, exit pressure is 35-150 psig, and the flow rate is a maximum of 270 gpm.
The operating criteria for the secondary side blowdown system are dictated by
 
the need for limiting the secondary side build-up of dissolved solids. The
 
equilibrium radioactive concentrations based on a assumed primary-to-secondary
 
leakrate are given in Chapter 11.0 for the steam generators.
10.4.8.4  Safety Evaluation Safety evaluations are numbered to correspond to the safety design bases in
 
Section 10.4.8.1.
SAFETY EVALUATION ONE - The safety-related portions of the SGBS are located in
 
the reactor and auxiliary buildings. These buildings are designed to withstand
 
the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.
 
10.4-44 Rev. 26 WOLF CREEK SAFETY EVALUATION TWO - The safety-related portions of the SGBS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) and (N) provide
 
the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.
 
SAFETY EVALUATION THREE - The component and system description for the SGBS
 
shows that complete redundancy is provided and, as indicated by Table 10.4-10, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described
 
in Chapter 8.0.
 
SAFETY EVALUATION FOUR - Periodic inservice functional testing is done in accordance with Section 10.4.8.5. Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI requirements that are appropriate for the
 
SGBS.
 
SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.4-9 shows that the components meet the design and fabrication codes given in Section 3.2. All the power
 
supplies and control function necessary for the safety functions of the system
 
are Class 1E, as described in Chapters 7.0 and 8.0.
SAFETY EVALUATION SIX - Section 10.4.8.2 describes provisions made to identify
 
and isolate leakage or malfunction and to isolate the steam generator water
 
inventory from the nonsafety-related portions of the system.
 
SAFETY EVALUATION SEVEN - Sections 6.2.4 and 6.2.6 provide the safety evaluation for the system containment isolation arrangement and testability for
 
the steam generator drain line penetration.
 
10.4.8.5  Tests and Inspections
 
The performance and structural and leaktight integrity of all system components is demonstrated by continuous operation.
The SGBS is testable through the full operational sequence that brings the system into operation for reactor shutdown and for DBAs, including operation of
 
applicable portions of the protection system and transfer between normal and
 
standby power.
 
10.4-45 Rev. 19 WOLF CREEK The safety-related components are located to permit preservice and inservice inspections.
 
10.4.8.6  Instrumentation Applications The SGBS instrumentation, as described in Table 10.4-11, is designed to
 
facilitate automatic operation, remote control, and continuous indication of
 
system parameters. As described in Chapter 7.0, certain devices are involved in the protection system.
 
The process radiation monitors provided downstream of the steam generator
 
blowdown flash tank and in the plant discharge line are discussed in Section
 
11.5. 10.4.9  AUXILIARY FEEDWATER SYSTEM
 
The auxiliary feedwater system (AFS) is a reliable source of water for the
 
steam generators. The AFS, in conjunction with safety valves in the main steam lines, is a safety-related system, the function of which is to remove thermal energy from the reactor coolant system by releasing secondary steam to the
 
atmosphere. The AFS also provides emergency water following a secondary side
 
line rupture. Removal of heat in this manner prevents the reactor coolant
 
pressure from increasing and causing release of reactor coolant through the pressurizer relief and/or safety valves.
 
The auxiliary feedwater system may also be used following a reactor shutdown in
 
conjunction with the condenser dump valves or atmospheric relief valves, to
 
cool the reactor coolant system.
10.4.9.1  Design Bases 10.4.9.1.1  Safety Design Bases
 
SAFETY DESIGN BASIS ONE - The AFS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external
 
missiles (GDC-2).
 
SAFETY DESIGN BASIS TWO - The AFS is designed to remain functional after an SSE or to perform its intended function following a postulated hazard, such as internal missile, or pipe break (GDC-4).
 
10.4-46 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS THREE - The safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power. The
 
system requirements may be met with a complete loss of ac power (GDC-34).
SAFETY DESIGN BASIS FOUR - The AFS is designed so that the active components are capable of being tested during plant operation. Provisions are made to
 
allow for inservice inspection of components at appropriate times specified in
 
the ASME Boiler and Pressure Vessel Code, Section XI.
SAFETY DESIGN BASIS FIVE - The AFS is designed and fabricated consistent with
 
the quality group classification assigned by Regulatory Guide 1.26 and the
 
seismic category assigned by Regulatory Guide 1.29. The power supply and
 
control functions are in accordance with Regulatory Guide 1.32.
SAFETY DESIGN BASIS SIX - The AFS, in conjunction with the condensate storage
 
tank (classified as special scope) or essential service water system, provides feedwater to maintain sufficient steam generator level to ensure heat removal from the reactor coolant system in order to achieve a safe shutdown following a main feedwater line break, a main steamline break, or an abnormal plant situation requiring shutdown. The auxiliary feedwater system is capable of
 
delivering full flow when required, after detection of any accident requiring auxiliary feedwater (refer to Chapter 15.0).
 
SAFETY DESIGN BASIS SEVEN - The capability to isolate components or piping is provided, if required, so that the AFS safety function is not compromised. 
 
This includes isolation of components to deal with leakage or malfunctions and
 
to isolate portions of the system that may be directing flow to a broken
 
secondary side loop.
SAFETY DESIGN BASIS EIGHT - The AFS has the capacity to be operated locally as
 
an alternate, redundant means of feedwater control, in the unlikely event that
 
the control room must be evacuated.
10.4.9.1.2  Power Generation Design Bases
 
The AFS has no power generation design bases. The condensate and feedwater
 
system is designed to provide a continuous feedwater supply to the steam
 
generators during startup normal plant operation, and shutdown. Refer to Section 10.4.7.
 
10.4-47 Rev. 16 WOLF CREEK 10.4.9.2  System Description 10.4.9.2.1  General Description The system consists of two motor-driven pumps, one steam turbine-driven pump, and associate piping, valves, instruments, and controls, as shown on Figure
 
10.4-9 and described in Table 10.4-12. Figure 10.4-10 shows the piping and
 
instrumentation for the steam turbine.
Each motor-driven auxiliary feedwater pump will supply 100 percent of the
 
feedwater flow required for removal of decay heat from the reactor. The
 
turbine-driven pump is sized to supply up to twice the capacity of a motor-
 
driven pump. This capacity is sufficient to remove decay heat and to provide adequate feedwater for cooldown of the reactor coolant system at 50&#xba;F/hr within 1 hour of a reactor trip from full power.
 
Normal flow is from the condensate storage tank (CST) to the auxiliary
 
feedwater pumps. Two redundant safety-related back-up sources of water from the essential service water system (ESWS) are provided for the pumps. For a more detailed description of the automatic sequence of events, refer to Section
 
10.4.9.2.3.
 
Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the
 
safety grade water source.
 
The condensate storage tank has sufficient capacity to allow the plant to remain at hot standby for 4 hours and then cool down the primary system at an average rate of 50&deg;F per hour to a temperature of 350&deg;F. Initially, sensible
 
and decay heat is removed from the reactor coolant system to reduce the
 
temperature from a full-power operation average temperature of 588&deg;F to a
 
nominal hot standby temperature of 500&deg;F. Subsequently, the reactor is brought down to 350&deg;F at 50&deg;F/hr. Refer to Section 9.2.6 for a description of the condensate storage system.
 
The non-safety auxiliary feedwater pump (NSAFP), installed in the Condensate
 
Storage and Transfer System (CSTS), functions to provide an alternate source of cooling water to the steam generators through the Auxiliary Feedwater system as shown in Figure 10.4-9. The NSAFP is powered from the Station Blackout Diesel Generators (SBO DGs) as described in section 8.3.1.1.1.3. The SBO DGs and NSAFP will be manually aligned as deemed necessary.
Hose connections are available for connection of a portable auxiliary feedwater pump in the event of an extended loss of all AC power. These connections
 
support implementation of beyond-design-basis external event Phase 2 coping
 
strategies to maintain or restore core cooling as described in Appendix 3D.
 
In order to remove decay heat by the steam generators, auxiliary feedwater must be supplied to the steam generators in the event that the normal source of feedwater is lost. The minimum required flow rate is 470 gpm for decay heat
 
removal during plant normal cooldown. The single active failure for Chapter 15
 
events that take credit for auxiliary feedwater flow for decay heat removal
 
assumes one of the two motor-driven auxiliary feedwater pumps is operable. The overall minimum auxiliary feedwater flow rate is 563 gpm to fulfill the acceptance criteria for the feedline break analysis in Section 15.2.8.
 
Provisions are incorporated in the AFS design to allow for periodic operation
 
to demonstrate performance and structural and leaktight integrity. Leak detection is provided by visual examination and in the floor drain system described in Section 9.3.3.
10.4-48 Rev. 30 WOLF CREEK 10.4.9.2.2  Component Description
 
Codes and standards applicable to the AFS are listed in Tables 3.2-1 and 10.4-
: 12. The AFS is designed and constructed in accordance with quality groups B and C and seismic Category I requirements.
 
MOTOR-DRIVEN PUMPS - Two auxiliary feedwater pumps are driven by ac-powered
 
electric motors supplied with power from independent Class 1E switchgear busses. Each horizontal centrifugal pump takes suction from the condensate storage tank, or alternatively, from the ESWS. Pump design capacity includes
 
continuous minimum flow recirculation, which is controlled by restriction
 
orifices.
 
TURBINE-DRIVEN PUMP - A turbine-driven pump provides system redundancy of auxiliary feedwater supply and diversity of motive pumping power. The pump is a
 
horizontal centrifugal unit. Pump bearings are cooled by the pumped fluid.
Pump design capacity includes continuous minimum flow recirculation. Power for
 
all controls, valve operators, and other support systems is independent of ac power sources.
 
Steam supply piping to the turbine driver is taken from two of the four main
 
steam lines between the containment penetrations and the main steam isolation
 
valves. Each of the steam supply lines to the turbine is equipped with a locked-open gate valve, normally closed air-operated globe valve with air-operated globe bypass to keep the line warm, and two nonreturn valves. Air-
 
operated globe valves are equipped with dc-powered solenoid valves. These
 
steam supply lines join to form a header which leads to the turbine through a
 
normally closed, dc motor-operated mechanical trip and throttle valve. The main steam system is described in Section 10.3.
The steam lines contain provisions to prevent the accumulation of condensate. 
 
The turbine driver is designed to operate with steam inlet pressures ranging
 
from 92 to 1,290 psia. Exhaust steam from the turbine driver is vented to the atmosphere above the auxiliary boiler building roof. Refer to Safety Evaluation Two for a discussion of the design provisions for the exhaust line.
 
PIPING AND VALVES - All piping in the AFS is seamless carbon steel. Welded
 
joints are used throughout the system, except for flanged connections at the pumps.
The piping from the ESWS to the suction of each of the auxiliary feedwater
 
pumps is equipped with a motor-operated butterfly valve, an isolation valve, and a nonreturn valve. Each line from the condensate storage tank is equipped with a motor-operated gate 
 
10.4-49 Rev. 11 WOLF CREEK valve and a nonreturn valve. Each motor-driven pump discharges through a nonreturn valve and a locked-open isolation valve to feed two steam generators
 
through individual sets of a locked open isolation valve, a normally open, motor-operated control valve, a check valve followed by a flow restriction orifice, and a locked-open globe valve. The turbine-driven pump discharges through a nonreturn valve, a locked-open gate valve to each of the four steam
 
generators through individual sets of a locked-open isolation valve, a normally
 
open air-operated control valve, followed by a nonreturn valve, a flow restriction orifice, and a locked-open globe valve.
 
The turbine-driven pump discharge control valves are positionable, air operated 
 
valves. At each connection to the four main feedwater lines, the auxiliary
 
feedwater lines are equipped with check valves.
The system design precludes the occurrence of water hammer in the main
 
feedwater inlet to the steam generators. For a description of prevention of water hammer, refer to Section 10.4.7.2.1.
 
TANKS - Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the safety grade water source.
10.4.9.2.3  System Operation NORMAL PLANT OPERATION - The AFS is not required during normal power generation. The pumps are placed in standby, lined up with the condensate
 
storage tank, and are available if needed.
EMERGENCY OPERATION - In addition to remote manual-actuation capabilities, the AFS is aligned to be placed into service automatically in the event of an
 
emergency. See section 7.3.6.1.1 for a description of this operation.
 
The common water supply header from the condensate storage tank contains a locked-open, 12-inch, butterfly isolation valve. Correct valve position is
 
verified by periodic surveillance. In the case of a failure of the water
 
supply from the condensate storage tank, the normally closed, motor-operated
 
butterfly valves from the ESWS are automatically opened on low suction header pressure. Valve opening time and pump start time are coordinated to ensure adequate suction pressure with either onsite or offsite power available.
 
If a motor-driven pump supplying two of the three intact steam generators fails
 
to function, the turbine-driven pump automatically starts when a low-low level is reached in two of the four steam generators. During all of the above emergency conditions, the normally open control valves are remote manually
 
operated.
 
During all of the above emergency conditions, the motor-driven pump normally
 
open control valves are automatically operated to limit runout flow under all secondary side pressure conditions. This is required to prevent pump suction cavitation at high flow rates. The turbine-driven pump design includes a lower
 
NPSH requirement. Therefore, the turbine-driven pump control valves are remote
 
manually operated.
 
10.4-50 Rev. 25 WOLF CREEK Low pump discharge pressure alarms assists alerting in the operator to a secondary side break. The operator then determines which Steam Generator is
 
faulted, and closes the appropriate discharge control valves. For a postulated unisolable double-ended secondary system pipe rupture, refer to Chapter 15.0 for further information on the required operator actions and times assumed in
 
the applicable accident analysis.
 
10.4.9.3  Safety Evaluation
 
Safety evaluations are numbered to correspond to the safety design bases in
 
Section 10.4.9.1.1.
 
SAFETY EVALUATION ONE - The AFS is located in the auxiliary building, except for the Turbine Driven Auxiliary Feedwater Pump exhaust pipe and the section of pump recirculation piping mentioned in the note below. This building is
 
designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections
 
3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of the auxiliary building.  (See the discussion in Safety Evaluation Two, pertaining to the exhaust steam from the turbine driver during a SSE.)
NOTE: To avoid pump damage due to overheating while operating with no delivered flow, the Motor Driven Auxiliary Feedwater Pumps (MDAFWPs) and the Turbine Driven
 
Auxiliary Feedwater Pump (TDAFWP) require minimum flows of 75 gpm and 120 gpm
 
respectively. To satisfy this requirement, each pump has a recirculation line
 
that joins to common header ALO45DBC-3" and returns to the condensate storage tank (CST). The common recirculation line transitions from safety-related to non-safety related/non-seismic at the Auxiliary Feedwater System to CST pipe
 
chase, becoming line ALO46DBC-3". The CST pipe chase and the CST are not
 
seismically qualified.
 
If a hazard (i.e. tornadoes, floods, missiles, pipe breaks, fires, and seismic events) resulted in the non-safety related portion of the recirculation header
 
becoming crimped such that recirculation flow was restricted in conjunction
 
with an AFS actuation signal, the potential for pump damage could exist.
 
To eliminate that potential, an alternate flow path has been designed such that even in the event of a recirculation line obstruction, sufficient cooling flow
 
will be available.
 
The AFW system is designed to remain functional after a tornado missile impact.
As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the driver is routed from the auxiliary building wall through the auxiliary boiler building. The portion of the turbine driver exhaust stack that exits the auxiliary building has been analyzed and is not expected to crimp and inhibit the ability of the TDAFWP to deliver design flow rates. The impact from a credible missile will cause the exhaust line to sever by any of the postulated tornado missile scenarios thus not inhibiting the function of the exhaust line.
 
SAFETY EVALUATION TWO - The AFS is designed to remain functional after a SSE. 
 
Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were
 
considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained. For a more complete description of motor qualification, refer to Sections 3.10(B)
 
and 3.11(B).
 
10.4-51 Rev. 30 WOLF CREEK As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the turbine driver is routed from the auxiliary building wall through the auxiliary boiler building, which is designed to UBC seismic requirements and is not expected to fail during a seismic event. If the auxiliary boiler building were to catastrophically fail and the exhaust line were sheared off completely, the AFP turbine would operate properly.
Even if the exhaust line were to crimp significantly, the AFP turbine driven pump would still deliver design flow rates. The back pressure on the turbine
 
may be increased significantly before the required flow rates are not
 
available. The TDAFWP is capable of delivering design flow even with a local
 
constriction of 50 percent of the free area of the exhaust line. This type of failure is not considered to be credible. However, the exhaust line and its support are re-classified as special scope, II/I, to assure they will not be
 
degraded and thus affect the operation of the Auxiliary Feedwater Pump Turbine.
 
Breaks in seismic Category I piping are not postulated during a seismic event.
Thus an MSLB or MFLB inside containment or in the steam tunnel are not postulated following a seismic event and the design of the exhaust line does
 
not enter into the evaluation of these breaks.
 
For a seismically induced MSLB in the turbine building, various single failures can be postulated, none of which result in adverse conditions even if the AFP turbine is inoperable. If an MSLIV fails to close, one steam generator blows
 
down; however, two motor driven AFW pumps are available to feed three intact
 
steam generators. If one motor driven pump train fails for any reason, the
 
other motor driven pump feeds two steam generators as required. In this case, the break has been isolated by the MSLIV, and all four steam generators are intact.
 
SAFETY EVALUATION THREE - Complete redundancy is provided and, as indicated by
 
Table 10.4-13, no single failure compromises the system's safety functions.
All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.
 
The turbine-driven pump is energized by steam drawn from two main steam lines
 
between the containment penetrations and the main steam isolation valves. All valves and controls necessary for the function of the turbine-driven pump are energized by the Class 1E dc power supplies. Turbine bearing lube oil is
 
circulated by an integral shaft-driven pump. Turbine and pump bearing oil is
 
cooled by pumped auxiliary feedwater.
 
SAFETY EVALUATION FOUR - The AFS is initially tested with the program given in Chapter 14.0. Periodic operational testing is done in accordance with Section
 
10.4.9.4.
 
Section 6.6 provides the ASME Boiler and Pressure Vessel Code, Section XI
 
requirements that are appropriate for the AFS.
SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group
 
classification and seismic category applicable to this system and supporting
 
systems. Table 10.4-12 shows that the components meet the design and
 
fabrication codes given in Section 3.2. All the power supplies and control functions necessary for safe function of the AFS are Class 1E, as described in Chapters 7.0 and 8.0.
 
10.4-52 Rev. 30 WOLF CREEK SAFETY EVALUATION SIX - The AFS provides a means of pumping sufficient feedwater to prevent damage to the reactor following a main feedwater line break inside the containment, or a main steamline break incident, as well as to cool down the reactor coolant system at a rate of 50 F per hour to a temperature of 350 F, at which point the residual heat removal system can operate. Pump capacities, as shown in Table 10.4-12, and start times are such that these objectives are met. Restriction orifices located in the pump discharge lines and automatic flow control valves for the motor-driven pumps
 
limit the flow to the broken loop so that adequate cooldown flow (470 gpm) can be provided to the other steam generators for removal of reactor decay heat and so that containment design pressure is not exceeded. Pump discharge head is
 
sufficient to establish the minimum necessary flowrate against a steam
 
generator pressure corresponding to the lowest pressure setpoint of the main
 
steam safety valves. The maximum time period required to start the electric motors and the steam turbine which drive the auxiliary feedwater pumps is chosen so that sufficient flowrates are established within the required time
 
for primary system protection. Refer to Chapter 15.0.
 
SAFETY EVALUATION SEVEN - As discussed in Sections 10.4.9.2 and 10.4.9.5 and Chapter 15.0, adequate instrumentation and control capability is provided to permit the plant operator to quickly identify and isolate the auxiliary
 
feedwater flow to a broken secondary side loop. Isolation from nonsafety-
 
related portions of the system, including the condensate storage tank, is
 
provided as described in Section 10.4.9.2.
SAFETY EVALUATION EIGHT - The AFS can be controlled from either the main
 
control room or the auxiliary shutdown panel. Refer to Section 7.4 for the
 
control description.
 
10.4.9.4  Tests and Inspections
 
Preoperational testing is described in Chapter 14.0. The performance and
 
structural and leaktight integrity of system components is demonstrated by
 
periodic operation.
The AFS is testable through the full operational sequence that brings the
 
system into operation for reactor shutdown and for DBA, including operation of
 
applicable portions of the protection system and the transfer between normal
 
and standby power sources.
The safety-related components, i.e., pumps, valves, piping, and turbine, are
 
designed and located to permit preservice and inservice inspection.
 
10.4.9.5  Instrumentation Applications
 
The AFS instrumentation is designed to facilitate automatic operation and
 
remote control of the system and to provide continuous indication of system
 
parameters.
 
Redundant condensate storage tank level indication and alarms are provided in the control room. The backup indication and alarms use auxiliary feedwater
 
pump suction pressure by converting it to available tank level. Both alarms
 
provide at least 20 minutes for operator action (e.g., refill the tank),
assuming that the largest capacity auxiliary feedwater pump is operating.
 
10.4-53 Rev. 30 WOLF CREEK Pressure transmitters are provided in the discharge and suction lines of the auxiliary feedwater pumps. Auxiliary feedwater flow to each steam generator is indicated by flow indicators provided in the control room. If the condensate supply from the storage tank fails, the resulting reduction of pressure at the pump suction is indicated in the control room.
Flow transmitters and control valves with remote control stations are provided on the auxiliary feedwater lines to each steam generator to indicate and allow control of flow at the auxiliary shutdown panel and in the control room. Flow
 
controllers for the motor-driven pump control valves position the valves to 
 
limit the flow to a preset value throughout the full range of downstream operating pressures.
 
Position indication in the control room is provided on the ESFAS status panel
 
for the manual isolation valve in the auxiliary feedwater pump suction header
 
from the condensate storage tank.
A flow element and indicator is provided in each auxiliary feedwater pump
 
minimum recirculation line to facilitate periodic performance testing.
 
Table 10.4-14 summarizes AFS controls, alarms, indication of status, etc.
10.4.10  SECONDARY LIQUID WASTE SYSTEM
 
The function of the secondary liquid waste system (SLWS) is to process
 
condensate demineralizer regeneration wastes and potentially radioactive liquid waste collected in the turbine building. Processed liquid waste may be reused in the plant or discharged to the environment.
 
10.4.10.1  Design Bases 10.4.10.1.1  Safety Design Bases
 
The SLWS is not a safety-related system, and its failure does not compromise
 
any safety-related system or prevent a safe shutdown of the reactor.
 
10.4.10.1.2  Power Generation Design Bases
 
POWER GENERATION DESIGN BASIS ONE - During normal plant operation, the SLWS is
 
utilized to the extent required to meet chemical composition limits for release
 
to the environment or for recyle of processed fluids back to the condenser.
POWER GENERATION DESIGN BASIS TWO - The SLWS processes recyclable turbine
 
building waste during normal operation with the radioactivity levels identified
 
in Appendix 11.1A.
 
POWER GENERATION DESIGN BASIS THREE - During abnormal operation, the SLWS has provisions to receive from nonradioactive turbine building sumps liquids that may be radioactively contaminated. This condition could occur if, for example, condensation from the turbine building air coolers contained radioactive  
 
contamination or if during maintenance a major component's normal drainage path  
 
was not available.  
 
10.4-54 Rev. 30 WOLF CREEK POWER GENERATION DESIGN BASIS FOUR - The SLWS processes condensate demineralizer regeneration waste products for recycle back to the condenser or discharge to the environment. The SLWS is designed to accept and process condensate demineralizer regeneration wastes resulting from the regeneration of one demineralizer vessel every 2 days.
POWER GENERATION DESIGN BASIS FIVE -
The SLWS includes cross-connections with the steam generator blowdown system to provide improved reliability by providing back-up demineralization capability.
10.4.10.2  System Description 10.4.10.2.1  General Description
 
The SLWS consists of several tanks and pumps, a demineralizer, a charcoal
 
adsorber, an oil interceptor, and three filters, as shown in Figure 10.4-12.
Turbine building wastes consist of wastes collected in turbine building floor
 
and equipment drains and condensate demineralizer regeneration wastes. The
 
turbine building drains are segregated into two categories. The first category
 
consists of drains which could include potentially radioactive turbine cycle leakage. The other category consists of nonradioactive sources.
 
The potentially radioactive turbine building drains are collected, as described
 
in Section 9.3.3, in specific sumps throughout the turbine building and sent to
 
the SLW drain collector tanks for processing. Drain processing is based on operator knowledge of secondary system chemistry and radioactive contamination, in conjunction with Technical Specification limitations and state and local
 
discharge permit restrictions. In all cases, the waste is processed through an
 
oil interceptor to remove oil which might be present in the sumps. In
 
addition, the waste may be processed by filtration, and/or demineralization.
The nonradioactive waste is normally discharged without processing (except for oil removal) through the oily waste system. However, provisions exist to
 
monitor the radioactivity of the nonradioactive waste and to divert it to be
 
processed if necessary. All discharges from the standard power block are
 
monitored for radioactivity levels, and the discharge is automatically terminated if the activity is above permissible levels or dilution flow rate is insufficient. The discharge from the SLWS oil interceptor pumps can be routed
 
to either the low or high total dissolved solids (TDS) collection tanks. The
 
routing of turbine effluents can be used to provide adequate dilution for pH
 
neutralization for discharge to the environment without using contaminated lines.
The condensate demineralizer regeneration waste is divided into two types --


10.4-54 Rev. 30 WOLF CREEK  POWER GENERATION DESIGN BASIS FOUR - The SLWS processes condensate demineralizer regeneration waste products for recycle back to the condenser or discharge to the environment. The SLWS is designed to accept and process condensate demineralizer regeneration wastes resulting from the regeneration of one demineralizer vessel every 2 days. POWER GENERATION DESIGN BASIS FIVE -  The SLWS includes cross-connections with the steam generator blowdown system to provide improved reliability by providing back-up demineralization capability. 10.4.10.2  System Description  10.4.10.2.1  General Description The SLWS consists of several tanks and pumps, a demineralizer, a charcoal adsorber, an oil interceptor, and three filters, as shown in Figure 10.4-12. Turbine building wastes consist of wastes collected in turbine building floor and equipment drains and condensate demineralizer regeneration wastes. The turbine building drains are segregated into two categories. The first category consists of drains which could include potentially radioactive turbine cycle leakage. The other category consists of nonradioactive sources.
The potentially radioactive turbine building drains are collected, as described in Section 9.3.3, in specific sumps throughout the turbine building and sent to the SLW drain collector tanks for processing. Drain processing is based on operator knowledge of secondary system chemistry and radioactive contamination, in conjunction with Technical Specification limitations and state and local discharge permit restrictions. In all cases, the waste is processed through an oil interceptor to remove oil which might be present in the sumps. In addition, the waste may be processed by filtration, and/or demineralization. The nonradioactive waste is normally discharged without processing (except for oil removal) through the oily waste system. However, provisions exist to monitor the radioactivity of the nonradioactive waste and to divert it to be processed if necessary. All discharges from the standard power block are monitored for radioactivity levels, and the discharge is automatically terminated if the activity is above permissible levels or dilution flow rate is insufficient. The discharge from the SLWS oil interceptor pumps can be routed to either the low or high total dissolved solids (TDS) collection tanks. The routing of turbine effluents can be used to provide adequate dilution for pH neutralization for discharge to the environment without using contaminated lines.
The condensate demineralizer regeneration waste is divided into two types --
high and low total dissolved solids (TDS).  
high and low total dissolved solids (TDS).  


High TDS waste results from the acid and caustic rinses used when chemically regenerating spent resins. Low TDS waste results from the initial backflushing of unregenerated resin and the final rinsing of the regenerated resin to remove the acid and caustic. These high and low TDS wastes are collected separately in two high and two low TDS collector tanks.
High TDS waste results from the acid and caustic rinses used when chemically regenerating spent resins. Low TDS waste results from the initial backflushing of unregenerated resin and the final rinsing of the regenerated resin to remove  
 
the acid and caustic. These high and low TDS wastes are collected separately in  
 
two high and two low TDS collector tanks.  
 
These input streams are retained within the appropriate collection tanks and then processed by various combinations of filtration, crud sedimentation, charcoal adsorption, and demineralization. The processed SLW liquids can then   
These input streams are retained within the appropriate collection tanks and then processed by various combinations of filtration, crud sedimentation, charcoal adsorption, and demineralization. The processed SLW liquids can then   


10.4-55 Rev. 30 WOLF CREEK be collected in either or both of the two SLW monitor tanks, sampled and returned to the condenser, or discharged. The monitor tanks provide holdup and isolation in conjunction with sampling to ensure that the chemical and radioactivity limits for discharge or recycle are met. The SLW drain collector tanks are sized based on 10,000 gpd of leakage in all areas of the turbine building. Since the SLWS normally receives only 7,200 gpd from these drains, the 15,000 gallon SLW drain collector tanks can each receive drainage for at least 2 days. This delay provides the surge capacity to facilitate repair, maintenance, or inspection that may be required on the process equipment or abnormal usage demands which may be made of the SLWS. The SLW drain collector tank pumps are cross-connected to take suction from either tank. A recirculation line from the pumps' discharge to either tank is provided to allow the tank contents to be mixed so that accurate sampling can be accomplished. The SLW drain collector tank contents are then processed and sent to the SLW monitor tanks. The SLW monitor tanks have the same design features, including two pumps, as the SLW drain collector tanks. After being sampled in the SLW monitor tanks, the processed water is either returned to the condenser or discharged. The distribution header connection for the laundry water storage tank is for makeup to the recyclable laundry system. This makeup is necessary to replenish the water lost in the laundry's dryer.
10.4-55 Rev. 30 WOLF CREEK be collected in either or both of the two SLW monitor tanks, sampled and returned to the condenser, or discharged. The monitor tanks provide holdup and isolation in conjunction with sampling to ensure that the chemical and radioactivity limits for discharge or recycle are met.
In addition, the floor drain system described in Section 9.3.3 provides leakage detection capabilities to assure that any abnormal leakage is detected and repaired. 10.4.10.2.2  Component Description Codes and standards applicable to the SLWS are listed in Table 3.2-1. Major components are described in Table 10.4-15.
The SLW drain collector tanks are sized based on 10,000 gpd of leakage in all areas of the turbine building. Since the SLWS normally receives only 7,200 gpd from these drains, the 15,000 gallon SLW drain collector tanks can each receive drainage for at least 2 days. This delay provides the surge capacity to facilitate repair, maintenance, or inspection that may be required on the process equipment or abnormal usage demands which may be made of the SLWS. The SLW drain collector tank pumps are cross-connected to take suction from either tank. A recirculation line from the pumps' discharge to either tank is provided to allow the tank contents to be mixed so that accurate sampling can be accomplished. The SLW drain collector tank contents are then processed and sent to the SLW monitor tanks. The SLW monitor tanks have the same design features, including two pumps, as the SLW drain collector tanks.
10.4.10.2.3  System Operation Turbine Building Recyclable Drains  
After being sampled in the SLW monitor tanks, the processed water is either  
 
returned to the condenser or discharged. The distribution header connection  
 
for the laundry water storage tank is for makeup to the recyclable laundry  
 
system. This makeup is necessary to replenish the water lost in the laundry's dryer.
In addition, the floor drain system described in Section 9.3.3 provides leakage  
 
detection capabilities to assure that any abnormal leakage is detected and  
 
repaired.
10.4.10.2.2  Component Description  
 
Codes and standards applicable to the SLWS are listed in Table 3.2-1. Major  
 
components are described in Table 10.4-15.  
 
10.4.10.2.3  System Operation  
 
Turbine Building Recyclable Drains  
 
The turbine building recyclable drains are collected in drain sumps throughout the turbine building. These sumps are normally 
 
aligned to discharge, via the sump pumps, to the secondary liquid waste (SLW)
 
oil interceptor. After passing through the oil interceptor, the de-oiled water
 
is pumped, via the SLW oil interceptor transfer pumps, to the SLW drain collector tanks. Two drain collector tanks are provided so that one is available for accepting wastes while the other is being sampled or processed.
 
Prior to processing the SLW drain collector tank contents, a sample is taken to
 
determine the optimum means of processing. The options available are:
: a. Filtration
: b. Charcoal adsorption
: c. Demineralization


The turbine building recyclable drains are collected in drain sumps throughout the turbine building. These sumps are normally aligned to discharge, via the sump pumps, to the secondary liquid waste (SLW) oil interceptor. After passing through the oil interceptor, the de-oiled water is pumped, via the SLW oil interceptor transfer pumps, to the SLW drain collector tanks. Two drain collector tanks are provided so that one is available for accepting wastes while the other is being sampled or processed.  
10.4-56 Rev. 30 WOLF CREEK or any combination of these options. Two SLW drain collector tank pumps are available to pump the drain fluids to the radwaste building for processing.
The operator selects the appropriate tank/pump combination, starts the pump, and, when ready, opens an air-operated valve located at the discharge of the drain collector tank pumps. The drain fluid is first passed through a wye strainer to remove all gross particulates, then it is passed through a cartridge filter to remove particulates in the 30-micron range. This scheme (strainer/filter) maximizes filter cartridge life. A bypass is provided around the strainer and/or filter combination. The wye strainer is provided with a local blow-off connection for ease of cleaning.  


Prior to processing the SLW drain collector tank contents, a sample is taken to determine the optimum means of processing. The options available are:
Processed water from the liquid Waste Process Skid is typically directed to the Secondary Liquid Waste (SLW) Monitor Tanks. The SLW charcoal absorber and SLW demineralizers are optional for removing trace organics and dissolved solids.
a. Filtration b. Charcoal adsorption


c. Demineralization 
These components are typically bypassed. The charcoal absorber and the
 
demineralizer have wye strainers at their discharge to remove charcoal and
 
resin fines. The blowdown ports of these wye strainers are directed to the secondary spent resin storage tank to minimize waste handling.  


10.4-56 Rev. 30 WOLF CREEK  or any combination of these options. Two SLW drain collector tank pumps are available to pump the drain fluids to the radwaste building for processing. The operator selects the appropriate tank/pump combination, starts the pump, and, when ready, opens an air-operated valve located at the discharge of the drain collector tank pumps. The drain fluid is first passed through a wye strainer to remove all gross particulates, then it is passed through a cartridge filter to remove particulates in the 30-micron range. This scheme (strainer/filter) maximizes filter cartridge life. A bypass is provided around the strainer and/or filter combination. The wye strainer is provided with a local blow-off connection for ease of cleaning.
Processed water from the liquid Waste Process Skid is typically directed to the Secondary Liquid Waste (SLW) Monitor Tanks. The SLW charcoal absorber and SLW demineralizers are optional for removing trace organics and dissolved solids.
These components are typically bypassed. The charcoal absorber and the demineralizer have wye strainers at their discharge to remove charcoal and resin fines. The blowdown ports of these wye strainers are directed to the secondary spent resin storage tank to minimize waste handling.
Secondary Liquid Waste Monitoring and Discharge  
Secondary Liquid Waste Monitoring and Discharge  


The processed water, is sampled and monitored while being recirculated in the SLW monitor tanks. Two monitor tanks are provided so that one is available for accepting water while the other is being sampled and discharged. The water in the monitor tanks is sampled to assure that the proper chemistry exists for discharge to the environment at the operator's option.
The processed water, is sampled and monitored while being recirculated in the SLW monitor tanks. Two monitor tanks are provided so that one is available for accepting water while the other is being sampled and discharged. The water in  
If the operator decides to discharge to the environment, a radiation monitor is provided to isolate the discharge line on high radiation. In addition, the discharge line is also isolated by a low dilution flow signal.  
 
the monitor tanks is sampled to assure that the proper chemistry exists for  
 
discharge to the environment at the operator's option.  
 
If the operator decides to discharge to the environment, a radiation monitor is provided to isolate the discharge line on high radiation. In addition, the  
 
discharge line is also isolated by a low dilution flow signal.  


If, for any reason, the SLW monitor tank water does not meet the necessary chemical requirements for discharge or recycle, the water may be reprocessed through liquid radwaste demineralizer skid.  
If, for any reason, the SLW monitor tank water does not meet the necessary chemical requirements for discharge or recycle, the water may be reprocessed through liquid radwaste demineralizer skid.  


10.4-57 Rev. 30 WOLF CREEK Condensate Demineralizer Regenerant Wastes The condensate demineralizer system and the regeneration process are described in Section 10.4.6. High Total Dissolved Solids (TDS) Wastes  
10.4-57 Rev. 30 WOLF CREEK Condensate Demineralizer Regenerant Wastes  
 
The condensate demineralizer system and the regeneration process are described in Section 10.4.6.
High Total Dissolved Solids (TDS) Wastes  
 
High TDS wastes are wastes that result from the acid and caustic rinses used to regenerate condensate demineralizer resins. These wastes (though high in dissolved solids) are generally low in crud content. These wastes flow by
 
gravity from the demineralizer regeneration system to the high TDS transfer
 
tank located in the condenser pit of the turbine building. These waste fluids
 
are then pumped by either or both of the high TDS transfer tank pumps to the high TDS collector tanks.
 
Two high TDS collector tanks are provided to accept the wastes. Mixers are provided on the high TDS collector tanks to effectively mix the tank contents
 
to obtain an accurate sample. After sampling the tank contents, the operator adds any necessary chemicals to adjust the pH. The chemical storage tanks and metering pumps are provided as part of the condensate demineralizer
 
regeneration system. This step is normally not required as the condensate
 
demineralizer regeneration system should control the outlet fluids to an
 
acceptable pH range for processing in the SLW equipment. After pH adjustment, the mixers continue to operate to again ensure even distribution of tank contents. The operator next chooses the proper tank and pump combination (using the high TDS collector tank pumps) and starts the pump to prepare for
 
discharge to either the liquid radwaste system or the wastewater treatment system. If the operator chooses to discharge to the wastewater treatment system, the tank contents shall be sampled to ensure the wastes have a pH greater than 2 and lessthan 12.5; thus ensuring that they are not classified as hazardous wastes. The operator must manually isolate the path to the radwaste
 
building prior to aligning the pumps and tanks for discharge. The wastewater treatment system radioactivity monitor 1-HF-RE-95, monitors both the high and low TDS wastewaters prior to discharge to the wastewater treatment facility/system. The monitor monitors the wastewater treatment system influent
 
discharge line upstream of the isolation valve. The high radioactivity alarm
 
shall close the isolation valve to prevent the discharge of radioactive fluid
 
to the wastewater treatment system. If the high TDS wastes were to become radioactive they shall be processed through the radwaste building.


High TDS wastes are wastes that result from the acid and caustic rinses used to regenerate condensate demineralizer resins. These wastes (though high in dissolved solids) are generally low in crud content. These wastes flow by gravity from the demineralizer regeneration system to the high TDS transfer tank located in the condenser pit of the turbine building. These waste fluids are then pumped by either or both of the high TDS transfer tank pumps to the high TDS collector tanks.
Two high TDS collector tanks are provided to accept the wastes. Mixers are provided on the high TDS collector tanks to effectively mix the tank contents to obtain an accurate sample. After sampling the tank contents, the operator adds any necessary chemicals to adjust the pH. The chemical storage tanks and metering pumps are provided as part of the condensate demineralizer regeneration system. This step is normally not required as the condensate demineralizer regeneration system should control the outlet fluids to an acceptable pH range for processing in the SLW equipment. After pH adjustment, the mixers continue to operate to again ensure even distribution of tank contents. The operator next chooses the proper tank and pump combination (using the high TDS collector tank pumps) and starts the pump to prepare for discharge to either the liquid radwaste system or the wastewater treatment system. If the operator chooses to discharge to the wastewater treatment system, the tank contents shall be sampled to ensure the wastes have a pH greater than 2 and lessthan 12.5; thus ensuring that they are not classified as hazardous wastes. The operator must manually isolate the path to the radwaste building prior to aligning the pumps and tanks for discharge. The wastewater treatment system radioactivity monitor 1-HF-RE-95, monitors both the high and low TDS wastewaters prior to discharge to the wastewater treatment facility/system. The monitor monitors the wastewater treatment system influent discharge line upstream of the isolation valve. The high radioactivity alarm shall close the isolation valve to prevent the discharge of radioactive fluid to the wastewater treatment system. If the high TDS wastes were to become radioactive they shall be processed through the radwaste building.
Low Total Dissolved Solids (TDS) Wastes  
Low Total Dissolved Solids (TDS) Wastes  


Low TDS wastes are wastes that result from the resin washing, flushing, and sluicing operations that are a part of the condensate demineralizer regeneration process. These wastes (though low in dissolved solids) are relatively high in crud content. These wastes flow by gravity from the demineralizer regeneration system to the low TDS transfer tank in the condenser pit of the turbine building. These waste fluids are then pumped by either or both low TDS transfer tank pumps to the two low TDS collector tanks. These tanks are designed to promote settling of crud and are provided with a nozzle to drain off the settled crud.  
Low TDS wastes are wastes that result from the resin washing, flushing, and sluicing operations that are a part of the condensate demineralizer regeneration process. These wastes (though low in dissolved solids) are  
 
relatively high in crud content. These wastes flow by gravity from the  
 
demineralizer regeneration system to the low TDS transfer tank in the condenser  
 
pit of the turbine building. These waste fluids are then pumped by either or  
 
both low TDS transfer tank pumps to the two low TDS collector tanks. These tanks are designed to promote settling of crud and are provided with a nozzle to drain off the settled crud.
 
10.4-58 Rev. 19 WOLF CREEK Two low TDS collector tank pumps are provided for pumping the waste to processing equipment. If insufficient time has been allowed for clarification
 
of the waste, the low TDS collector tanks can be processed through a local bag filter and returned to the collector tanks. When the operator is ready to process the low TDS collector tanks, he selects the proper tank/pump combination, starts the pump, and, when ready to initiate processing, opens an
 
air-operated valve located at the discharge of the low TDS collector tank
 
pumps. The waste then flows to the radwaste building where it passes through a wye
 
strainer and one of two low TDS filters. This strainer/filter combination
 
extends filter cartridge life by removing all large particulates prior to the
 
filters. The waste next flows to the SLW demineralizer, and processing is completed as described previously.
 
If the SLW demineralizer is not available and the plant can be operated at one-half the maximum steam generator blowdown rate, the option exists to process
 
the low TDS wastes via two of the steam generator blowdown demineralizers.
If the operator chooses to discharge the low TDS wastes through the wastewater
 
treatment system, the operator must isolate the flowpath to the radwaste
 
building. The contents of the low TDS waste collector tank shall be sampled to
 
ensure that the pH is between 2 and 12.5. The operator then chooses the proper tank and pump combination, starts the pump and begins discharge to the wastewater treatment system. The discharge line to the wastewater treatment
 
facility is monitored by radioactivity monitor 1-HF-RE-95. The high
 
radioactivity monitor shall close the isolation valve downstream of the monitor
 
on a high radioactivity alarm to prevent discharge to the wastewater treatment facility.
Abnormal Operation
 
If abnormally large amounts of nonradioactively contaminated drainage collect in the turbine building recyclable sumps, such as a fire deluge, then the SLW system can be bypassed completely and the water discharged via the oily waste
 
discharge pipe.
 
System Releases Liquid effluents from the SLWS may be recycled to the secondary system via the
 
condenser or may be discharged to the environment.
 
Prior to discharge to the environment, the effluent is isolated within the appropriate monitor tank. The tank contents are recirculated to assure that they are well mixed and then sampled to assure that the release would not
 
exceed release limits. The discharge to the environment passes through a
 
process radiation monitor, which automatically closes the discharge valve on
 
high radioactivity. The method of processing secondary liquid wastes and
 
whether to recycle or discharge the processed wastes depend on the radioactivity concentrations. The radioactivity content of the SLWS releases is limited, along with radioactivity in other liquid releases, so as not to
 
exceed Offsite Dose Calculation Manual.  


10.4-58 Rev. 19 WOLF CREEK Two low TDS collector tank pumps are provided for pumping the waste to processing equipment. If insufficient time has been allowed for clarification of the waste, the low TDS collector tanks can be processed through a local bag filter and returned to the collector tanks. When the operator is ready to process the low TDS collector tanks, he selects the proper tank/pump combination, starts the pump, and, when ready to initiate processing, opens an air-operated valve located at the discharge of the low TDS collector tank pumps. The waste then flows to the radwaste building where it passes through a wye strainer and one of two low TDS filters. This strainer/filter combination extends filter cartridge life by removing all large particulates prior to the filters. The waste next flows to the SLW demineralizer, and processing is completed as described previously.
The radioactivity releases provided in Section 11.1 and Appendix 11.1.A are based on the analytical models of the GALE code and do not reflect the normal variations in the concentrations of radioactive isotopes in the secondary
If the SLW demineralizer is not available and the plant can be operated at one-half the maximum steam generator blowdown rate, the option exists to process the low TDS wastes via two of the steam generator blowdown demineralizers. If the operator chooses to discharge the low TDS wastes through the wastewater treatment system, the operator must isolate the flowpath to the radwaste building. The contents of the low TDS waste collector tank shall be sampled to ensure that the pH is between 2 and 12.5. The operator then chooses the proper tank and pump combination, starts the pump and begins discharge to the wastewater treatment system. The discharge line to the wastewater treatment facility is monitored by radioactivity monitor 1-HF-RE-95. The high radioactivity monitor shall close the isolation valve downstream of the monitor on a high radioactivity alarm to prevent discharge to the wastewater treatment facility. Abnormal Operation


If abnormally large amounts of nonradioactively contaminated drainage collect in the turbine building recyclable sumps, such as a fire deluge, then the SLW system can be bypassed completely and the water discharged via the oily waste discharge pipe.  
system which depend on the status of the fuel, primary-to-secondary leakage, operation of the steam generator blowdown system, and extent of removal of radioisotopes from secondary steam to the MSR and high pressure heater drains (which are recycled directly to the steam generators). 10.4-59 Rev. 10 WOLF CREEK It is estimated that the annual liquid volume released from the SLWS will be approximately 2,100,000 gallons (7,200 gallons per day with an 80-percent plant


System Releases  Liquid effluents from the SLWS may be recycled to the secondary system via the condenser or may be discharged to the environment.  
capacity factor). As described above, the releases would be on a batch basis from the SLW monitor tank. The discharge rate is 90 gpm (80 minutes per day) and the temperature less than 135 F. 10.4.10.3  Safety Evaluation The secondary liquid waste system is not a safety-related system.  


Prior to discharge to the environment, the effluent is isolated within the appropriate monitor tank. The tank contents are recirculated to assure that they are well mixed and then sampled to assure that the release would not exceed release limits. The discharge to the environment passes through a process radiation monitor, which automatically closes the discharge valve on high radioactivity. The method of processing secondary liquid wastes and whether to recycle or discharge the processed wastes depend on the radioactivity concentrations. The radioactivity content of the SLWS releases is limited, along with radioactivity in other liquid releases, so as not to exceed Offsite Dose Calculation Manual.  
10.4.10.4  Tests and Inspections Preoperational testing is performed as described in Chapter 14.0.  


The radioactivity releases provided in Section 11.1 and Appendix 11.1.A are based on the analytical models of the GALE code and do not reflect the normal variations in the concentrations of radioactive isotopes in the secondary system which depend on the status of the fuel, primary-to-secondary leakage, operation of the steam generator blowdown system, and extent of removal of radioisotopes from secondary steam to the MSR and high pressure heater drains (which are recycled directly to the steam generators). 10.4-59 Rev. 10 WOLF CREEK It is estimated that the annual liquid volume released from the SLWS will be approximately 2,100,000 gallons (7,200 gallons per day with an 80-percent plant capacity factor). As described above, the releases would be on a batch basis from the SLW monitor tank. The discharge rate is 90 gpm (80 minutes per day) and the temperature less than 135F. 10.4.10.3  Safety Evaluation  The secondary liquid waste system is not a safety-related system.
Continuous operation demonstrates the operability, performance, and structural and leaktight integrity of all system components.  
10.4.10.4  Tests and Inspections  Preoperational testing is performed as described in Chapter 14.0.
Continuous operation demonstrates the operability, performance, and structural and leaktight integrity of all system components.
10.4.10.5  Instrumentation Applications  The SLWS instrumentation is designed to facilitate automatic operation, remote control, and continuous indication of system parameters, as described in 10.4.10.2.3. 


10.4-60 Rev. 14 WOLF CREEKTABLE 10.4-1CONDENSER DESIGN DATA (Note 1)ItemType                                          Multipressure, 3-shellDesign duty, Btu/hr-total 3                  7.8696 x 109   shellsShell pressure w/80&deg;F circ.                  2.34/2.89/3.64  water, inches HgaWaterbox circulating flow, gpm                500,000 (Site A/E design value)Tubeside temperature rise, &deg;F                  31.5 Design pressure-shell                        Full vacuum to 15 psig Hotwell storage capacity -                    159,000   total 3 shells, gallonsDesign pressure-channel, psig                70 and full vacuum Number of tubes                              59,796 Tube material  Main bundle                                304 S.S.
10.4.10.5  Instrumentation Applications The SLWS instrumentation is designed to facilitate automatic operation, remote
 
control, and continuous indication of system parameters, as described in
 
10.4.10.2.3.
 
10.4-60 Rev. 14 WOLF CREEK TABLE 10.4-1CONDENSER DESIGN DATA (Note 1)
ItemType                                          Multipressure, 3-shell Design duty, Btu/hr-total 3                  7.8696 x 10 9   shellsShell pressure w/80&deg;F circ.                  2.34/2.89/3.64  water, inches HgaWaterbox circulating flow, gpm                500,000 (Site A/E design value)
Tubeside temperature rise, &deg;F                  31.5 Design pressure-shell                        Full vacuum to 15 psig
 
Hotwell storage capacity -                    159,000 total 3 shells, gallonsDesign pressure-channel, psig                70 and full vacuum
 
Number of tubes                              59,796
 
Tube material  Main bundle                                304 S.S.
Air cooler                                304 S.S.
Air cooler                                304 S.S.
Impingement area                          304 S.S.Surface area, sq. ft.                        900,000 Overall Shell dimensions, feetLPIPHP  Length                                    292929  Width                                      394551  Height                                    787878Number of tube passes                        1 Steam flow, 1b/hr   Normal                                    7,940,886   Maximum                                    8,270,751Circulating Water Temp, &deg;F   Design                                    80 Maximum                                    90Steam temperature, &deg;F   Normal (avg.)                              114 Maximum (without turbine bypass)          134 Maximum (with turbine bypass)              141                                                              Rev. 13 WOLF CREEK                         TABLE 10.4-1 (Sheet 2)Applicable codes and standards:              ASME Sect. VIII, Div. 1,                                              ANSI Standards, HEI                                              Standards for Steam Sur-                                             face CondensersEffluent oxygen content, ppb                  7Notes:1.The data in this table reflects the original engineering specificationfor the condenser. The data may not reflect actual operating values.                                                              Rev. 13 WOLF CREEK TABLE 10.4-2 MAIN CONDENSER AIR REMOVAL SYSTEM DESIGN DATA Component Description   Condenser Mechanical Vacuum Pumps     Quantity                          3     Type                              Rotary water ring Holding capacity                  35 SCFM @ 1" Hga Hogging capacity                  72 SCFM @ 5" Hga Speed                            435 rpm     Cooling water flow                630 gpm     Motor Data     Horsepower                        150     Speed                            1,800 rpm Electrical requirements          460 Volt, 60 Hz, 3     Seal Water Coolers     Quantity                          3     Type                              Straight tube Heat exchanged                    14,600 Btu/hr                                       Shell Side   Tube Side     Fluid                            Seal water    Service water     Total fluid entering              90 gpm        630 gpm     Design pressure, psig            150          250 Design temperature, F            300          300 Test pressure, psig              225          375     Piping and Valves     Material                          Carbon steel     Design temperature, F            175 Design pressure, psig            225     Charcoal bed adsorber and filters are described in Section     9.4.4.                                                         Rev. 5 WOLF CREEKTABLE 10.4-3CIRCULATING WATER SYSTEMCOMPONENT DESCRIPTIONCirculating Water Pumps Quantity                                        3 Type                                            Vertical, wet-pit Capacity, each (gpm)                            166,700 Total developed head at   normal operating level,    approx (ft)                                  74Circulating Water Piping (Power Block, above floor)  MaterialCarbon steel  Outside diameter, in.120 Type of interface    connectionFlanged  Code (pipe)AWWA-C201  Code (flange)AWWA-C207, Class D  Design pressure, psig70 at water boxes  Site interfaceNoneCirculating Water Piping (Power Block, below floor)MaterialCast-in-place concreteInside dimension, in.120 inches squareType of interfaceconnectionFlangedCode (pipe)ACICode (flange)AWWA-C207, Class DDesign pressure, psig85 at El. 1,970Site interfaceWelded jointCirculating Water Expansion Joints Type                                            Rubber  Design pressure, psig                          70 Design temperature, &deg;F                          125Circulating Water Valves Type                                            Butterfly Operator                                        Electric motor Design pressure, psig                          70 Design temperature, &deg;F                          125 Code                                            AWWA                                                                  Rev. 13 WOLF CREEK                         TABLE 10.4-3 (Sheet 2)Water Box Venting Pumps Quantity                                        3 Type                                            Rotary  Capacity, acfm (each pump)                      775  Suction pressure, inches Hg. abs                5Motor Horsepower50  Speed, rpm690  Design codeMSWater Box Venting Tank Quantity                                        1 Capacity, gal                                  700  Design pressure, min/max psig                  Full vacuum/15 Design temperature, &deg;F                          150 Design code                                    ASME Section VIIIVenting System Seal Tank Quantity                                        1 Capacity, gal                                  53 Design pressure, psig                          15 Design temperature, &deg;F                          150 Design code                                    ASME Section VIIICondenser Drain Pump Quantity                                        1 Type                                            Centrifugal  Capacity, gpm                                  900 Total head, feet                                88 Motor horsepower                                30 Design code                                    MSCooling Lake Type                                            Man-made Normal operating level (ft, MSL)                                    1,087 Capacity (acre-ft)                              111,280 Nominal surface area (acres) at normal operating level                    5,090                                                                  Rev. 13 WOLF CREEK                           TABLE 10.4-4             CONDENSATE DEMINERALIZER SYSTEM DESIGN DATADemineralizer Vessels       Quantity                            6       Design pressure, psig              700       Design temperature, &deg;F              140 Design flow per vessel, gpm        4,560        Diameter (I.D.)                    10'-6" Type                                Spherical-rubber linedRegeneration Equipment Cation regeneration tank Quantity                            1       Design pressure, psig              75 Design temperature, &deg;F              140 Diameter                            7'-6" Height                              13'-6" Type                                Vertical cylindrical-rubber lined Anion regeneration tank       Quantity                            1       Design pressure, psig              75 Design temperature, &deg;F              140 Diameter                            6'-6" Height                              11'-0" Type                                Vertical cylindrical-rubber lined Resin mixing and storage tank Quantity                            1       Design pressure, psig              75 Design temperature, &deg;F              140 Diameter                            7'-6" Height                              10'-6" Type                                Vertical cylindrical-rubber lined                                                            Rev. 12 WOLF CREEK                       TABLE 10.4-4 (Sheet 2)Acid day tank       Quantity                            1        Design pressure                    Atm.        Design temperature,&deg;F            100 Diameter                            3'-6"        Height                              6'-0"        Type                                Vertical cylindrical-                                              lined - High Bake PhenolicCaustic day tank       Quantity                            1        Design pressure                    Atm.       Design temperature, &deg;F              100       Diameter                            4'-0"        Height                              4'-6"        Type                                Vertical cylindrical-unlinedSluice water pump Quantity                            2 (one standby)       Type                                Centrifugal-inline Capacity, gpm                      320 Head, ft                            127Acid metering pump Quantity                            2 (one standby)       Type                                Positive displacement Capacity, gph                      210 Differential pressure, psi          65Caustic metering pump Quantity                            2 (one standby)        Type                                Positive displacment Capacity, gph                      280       Differential pressure, psi          65Waste collection tank Quantity                            1        Design pressure                    Atm.
Impingement area                          304 S.S.
Design temperature,&deg;F            140 Diameter                            3'-6"        Height                              5'-0"        Special feature                    Mounted in strainer                                                            Rev. 10 WOLF CREEK                       TABLE 10.4-4 (Sheet 3)Resin addition hopper       Quantity                            1       Diameter                            2'-0" Height                              2'-0" Capacity, ft3                      7 Design pressure                    Atm.
Surface area, sq. ft.                        900,000 Overall Shell dimensions, feetLPIPHP  Length                                    292929  Width                                      394551  Height                                    787878 Number of tube passes                        1
 
Steam flow, 1b/hr Normal                                    7,940,886 Maximum                                    8,270,751 Circulating Water Temp, &deg;F Design                                    80
 
Maximum                                    90 Steam temperature, &deg;F Normal (avg.)                              114
 
Maximum (without turbine bypass)          134
 
Maximum (with turbine bypass)              141                                                              Rev. 13 WOLF CREEK TABLE 10.4-1 (Sheet 2)
Applicable codes and standards:              ASME Sect. VIII, Div. 1,                                              ANSI Standards, HEI                                              Standards for Steam Sur-face CondensersEffluent oxygen content, ppb                  7 Notes:1.The data in this table reflects the original engineering specification for the condenser. The data may not reflect actual operating values.                                                              Rev. 13 WOLF CREEK TABLE 10.4-2 MAIN CONDENSER AIR REMOVAL SYSTEM DESIGN DATA Component Description Condenser Mechanical Vacuum Pumps Quantity                          3 Type                              Rotary water ring  
 
Holding capacity                  35 SCFM @ 1" Hga  
 
Hogging capacity                  72 SCFM @ 5" Hga  
 
Speed                            435 rpm Cooling water flow                630 gpm Motor Data Horsepower                        150 Speed                            1,800 rpm  
 
Electrical requirements          460 Volt, 60 Hz, 3 Seal Water Coolers Quantity                          3 Type                              Straight tube  
 
Heat exchanged                    14,600 Btu/hr Shell Side Tube Side Fluid                            Seal water    Service water Total fluid entering              90 gpm        630 gpm Design pressure, psig            150          250  
 
Design temperature, F            300          300  
 
Test pressure, psig              225          375 Piping and Valves Material                          Carbon steel Design temperature, F            175  
 
Design pressure, psig            225 Charcoal bed adsorber and filters are described in Section 9.4.4.
Rev. 5 WOLF CREEK TABLE 10.4-3 CIRCULATING WATER SYSTEM COMPONENT DESCRIPTION Circulating Water Pumps Quantity                                        3 Type                                            Vertical, wet-pit Capacity, each (gpm)                            166,700
 
Total developed head at normal operating level,    approx (ft)                                  74Circulating Water Piping (Power Block, above floor)  MaterialCarbon steel  Outside diameter, in.120 Type of interface    connectionFlanged  Code (pipe)AWWA-C201  Code (flange)AWWA-C207, Class D  Design pressure, psig70 at water boxes  Site interfaceNone Circulating Water Piping (Power Block, below floor)MaterialCast-in-place concreteInside dimension, in.120 inches square Type of interfaceconnectionFlangedCode (pipe)ACICode (flange)AWWA-C207, Class DDesign pressure, psig85 at El. 1,970Site interfaceWelded joint Circulating Water Expansion Joints Type                                            Rubber  Design pressure, psig                          70 Design temperature, &deg;F                          125 Circulating Water Valves
 
Type                                            Butterfly Operator                                        Electric motor Design pressure, psig                          70
 
Design temperature, &deg;F                          125
 
Code                                            AWWA                                                                  Rev. 13 WOLF CREEK TABLE 10.4-3 (Sheet 2)
Water Box Venting Pumps Quantity                                        3 Type                                            Rotary  Capacity, acfm (each pump)                      775  Suction pressure, inches Hg. abs                5Motor Horsepower50  Speed, rpm690  Design codeMS Water Box Venting Tank Quantity                                        1 Capacity, gal                                  700  Design pressure, min/max psig                  Full vacuum/15
 
Design temperature, &deg;F                          150 Design code                                    ASME Section VIIIVenting System Seal Tank Quantity                                        1 Capacity, gal                                  53 Design pressure, psig                          15
 
Design temperature, &deg;F                          150 Design code                                    ASME Section VIII Condenser Drain Pump
 
Quantity                                        1 Type                                            Centrifugal  Capacity, gpm                                  900 Total head, feet                                88 Motor horsepower                                30
 
Design code                                    MS Cooling Lake
 
Type                                            Man-made Normal operating level
 
(ft, MSL)                                    1,087
 
Capacity (acre-ft)                              111,280 Nominal surface area (acres)
 
at normal operating level                    5,090                                                                  Rev. 13 WOLF CREEK TABLE 10.4-4 CONDENSATE DEMINERALIZER SYSTEM DESIGN DATA Demineralizer Vessels Quantity                            6 Design pressure, psig              700 Design temperature, &deg;F              140 Design flow per vessel, gpm        4,560        Diameter (I.D.)                    10'-6" Type                                Spherical-rubber lined Regeneration Equipment
 
Cation regeneration tank
 
Quantity                            1 Design pressure, psig              75
 
Design temperature, &deg;F              140
 
Diameter                            7'-6" Height                              13'-6" Type                                Vertical cylindrical-
 
rubber lined Anion regeneration tank Quantity                            1 Design pressure, psig              75
 
Design temperature, &deg;F              140
 
Diameter                            6'-6" Height                              11'-0" Type                                Vertical cylindrical-
 
rubber lined Resin mixing and storage tank
 
Quantity                            1 Design pressure, psig              75
 
Design temperature, &deg;F              140
 
Diameter                            7'-6" Height                              10'-6" Type                                Vertical cylindrical-
 
rubber lined                                                            Rev. 12 WOLF CREEK TABLE 10.4-4 (Sheet 2)
Acid day tank Quantity                            1        Design pressure                    Atm.        Design temperature,&deg;F            100
 
Diameter                            3'-6"        Height                              6'-0"        Type                                Vertical cylindrical-                                              lined - High Bake Phenolic Caustic day tank Quantity                            1        Design pressure                    Atm.
Design temperature, &deg;F              100 Diameter                            4'-0"        Height                              4'-6"        Type                                Vertical cylindrical-
 
unlined Sluice water pump
 
Quantity                            2 (one standby)
Type                                Centrifugal-inline Capacity, gpm                      320
 
Head, ft                            127 Acid metering pump
 
Quantity                            2 (one standby)
Type                                Positive displacement Capacity, gph                      210
 
Differential pressure, psi          65 Caustic metering pump
 
Quantity                            2 (one standby)        Type                                Positive displacment Capacity, gph                      280 Differential pressure, psi          65 Waste collection tank
 
Quantity                            1        Design pressure                    Atm.
Design temperature,&deg;F            140
 
Diameter                            3'-6"        Height                              5'-0"        Special feature                    Mounted in strainer                                                            Rev. 10 WOLF CREEK TABLE 10.4-4 (Sheet 3)
Resin addition hopper Quantity                            1 Diameter                            2'-0" Height                              2'-0" Capacity, ft3                      7 Design pressure                    Atm.
Design temperature                  Amb.
Design temperature                  Amb.
Special feature                    Filling by eductor                                                         Rev. 0 WOLF CREEK TABLE 10.4-5                             CONDENSATE AND FEEDWATER SYSTEM COMPONENT FAILURE ANALYSIS Component          Failure Effect On Train       Failure Effect on System         Failure Effect on RCSCondensate pump    None. Condenser hotwells      Operation continues at full      None                   are interconnected.            capacity, using parallel pumps (condensate pump runout                                                   capacity is 50 percent). No. 1, 2, 3,      One train of No. 1, 2, 3,      Operation continues at reduced    None. No. 5 feedwater heater or 4 feedwater    and 4 feedwater heaters        capacity, using parallel          is designed to maintain heater            is shut down. Remaining      feedwater heaters. Load          normal outlet feedwater trains continue to operate. must not exceed that which        temperature under this con-                                                   is required to protect the        dition.                                                   Turbines from excessive exhaust flow. Heater drain      Extraction steam to both      Operation continues at re-        Reactor control system tank              No. 5 feedwater heaters        duced capacity.                  reduces reactor power to                   must be isolated. Drains                                        compensate for reduced feed-                   from Nos. 6 and 7 feed-                                          water temperature.                   water heaters are dumped                   to condenser. Heater drain      None. Parallel pump with      50 percent of HP feedwater        Reactor control system pump              condensate pumps have suf-    heater drains are dumped          reduces reactor power to                   ficient capacity to handle    to condenser.                    compensate for reduced feed-full load.                                                      water temperature. Steam generator    None. Two parallel trains    Operations may continue at        Reactor control system feedwater pump    are interconnected.            reduced capacity, using par-      reduces reactor power to                                                   allel pump if the reactor        compensate for reduced feed-                                                   does not trip. Steam gener-      water flow.
Special feature                    Filling by eductor Rev. 0 WOLF CREEK TABLE 10.4-5 CONDENSATE AND FEEDWATER SYSTEM COMPONENT FAILURE ANALYSIS Component          Failure Effect On Train Failure Effect on System Failure Effect on RCS Condensate pump    None. Condenser hotwells      Operation continues at full      None are interconnected.            capacity, using parallel  
ator feedwater pump runout                                                   capacity is 67 percent. No. 5, 6, or 7    One train is shut down. Operation continues at reduced Reactor control system feedwater heater  capacity, using parallel reduces reactor and generator  feedwater heaters. Load must output power to compensate  not exceed that which is for reduced feedwater  required to protect the temperature. Turbines from excessive exhaust flow.                                                                                                      Rev. 11 WOLF CREEK TABLE 10.4-6 CONDENSATE AND FEEDWATER SYSTEM DESIGN DATA   Main Feedwater Piping (Safety-Related Portion)   Power Rerate Flowrate, lb/hr 16,082,021 Design (VWO) flowrate, lb/hr 15,850,801  Number of lines 4  Nominal size, in. 14 Schedule 80  Design pressure, psig 1,185  Design temperature, F 450 Design code ASME Section III, Class 2  Seismic design Category I Feedwater Isolation Valves   Number per main feedwater line 1 Closing time, sec 5 (at normal operating conditions prior to receiving isolation signal)  Body design pressure, psig 1,950  Design temperature, F 450  Design code ASME Section III, Class 2  Seismic design Category I Feedwater Control Valves Number per main feedwater line 1  Closing time, sec 5 Design code ASME Section III, Class 3  Seismic design None   
 
pumps (condensate pump runout capacity is 50 percent).
No. 1, 2, 3,      One train of No. 1, 2, 3,      Operation continues at reduced    None. No. 5 feedwater heater or 4 feedwater    and 4 feedwater heaters        capacity, using parallel          is designed to maintain heater            is shut down. Remaining      feedwater heaters. Load          normal outlet feedwater  
 
trains continue to operate. must not exceed that which        temperature under this con-is required to protect the        dition.
Turbines from excessive
 
exhaust flow.
Heater drain      Extraction steam to both      Operation continues at re-        Reactor control system  
 
tank              No. 5 feedwater heaters        duced capacity.                  reduces reactor power to must be isolated. Drains                                        compensate for reduced feed-from Nos. 6 and 7 feed-                                          water temperature.
water heaters are dumped to condenser.
Heater drain      None. Parallel pump with      50 percent of HP feedwater        Reactor control system pump              condensate pumps have suf-    heater drains are dumped          reduces reactor power to ficient capacity to handle    to condenser.                    compensate for reduced feed-  
 
full load.                                                      water temperature.
Steam generator    None. Two parallel trains    Operations may continue at        Reactor control system feedwater pump    are interconnected.            reduced capacity, using par-      reduces reactor power to allel pump if the reactor        compensate for reduced feed-does not trip. Steam gener-      water flow.  
 
ator feedwater pump runout capacity is 67 percent. No. 5, 6, or 7    One train is shut down. Operation continues at reduced Reactor control system feedwater heater  capacity, using parallel reduces reactor and generator  feedwater heaters. Load must output power to compensate  not exceed that which is for reduced feedwater  required to protect the temperature. Turbines from excessive exhaust flow.                                                                                                      Rev. 11 WOLF CREEK TABLE 10.4-6 CONDENSATE AND FEEDWATER SYSTEM DESIGN DATA Main Feedwater Piping (Safety-Related Portion)
Power Rerate Flowrate, lb/hr 16,082,021 Design (VWO) flowrate, lb/hr 15,850,801  Number of lines 4  Nominal size, in. 14 Schedule 80  Design pressure, psig 1,185  Design temperature, F 450 Design code ASME Section III, Class 2  Seismic design Category I  
 
Feedwater Isolation Valves Number per main feedwater line 1 Closing time, sec 5 (at normal operating conditions prior to receiving isolation signal)  Body design pressure, psig 1,950  Design temperature, F 450  Design code ASME Section III, Class 2  Seismic design Category I Feedwater Control Valves  
 
Number per main feedwater line 1  Closing time, sec 5 Design code ASME Section III, Class 3  Seismic design None  
 
Rev. 24 WOLF CREEK TABLE 10.4-7 FEEDWATER ISOLATION SINGLE FAILURE ANALYSIS Component                              Failure Comments Main feedwater          Valve fails to close upon receipt      MFIV will close, providing control valve            of automatic signal (FIS)              adequate isolation to limit (MFCV) (1)                                                      high energy fluid addition Loss of power from one power          Valve fails closed upon loss supply                                of either train of power Main feedwater          Same as main feedwater control        Same as main feedwater control bypass control          valve                                  valve valve. MFBCV (1)
Main feedwater          Valve fails to close upon receipt      MF control valve and MF check isolation valve          of automatic signal (FIS)              valve close as required to (MFIV)                                                          isolate The MF control valve (and bypass control valve) serve to limit the addition of high energy fluid into the containment following a main feedwater line rupture inside the containment or a main steam line break Loss of power from one power          Valve fails closed upon loss of supply                                either train of power Main feedwater          Valve fails to close                  MFIV will close, providing check valve                                                    adequate isolation (1)  Valve is only required following pipe rupture of feedwater line inside containment or following a MSLB.
Rev. 0 WOLF CREEK TABLE 10.4-7 (Sheet 2)
Component                              Failure Comments Chemical addition        Valve fails to close upon receipt      Associated check valve will isolation valve          of automatic signal (FIS)              close, providing adequate isolation Loss of power for valve operation      Valve fails closed Chemical addition        Valve fails to close                  Chemical addition isolation check valve                                                    valve will close, providing adequate isolation Auxiliary feedwater      Valve fails to open properly          Remaining two intact steam check valve                                                    generators will provide adequate auxiliary feedwater Steam generator          No signal generated for protection    2-out-of 4 logic reverts to narrow range level      logic from one transmitter            2-out-of 3 logic, and protection (Four per steam                                                logic is generated by other generator)                                                      channel devices Loss of one of four logic              2-out-of 4 logic reverts to channels                              2-out-of 3 logic, and protection logic is gen-
 
erated by other channel devices Rev. 0 WOLF CREEK TABLE 10.4-8 MAIN FEEDWATER SYSTEM CONTROL, INDICATING, AND ALARM DEVICES Control Room                    Control Room Device            Indication/Control Local Alarm___
Flow rate (1)              Yes              No            Yes (1)Steam gener-ator level (narrow range)(2)                Yes              No            Yes Steam gener-ator level (wide range)              Yes              No            No Feedpump Speed                    Yes              No            Yes (1)    Steam flow - Feedwater flow mismatch
 
(2)    Four per steam generator - Involved in 2-out-of-4 logic to generate input to reactor trip, auxiliary feed pump start, turbine trip, and feedwater isolation signals.
Rev. 0 WOLF CREEK TABLE 10.4-9 STEAM GENERATOR BLOWDOWN SYSTEM MAJOR COMPONENT PARAMETERS Steam Generator Blowdown Discharge Pump Type                                Inline centrifugal Number                              2
 
Design temperature, F                200 Design pressure, psig                150 Process fluid                        Blowdown
 
Design flow, gpm                    270 Discharge head, ft                  290 Code                                Manufacturer's standard
 
Material                            Stainless steel Steam Generator Blowdown Regenerative Heat Exchanger
 
Type                                Two stacked, BFU, two pass shell/two pass U-tube
 
Installation                        Horizontal Number                              1 Eff. heat transfer area, ft 2        1,090 Fluid Tube                              Blowdown fluid Shell                              Condensate fluid
 
Design flow Tube, lb/hr                        140,000 Shell, lb/hr                      200,000
 
Design temperature, F Shell side                        400 Tube side                          600
 
Design pressure, psig Shell side                        700 Tube side                          300
 
Design codes                        TEMA R and ASME Section VIII Div I Materials
 
Tube                              Stainless steel Tubesheet                          Stainless steel Shell                              Carbon steel
 
Channel                            Carbon steel Rev. 0 WOLF CREEK TABLE 10.4-9 (Sheet 2)
Steam Generator Blowdown Surge Tank  Type Vertical cylindrical  Number 1 Capacity, gallons 2,065  Tank diameter, in. 78  Design pressure, psig 0.5 Design temperature, F 175  Material Carbon steel  Code ASME Section VIII, Div. I Steam Generator Blowdown Mixed-Bed Demineralizer  Type Flushable  Number 4  Design temperature, F 200 Design pressure, psig 300  Design pressure drop  (fouled condition), psi 20 @ 200 gpm Shell diameter, in. 60  Design flow, gpm 150  Decontamination factors  Cation (a) 100  Anion 100  Cs, Rb 2  Resin volume, ft 3 75  Material Stainless steel  Code ASME Section VIII, Div. I (a) Does not include Cs, Mo,  Y, Rb, Te Steam Generator Blowdown Filter (FBM03A & 03B)
* Type Disposable cartridge  Number 2  Design pressure, psig 300  Design temperature, F 250 Design flow, gpm 250  Pressure drop  (250 gpm, clean), psi 5 Pressure drop  (fouled condition), psi 20  Particle retention 98% (min) of 30 micron size (max)*
Material (vessel) Stainless steel Code ASME Section VIII, Div. I
*Standard filter cartridges are available with variable particle retention characteristics, and the selection of the filter cartridge is based on operating data.
Rev. 18 WOLF CREEK TABLE 10.4-9 (Sheet 3)
Steam Generator Drain Pump Type                                Inline centrifugal Number                              2
 
Rated flow, gpm                      100 Rated total dynamic head, ft        372 Design pressure, psig                150
 
Design temperature, F                150 Design code                          Manufacturer's standard Material                            Stainless steel Steam Generator Blowdown Nonregenerative Heat Exchanger Type                                BFU two pass shell 4 pass-tube Installation                        Horizontal
 
Number                              1 Eff. heat transfer area, ft 2        682.5 Flow, continuous max., gpm          270 Fluid Shell side                        Service water Tube side                          Blowdown fluid
 
Design temperature, F Shell side                        150 Tube side                          600
 
Design pressure, psig Shell side                        200 Tube side                          300
 
Design code                          ASME Section VIII Div. I,                                              TEMA-R Materials
 
Tube                              Stainless steel Shell                              Carbon steel Tubesheet                          Stainless Steel
 
Channel                            Carbon steel Steam Generator Blowdown Flash Tank
 
Type                                Vertical Number                              1
 
Volume, gallons                      2,350 Vessel diameter, in.                72 Design temperature, F                425
 
Design pressure, psig                300 Material                            Stainless steel Code                                ASME Section VIII, Div. I
* If greater than 5% of the tubes have been plugged heat transfer value will be less than this value. .                                                              Rev. 18 WOLF CREEK TABLE 10.4-10 STEAM GENERATOR BLOWDOWN SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component                Failure Comments Blowdown isolation      Loss of power from        Redundant power valves                one power supply          supply provided Valve fails to close      Closure of three upon receipt of auto-      out of four isolation matic signal (SLIS)        valves adequate to
 
meet safety re-quirements (Refer to Section 10.4.8.2.2)
Sample isolation        Loss of power from        Valves fail closed valves                one power supply          upon loss of power Valve fails to close      Closure of three out upon receipt of auto-      of four isolation matic signal              valves adequate to meet safety re-
 
quirements Rev. 0 WOLF CREEK TABLE 10.4-11 STEAM GENERATOR BLOWDOWN SYSTEM CONTROL, INDICATING AND ALARM DEVICES
 
Radwaste Building Control          Main Control        Main Room                Room      Control Room
 
Device                Control/Indication Indication Alarm___
 
Blowdown flash
 
tank level                    X                              X (1)
Blowdown flash
 
tank pressure                  X Surge tank level              X                              X (1)
 
Blowdown flow                  X                  X
 
Blowdown liquid high temperature              X                              X (1)
 
Blowdown liquid radiation monitor              X (alarm)          X          X
 
Surge tank discharge radiation monitor              X (alarm)          X          X
 
Blowdown conductivity monitor                        X                              X (1)
 
(1) Common alarm window on main control board.


Rev. 24 WOLF CREEK                                          TABLE 10.4-7                            FEEDWATER ISOLATION SINGLE FAILURE ANALYSISComponent                              Failure                            CommentsMain feedwater          Valve fails to close upon receipt      MFIV will close, providingcontrol valve            of automatic signal (FIS)              adequate isolation to limit(MFCV) (1)                                                      high energy fluid addition                        Loss of power from one power          Valve fails closed upon loss                        supply                                of either train of powerMain feedwater          Same as main feedwater control        Same as main feedwater controlbypass control          valve                                  valvevalve. MFBCV (1)Main feedwater          Valve fails to close upon receipt      MF control valve and MF checkisolation valve          of automatic signal (FIS)              valve close as required to(MFIV)                                                          isolate                                                                The MF control valve (and bypass                                                                control valve) serve to limit the                                                                addition of high energy fluid into                                                                the containment following a main                                                                feedwater line rupture inside the                                                                containment or a main steam line                                                                break                        Loss of power from one power          Valve fails closed upon loss of                        supply                                either train of powerMain feedwater          Valve fails to close                  MFIV will close, providingcheck valve                                                    adequate isolation(1)  Valve is only required following pipe rupture of feedwater line inside    containment or following a MSLB.                                                                                            Rev. 0 WOLF CREEK                                      TABLE 10.4-7 (Sheet 2)Component                              Failure                            CommentsChemical addition        Valve fails to close upon receipt      Associated check valve willisolation valve          of automatic signal (FIS)              close, providing adequate                                                                isolation                        Loss of power for valve operation      Valve fails closedChemical addition        Valve fails to close                  Chemical addition isolationcheck valve                                                    valve will close, providing                                                                adequate isolationAuxiliary feedwater      Valve fails to open properly          Remaining two intact steamcheck valve                                                    generators will provide                                                                adequate auxiliary feedwaterSteam generator          No signal generated for protection    2-out-of 4 logic reverts tonarrow range level      logic from one transmitter            2-out-of 3 logic, and protection(Four per steam                                                logic is generated by othergenerator)                                                      channel devices                        Loss of one of four logic              2-out-of 4 logic reverts to                        channels                              2-out-of 3 logic, and                                                                protection logic is gen-erated by other channel                                                                devices                                                                                            Rev. 0 WOLF CREEK                              TABLE 10.4-8                          MAIN FEEDWATER SYSTEM                  CONTROL, INDICATING, AND ALARM DEVICES                    Control Room                    Control RoomDevice            Indication/Control      Local          Alarm___Flow rate(1)              Yes              No            Yes(1)Steam gener-ator level (narrowrange)(2)                Yes              No            YesSteam gener-ator level (wide range)              Yes              No            NoFeedpumpSpeed                    Yes              No            Yes(1)    Steam flow - Feedwater flow mismatch (2)    Four per steam generator - Involved in 2-out-of-4 logic to      generate input to reactor trip, auxiliary feed pump start, turbine trip, and feedwater isolation signals.                                                          Rev. 0 WOLF CREEK                                TABLE 10.4-9                      STEAM GENERATOR BLOWDOWN SYSTEM                        MAJOR COMPONENT PARAMETERS Steam Generator Blowdown Discharge Pump      Type                                Inline centrifugal      Number                              2 Design temperature, F                200      Design pressure, psig                150      Process fluid                        Blowdown Design flow, gpm                    270      Discharge head, ft                  290      Code                                Manufacturer's standard Material                            Stainless steel Steam Generator Blowdown Regenerative Heat Exchanger Type                                Two stacked, BFU, two pass                                              shell/two pass U-tube Installation                        Horizontal      Number                              1      Eff. heat transfer area, ft2        1,090      Fluid        Tube                              Blowdown fluid        Shell                              Condensate fluid Design flow        Tube, lb/hr                        140,000        Shell, lb/hr                      200,000 Design temperature, F        Shell side                        400        Tube side                          600 Design pressure, psig        Shell side                        700        Tube side                          300 Design codes                        TEMA R and ASME Section VIII                                              Div I      Materials Tube                              Stainless steel        Tubesheet                          Stainless steel        Shell                              Carbon steel Channel                            Carbon steel                                                              Rev. 0 WOLF CREEK                          TABLE 10.4-9 (Sheet 2) Steam Generator Blowdown Surge Tank  Type Vertical cylindrical  Number 1 Capacity, gallons 2,065  Tank diameter, in. 78  Design pressure, psig 0.5 Design temperature, F 175  Material Carbon steel  Code ASME Section VIII, Div. I Steam Generator Blowdown Mixed-Bed Demineralizer  Type Flushable  Number 4  Design temperature, F 200 Design pressure, psig 300  Design pressure drop  (fouled condition), psi 20 @ 200 gpm Shell diameter, in. 60  Design flow, gpm 150  Decontamination factors  Cation (a) 100  Anion 100  Cs, Rb 2  Resin volume, ft3 75  Material Stainless steel  Code ASME Section VIII, Div. I (a) Does not include Cs, Mo,  Y, Rb, Te Steam Generator Blowdown Filter (FBM03A & 03B)* Type Disposable cartridge  Number 2  Design pressure, psig 300  Design temperature, F 250 Design flow, gpm 250  Pressure drop  (250 gpm, clean), psi 5 Pressure drop  (fouled condition), psi 20  Particle retention 98% (min) of 30 micron size (max)*
Material (vessel) Stainless steel  Code ASME Section VIII, Div. I *Standard filter cartridges are available with variable particle retention characteristics, and the selection of the filter cartridge is based on operating data. Rev. 18 WOLF CREEK TABLE 10.4-9 (Sheet 3) Steam Generator Drain Pump      Type                                Inline centrifugal      Number                              2 Rated flow, gpm                      100      Rated total dynamic head, ft        372      Design pressure, psig                150 Design temperature, F                150      Design code                          Manufacturer's standard      Material                            Stainless steel Steam Generator Blowdown Nonregenerative Heat Exchanger      Type                                BFU two pass shell 4 pass-                                              tube      Installation                        Horizontal Number                              1      Eff. heat transfer area, ft2        682.5      Flow, continuous max., gpm          270      Fluid        Shell side                        Service water        Tube side                          Blowdown fluid Design temperature, F        Shell side                        150        Tube side                          600 Design pressure, psig        Shell side                        200        Tube side                          300 Design code                          ASME Section VIII Div. I,                                              TEMA-R      Materials Tube                              Stainless steel        Shell                              Carbon steel        Tubesheet                          Stainless Steel Channel                            Carbon steel Steam Generator Blowdown Flash Tank Type                                Vertical      Number                              1 Volume, gallons                      2,350      Vessel diameter, in.                72      Design temperature, F                425 Design pressure, psig                300      Material                            Stainless steel      Code                                ASME Section VIII, Div. I
* If greater than 5% of the tubes have been plugged heat transfer value will be less than this value. .                                                              Rev. 18 WOLF CREEK                              TABLE 10.4-10                    STEAM GENERATOR BLOWDOWN SYSTEM                      SINGLE ACTIVE FAILURE ANALYSIS  Component                Failure                    CommentsBlowdown isolation      Loss of power from        Redundant power  valves                one power supply          supply provided                        Valve fails to close      Closure of three                        upon receipt of auto-      out of four isolation                        matic signal (SLIS)        valves adequate to meet safety re-                                                  quirements                                                  (Refer to Section                                                  10.4.8.2.2)Sample isolation        Loss of power from        Valves fail closed  valves                one power supply          upon loss of power                        Valve fails to close      Closure of three out                        upon receipt of auto-      of four isolation                        matic signal              valves adequate to                                                  meet safety re-quirements                                                            Rev. 0 WOLF CREEK TABLE 10.4-11  STEAM GENERATOR BLOWDOWN SYSTEM CONTROL, INDICATING AND ALARM DEVICES Radwaste Building                            Control          Main Control        Main                              Room                Room      Control Room Device                Control/Indication    Indication        Alarm___
Blowdown flash tank level                    X                              X (1)  Blowdown flash tank pressure                  X  Surge tank level              X                              X (1)
Blowdown flow                  X                  X Blowdown liquid high temperature              X                              X (1)
Blowdown liquid radiation monitor              X (alarm)          X          X Surge tank discharge radiation monitor              X (alarm)          X          X Blowdown conductivity monitor                        X                              X (1) 
(1) Common alarm window on main control board.
X denotes that indicating device is provided.  
X denotes that indicating device is provided.  


Rev. 19 WOLF CREEK TABLE 10.4-12 AUXILIARY FEEDWATER SYSTEM COMPONENT DATA   Motor-Driven Auxiliary Feedwater Pump (per pump)       Quantity                      2 Type                          Horizontal centrifugal, multistage,                                    split case with packing      Capacity, gpm (each)          575 TDH, ft                        3,200      NPSH required, ft              17      NPSH available, ft (min)      28 Material Case                          Alloy steel      Impellers                      Stainless steel      Shaft                          Stainless steel Design code                    ASME Section III, Class 3      Seismic design                Category I Driver      Type                          Electric motor Horsepower, hp                800      Rpm                            3,600      Power supply                  4, 160 V, 60 Hz, 3-phase Class 1E      Design code                    NEMA      Seismic design                Category I  Turbine-Driven Auxiliary Feedwater Pump Quantity                      1      Type                          Horizontal centrifugal, multistage,                                    split case with packing Capacity, gpm                  1,145      TDH, ft                        3,450      NPSH required, ft              17 NPSH available ft (min)        27 Material Case                          Alloy steel      Impellers                      Stainless steel Shaft                          Stainless steel 
Rev. 19 WOLF CREEK TABLE 10.4-12 AUXILIARY FEEDWATER SYSTEM COMPONENT DATA Motor-Driven Auxiliary Feedwater Pump (per pump)
Quantity                      2  


Rev. 13 WOLF CREEK                          TABLE 10.4-12 (Sheet 2)        Design code                    ASME Section III, Class 3      Driver Type                          Noncondensing, single stage,                                    mechanical-drive steam turbine      Rpm                            3,850 Horsepower, hp                1,590      Design code                    NEMA      Seismic design                Category I Motor-Driven Pump Control Valves Quantity                      4 (2 per pump)     Type                          Motor-operated globe valve      Size, in.                      4 CV                            50      Design pressure, psig          1,800      Design temperature, F          150 Material                      Carbon steel      Design Code                    ASME Section III      Seismic Design                Category I Turbine-Driven Pump Control Valves Quantity                      4      Type                          Air-operated globe valve      Size, in.                      4 CV                            50      Design pressure, psig          2,000      Design temperature, F          150 Material                      Carbon steel      Design Code                    ASME Section III      Seismic Design                Category I Turbine Driven Auxiliary Feedwater Pump Standby Water Accumulator Tanks Quantity 3  Type Cylindrical with dished heads  Capacity 300 gallons Manufacturer Joseph Oat Corporation  Seismic Category 1 Weight 2500 lbs. Design Code ASME Section III, Class 3     
Type                          Horizontal centrifugal, multistage,                                    split case with packing Capacity, gpm (each)           575


Rev. 26 WOLF CREEK TABLE 10.4-13  AUXILIARY FEEDWATER SYSTEM SINGLE ACTIVE FAILURE ANALYSIS  Component                        Failure                                Comments  Suction isolation      In the event that the CST is un-      Redundant nonreturn check valves from CST        available, valve fails to close        valve is provided, and suffi-upon receipt of automatic isola-       cient ESW flow is provided to tion signal or loss of power          the auxiliary feedwater pumps.
TDH, ft                        3,200 NPSH required, ft              17 NPSH available, ft (min)       28


Suction isola-        In the event that the CST is un-      Two 100-percent redundant tion valves from      available, valve fails to open upon    backup ESW trains are pro-ESW                    receipt of automatic signal or loss    vided. Operation of one train of power                              of the suction valves meet the requirements.
Material


Suction header        Loss of one transmitter. No pro-      2-out-of-3 logic reverts to pressure trans-        tection logic generated                1-out-of-2 logic, and protec- mitters                                                      tion logic is generated by                                                              other devices.
Case                          Alloy steel Impellers                      Stainless steel Shaft                          Stainless steel


Motor-driven auxi-    Fails to start on automatic signal    Two motor-driven pumps are liary feedwater                                              provided. One pump is suf-pump                                                          ficient to meet decay heat removal requirements. If due to a main steam or feed-water line break, the oper-ating motor-driven pump can-not supply two intact steam generators, the turbine-driven pump will supply feedwater                                                              to meet decay heat removal                                                              requirements.
Design code                    ASME Section III, Class 3 Seismic design                Category I
Turbine-driven        Fails to open on automatic signal      Parallel connections are pro-pump steam supply                                            vided on two main steam lines.
valve from main                                              One of the two valves will steam header                                                  supply 100 percent of the turbine steam requirements. Rev. 25 WOLF CREEK TABLE 10.4-13 (Sheet 2)
Component                        Failure                                Comments Turbine-driven        Failure resulting in loss of func-    Two motor-driven pumps are pump                  tion                                  provided. Either will pro-                                                              vide 100 percent of the feed-                                                              water requirements for decay heat  removal during plant normal cooldown.
Motor-driven pump      Failure resulting in loss of flow      The second motor-driven pump control valve          or loss of flow control                will provide 100 percent of the required flow through separate control valves.
If due to a main steam or feedwater line break, the operational motor-driven pump train cannot supply two intact                                                              steam generators, the turbine-driven pump will supply                                                              feedwater to meet decay heat                                                              removal requirements.


Failure to close valve in line feed-  Second motor-driven ing broken loop                        pump will provide 100 percent required flow through separate control valves.
Driver Type                          Electric motor  


Turbine-driven        Failure resulting in loss of flow      Either of the two motor-driven pump control valve    or loss of flow control                pumps will supply 100 percent of the required feedwater flow                                                               through separate control                                                               valves.                         Failure to close valve inline feed-    Either of the two motor-ing broken loop                        driven pumps will supply 100 percent required flow through separate control valves. Rev. 11 WOLF CREEK TABLE 10.4-13 (Sheet 3) Non-return check Fails to close Redundant non-return check valve (ALV0161) and air valve ALV0001  release vacuum breaker check valve (ALV0167) are provided. ALV0161 is considered passive for a "loss of offsite power with a concurrent loss of the CST"   event because the valve is normally closed by gravity   and is not required to have discernable   mechanical motion. AV0167 is considered active   for this event and passive for all other events. The design of the valve requires water flow to raise the float to stop the flow. The float is normally in the neutral position so air can flow in response to system conditions. The valve is mounted above the overflow of the CST. Water will be below the valve inlet. The float is considered passive for all other events.    
Horsepower, hp                800 Rpm                            3,600 Power supply                  4, 160 V, 60 Hz, 3-phase
 
Class 1E Design code                    NEMA Seismic design                Category I Turbine-Driven Auxiliary Feedwater Pump
 
Quantity                      1 Type                          Horizontal centrifugal, multistage,                                    split case with packing
 
Capacity, gpm                  1,145 TDH, ft                        3,450 NPSH required, ft              17
 
NPSH available ft (min)        27
 
Material
 
Case                          Alloy steel Impellers                      Stainless steel
 
Shaft                          Stainless steel
 
Rev. 13 WOLF CREEK TABLE 10.4-12 (Sheet 2)
Design code                    ASME Section III, Class 3 Driver
 
Type                          Noncondensing, single stage,                                    mechanical-drive steam turbine Rpm                            3,850
 
Horsepower, hp                1,590 Design code                    NEMA Seismic design                Category I
 
Motor-Driven Pump Control Valves
 
Quantity                      4 (2 per pump)
Type                          Motor-operated globe valve Size, in.                      4
 
CV                            50 Design pressure, psig          1,800 Design temperature, F          150
 
Material                      Carbon steel Design Code                    ASME Section III Seismic Design                Category I
 
Turbine-Driven Pump Control Valves
 
Quantity                      4 Type                          Air-operated globe valve Size, in.                      4
 
CV                            50 Design pressure, psig          2,000 Design temperature, F          150
 
Material                      Carbon steel Design Code                    ASME Section III Seismic Design                Category I
 
Turbine Driven Auxiliary Feedwater Pump Standby Water Accumulator Tanks
 
Quantity 3  Type Cylindrical with dished heads  Capacity 300 gallons Manufacturer Joseph Oat Corporation  Seismic Category 1 Weight 2500 lbs. Design Code ASME Section III, Class 3
 
Rev. 26 WOLF CREEK
 
TABLE 10.4-13 AUXILIARY FEEDWATER SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component                        Failure Comments Suction isolation      In the event that the CST is un-      Redundant nonreturn check valves from CST        available, valve fails to close        valve is provided, and suffi-
 
upon receipt of automatic isola-      cient ESW flow is provided to
 
tion signal or loss of power          the auxiliary feedwater pumps.
 
Suction isola-        In the event that the CST is un-      Two 100-percent redundant
 
tion valves from      available, valve fails to open upon    backup ESW trains are pro-
 
ESW                    receipt of automatic signal or loss    vided. Operation of one train
 
of power                              of the suction valves meet
 
the requirements.
 
Suction header        Loss of one transmitter. No pro-      2-out-of-3 logic reverts to
 
pressure trans-        tection logic generated                1-out-of-2 logic, and protec-mitters                                                      tion logic is generated by other devices.
 
Motor-driven auxi-    Fails to start on automatic signal    Two motor-driven pumps are
 
liary feedwater                                              provided. One pump is suf-
 
pump                                                          ficient to meet decay heat
 
removal requirements. If
 
due to a main steam or feed-
 
water line break, the oper-
 
ating motor-driven pump can-
 
not supply two intact steam
 
generators, the turbine-driven
 
pump will supply feedwater to meet decay heat removal requirements.
 
Turbine-driven        Fails to open on automatic signal      Parallel connections are pro-
 
pump steam supply                                            vided on two main steam lines.
 
valve from main                                              One of the two valves will
 
steam header                                                  supply 100 percent of the
 
turbine steam requirements.
Rev. 25 WOLF CREEK
 
TABLE 10.4-13 (Sheet 2)
 
Component                        Failure Comments
 
Turbine-driven        Failure resulting in loss of func-    Two motor-driven pumps are pump                  tion                                  provided. Either will pro-vide 100 percent of the feed-water requirements for decay heat removal during plant normal cooldown.
 
Motor-driven pump      Failure resulting in loss of flow      The second motor-driven pump
 
control valve          or loss of flow control                will provide 100 percent of
 
the required flow through
 
separate control valves.
 
If due to a main steam or
 
feedwater line break, the
 
operational motor-driven pump
 
train cannot supply two intact steam generators, the turbine-
 
driven pump will supply feedwater to meet decay heat removal requirements.
 
Failure to close valve in line feed-  Second motor-driven
 
ing broken loop                        pump will provide 100 percent
 
required flow through separate
 
control valves.
 
Turbine-driven        Failure resulting in loss of flow      Either of the two motor-driven  
 
pump control valve    or loss of flow control                pumps will supply 100 percent  
 
of the required feedwater flow through separate control valves.
Failure to close valve inline feed-    Either of the two motor-  
 
ing broken loop                        driven pumps will supply 100  
 
percent required flow through  
 
separate control valves.
Rev. 11 WOLF CREEK  
 
TABLE 10.4-13 (Sheet 3)
Non-return check Fails to close Redundant non-return check valve (ALV0161) and air valve ALV0001  release vacuum breaker check valve (ALV0167) are provided. ALV0161 is considered passive for a "loss of offsite power with a concurrent loss of the CST" event because the valve is normally closed by gravity and is not required to have discernable mechanical motion. AV0167 is considered active for this event and passive for all other events.
The design of the valve requires water flow to raise the float to stop the flow. The float is normally in the neutral position so air can flow in response to system conditions. The valve is mounted above the overflow of the CST. Water will be below the valve inlet. The float is considered passive for all other events.  


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Rev. 26 WOLF CREEK&+,/1.3*6*-%3+3+25.1*+&,-5%*6*-%35*6*-%.'6+*&(0.**+)%
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WOLF CREEK TABLE 10.4-13B DESIGN COMPARISONS TO NRC RECOMMENDATIONS ON AUXILIARY FEEDWATER SYSTEMS CONTAINED IN THE MARCH 10, 1980 NRC LETTER A. SHORT-TERM RECOMMENDATIONS                                          WCGS POSITION     1. Recommendation GS The licensee should        The limiting conditions for operation re-         propose modifications to the Technical          lated to the auxiliary feedwater system are         Specifications to limit the time that one        addressed in the Technical Specifications.         auxiliary feedwater system pump and its         associated flow train and essential         instrumentation can be inoperable. The outage         time limit and subsequent action time should         be as required in current Technical         Specifications; i.e., 72 hours and 12 hours,          respectively.     2. Recommendation GS The licensee should        This item is not applicable to WCGS because         lock open single valves or multiple valves      the design does not include single valves or         in series in the auxiliary feedwater system      multiple valves in series that could interrupt         pump suction piping and lock open other          auxiliary feedwater pump suction or all         single valves or multiple valves in series      auxiliary feedwater flow.         that could interrupt all auxiliary feedwater system flow. Monthly inspections should be         performed to verify that these valves are         locked and in the open position. These inspections should be proposed for         incorporation into the surveillance         requirements of the plant Technical Specifications. See Recommendation GL-2 for         the longer-term resolution of this concern.     3. Recommendation GS The licensee has          Throttling auxiliary feedwater flow to avoid         stated that it throttles auxiliary feed-        water hammer is not utilized. The system         water flow to avoid water hammer. The          design precludes the occurrence of water hammer         licensee should reexamine the practice          in the steam generator inlet, as described in         of throttling auxiliary feedwater                Section 10.4.7.2.1. Rev. 10 WOLF CREEK                                         TABLE 10.4-13B (Sheet 2) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     3. system flow to avoid water hammer.         The licensee should verify that the         auxiliary feedwater system will supply on demand sufficient initial         flow to the necessary steam genera-         tors to assure adequate decay heat removal following loss of main         feedwater flow and a reactor trip         from 100 percent power. In cases where this reevaluation results in         an increase in initial auxiliary         feedwater system flow, the licensee should provide sufficient informa-         tion to demonstrate that the         required initial auxiliary feed-water system flow will not result         in plant damage due to water hammer.     4. Recommendation GS Emergency                        The WCGS design includes an automatic         procedures for transferring to                        transfer to the alternate sources of         alternate sources of auxiliary                        supply. Procedures provide guidance         feedwater system supply should be                      to the operator concerning alternate         available to the plant operators.                      water sources.         These procedures should include criteria to inform the operator                        The normal supply from the condensate         when, and in what order, the                          storage tank (CST) is through a locked-         transfer to alternate water sources                    open, butterfly valve. Periodic sur-should take place. The following                      veillance verifies valve position.         cases should be covered by the         procedures:                                                                                             Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 3) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)         (1)  The case in which the primary water              Opening of valves from the backup ESWS               supply is not initially available.              and starting of auxiliary feedwater pumps               The procedures for this case should              are timed such that an AFWS start with include any operator actions required            no suction from the CST is not a mode for               to protect the auxiliary feedwater              common failure of all auxiliary feedwater               system pumps against self-damage                pumps.
WOLF CREEK TABLE 10.4-13B DESIGN COMPARISONS TO NRC RECOMMENDATIONS ON AUXILIARY FEEDWATER SYSTEMS CONTAINED IN THE MARCH 10, 1980 NRC LETTER A. SHORT-TERM RECOMMENDATIONS                                          WCGS POSITION
before water flow is initiated.         (2)  The case in which the primary water               supply is being depleted. The pro-               cedure for this case should provide               for transfer to the alternate water sources prior to draining of the pri-               mary water supply.     5. Recommendation GS The as-built plant              The turbine-driven pump in the WCGS         should be capable of providing the                    design is capable of being auto-         required auxiliary feedwater system flow              matically initiated and operated         for at least 2 hours from any one                    independent of any alternating         auxiliary feedwater pump train, indepen-              current power source for at         dent of any alternating current power                least 2 hours. Essential con-source. If manual auxiliary feedwater                trols, valve operators, other         system initiation or flow control is                  supporting systems, and turbine         required following a complete loss of                lube oil cooling for the turbine-alternating current power, emergency                  driven pump are all independent         procedures should be established for                  of alternating current power.         manually initiating and controlling the system under these conditions. Since         the water for cooling of the lube oil for         the turbine-driven pump bearings may be dependent on alternating current power,                                                                                          Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 4) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     5. design or procedural changes         shall be made to eliminate this         dependency as soon as practicable.
: 1. Recommendation GS The licensee should        The limiting conditions for operation re-propose modifications to the Technical          lated to the auxiliary feedwater system are Specifications to limit the time that one        addressed in the Technical Specifications.
Until this is done, the emergency         procedures should provide for an         individual to be stationed at the turbine-driven pump in the event         of loss of all alternating cur-         rent power to monitor pump bearing and/or lube oil temperatures. If         necessary, this operator would         operate the turbine-driven pump in a manual on-off mode until         alternating current power is re-         stored. Adequate lighting powered by direct current power sources         and communications at local sta-         tions should also be provided if manual initiation and control of         the auxiliary feedwater system is         needed. See Recommendation GL-3 for the longer-term resolution of         this concern.     6. Recommendation GS The licensee                    Valve lineups and independent second         should confirm flow path                              operator verification of valve lineups         availabiity of an auxiliary                          is required on the auxiliary feedwater         feedwater system flow train that                      system after maintenance. Verification         has been out of service to perform                    of operability is included as part of         periodic testing or maintenance as                    functional testing on return from ex-follows:                                              tended cold shutdown.          - Procedures should be implemented           to require an operator to determine                                                                                               Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 5) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     6. that the auxiliary feedwater             system valves are properly             aligned and a second operator to independently verify that the             valves are properly aligned.             The licensee should propose             Technical Specifications to             assure that prior to plant startup following an extended             cold shutdown, a flow test would             be performed to verify the normal flow path from the             primary auxiliary feedwater             system water source to the steam generators. The flow test             should be conducted with             auxiliary feedwater system valves in their normal             alignment.     7. Recommendation GS The licensee                    The WCGS auxiliary feedwater system         should verify that the automatic                      is designed so that automatic         start auxiliary feedwater system                      initiation signals and circuits         signals and associated circuitry                      are redundant and meet safety-         are safety grade. If this cannot                      grade requirements. Refer to         be verified, the auxiliary system                      Section 7.3.6.
auxiliary feedwater system pump and its associated flow train and essential instrumentation can be inoperable. The outage time limit and subsequent action time should be as required in current Technical Specifications; i.e., 72 hours and 12 hours,          respectively.
automatic initiation system should         be modified in the short-term to         meet the functional requirements listed below. For the longer term,          the automatic initiation signals                                                                                             Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 6) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     7. and circuits should be upgraded         to meet safety-grade requirements         as indicated in Recommendation GL-5.         (1)  The design should provide for               the automatic initiation of               the auxiliary feedwater system               flow.         (2)  The automatic initiation               signals and circuits should be designed so that a single               failure will not result in the               loss of auxiliary feedwater system function.         (3)  Testability of the initiation               signal and circuits shall be a               feature of the design.         (4)  The initiation signals and               circuits should be powered               from the emergency buses.         (5)  Manual capability to initiate               the auxiliary feedwater system from the control room should               be implemented so that a               single failure in the manual               circuits will not result in               the loss of system function.                                                                                             Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 7) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     7.  (6)  The alternating current motor-driven               pumps and valves in the auxiliary               feedwater system should be included in the automatic actuation (simul-               taneous and/or sequential) of the               loads to the emergency buses.           (7)  The automatic initiation signals and               circuits shall be designed so that their failure will not result in the               loss of manual capability to initiate               the auxiliary feedwater system from the control room.     8. Recommendation GS  The licensee should        See response to GS-7 above.         install a system to automatically initiate           auxiliary feedwater system flow. This           system need not be safety grade; however,          in the short term, it should meet the           criteria listed below, which are similar to           Item 2.1.7.a of NUREG-0578. For the longer term, the automatic initiation signals and           circuits should be upgraded to meet safety-           grade requirements; as indicated in Recommendation GL-2.           (1)  The design should provide for the               automatic initiation of the auxiliary               feedwater system flow.           (2)  The automatic initiation signal and               circuits should be designed so that               a single failure will not result in the loss of auxiliary feedwater system function.                      Rev. 1 WOLF CREEK                                         TABLE 10.4-13B (Sheet 8) A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)     8.  (3)  Testability of the initiating               signals and circuits should be               a feature of the design.           (4)  The initiating signals and circuits               should be powered from the emergency buses.           (5)  Manual capability to initiate               the auxiliary feedwater system               from the control room should be               retained and should be implemented so that a single failure in the               manual circuits will not result               in the loss of system function.           (6)  The alternating current powered               motor-driven pumps and valves in the auxiliary feedwater system should               be included in the automatic actua-               tion (simultaneous and/or sequen-tial) of the loads to the emergency               buses.           (7)  The automatic initiation signals and               circuits should be designed so that               their failure will not result in the loss of manual capability to               initiate the auxiliary feedwater sys-               tem from the control room. B. ADDITIONAL SHORT-TERM RECOMMENDATIONS       1. Recommendation - The licensee should provide          The existing WCGS design provides the         redundant level indication and low-level              following redundant control room indica-         alarms in the control room for the auxiliary          tion for condensate storage tank level.                                                                                               Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 9) B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.)                        WCGS POSITION (Cont.)           feedwater system primary water supply to              a)  LI-4A shown on Figure 9.2-12.         allow the operator to anticipate the need              b)  P1-24A, P1-25A, or P1-26A- Class 1E         to make up water or transfer to an alternate              auxiliary feedwater pump suction         water supply and prevent a low pump suction                pressure indication shown on pressure condition from occurring. The                    Figure 10.4-9.         low-level alarm setpoint should allow at         least 20 minutes for operator action,                  Direct correlation between pump suction assuming that the largest capacity auxiliary          pressure and tank level is achieved by         feedwater system pump is operating.                    simple conversion. Exclusion of dynamic                                                                 piping losses from the conversion results in a conservative determination of tank                                                                 level.                                                                 Redundant control room tank level alarms                                                                 are as follows:                                                                 a)  LALL-9 shown on Figure 9.2-12.                                                                 b)  LAL Class 1E auxiliary feedwater                                                                     pump low suction pressure alarm shown on Figure 10.4-9.                                                                 Setpoints for both alarms allow at                                                               least 20 minutes for operator action,                                                                assuming that the largest capacity                                                                 auxiliary feedwater pump is operating.     2. Recommendation (This recommendation has been           WCGS performed a 48-hour, in situ endur-         revised from the original recommendation in           ance test on all auxiliary feedwater         NUREG-0611 - The licensee should perform a            pumps as part of the preoperational test         48-hour endurance test on all auxiliary feed-          program.         water system pumps, if such a test or contin-         uous period of operation has not been accom-         plished to date. Following the 48-hour pump         run, the pumps should be shut down and cooled down and then restarted and run for 1 hour.         Test acceptance criteria should include                                            Rev. 1 WOLF CREEK                                         TABLE 10.4-13B (Sheet 10) B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.)                        WCGS POSITION (Cont.)         demonstrating that the pumps remain within         design limits with respect to bearing/         bearing oil temperatures and vibration         and that pump room ambient conditions (temperature, humidity) do not exceed         environmental qualification limits for         safety-related equipment in the room.     3. Recommendation - The licensee should                  The WCGS auxiliary feedwater design         implement the following requirements as                provides safety-grade (Class 1E) indica-         specified by Item 2.1.7.b on page A-32 of              tion in the control room of auxiliary         NUREG-0578:                                            feedwater flow to each steam generator.                                                                 The design utilizes four independent Safety-grade indication of auxiliary feed-            Class 1E power supplies. The safety-         water flow to each steam generator shall              grade steam generator level indication         be provided in the control room. The                  provides a backup method for determining auxiliary feedwater flow instrument channels          the auxiliary feedwater flow to each         shall be powered from the emergency buses              steam generator.         consistent with satisfying the emergency power diversity requirements for the auxiliary         feedwater system set forth in Auxiliary         Systems Branch Technical Position 10-1 of the Standard Review Plan, Section 10.4.9     4. Recommendation - Licensees with plants which          This recommendation is not applicable to         require local manual realignment of valves to          the WCGS design.         conduct periodic tests on auxiliary feedwater         system trains, and where there is only one re-         maining auxiliary feedwater system  train         available for operation, should propose         Technical Specifications to provide that a dedicated individual who is in communication         with the control room be stationed at the         manual valves. Upon instruction from the con-trol room, this operator would realign the         valves in the auxiliary feedwater system train          from the test mode to their operational alignment.        Rev. 0 WOLF CREEK                                         TABLE 10.4-13B (Sheet 11) C. LONG-TERM RECOMMENDATIONS                                            WCGS POSITION (Cont.)     1. Recommendation GL For plants with a                The WCGS design includes automatic         manual starting system, the licensee should            initiation of the auxiliary feedwater         install a system to automatically initiate            system. Refer to the response to GS-7.         the auxiliary feedwater system flow. This         system and associated automatic initation signals should be designed and installed to         meet safety-grade requirements. Manual         auxiliary feedwater system start and control capability should be retained with manual         start serving as backup to automatic auxil-         iary system initiation.     2. Recommendation GL Licensees with plant            The alternate water supply (essential         designs in which all (primary and alternate)          service water) connects to the auxiliary         water supplies to the auxiliary feedwater              feedwater pump suction piping downstream         systems pass through valves in a single flow          of the single, normally locked-open valve         path should install redundant parallel flow            in a single flow path from the primary         paths (piping and valves).                            water source (condensate storage tank).
: 2. Recommendation GS The licensee should        This item is not applicable to WCGS because lock open single valves or multiple valves      the design does not include single valves or in series in the auxiliary feedwater system      multiple valves in series that could interrupt pump suction piping and lock open other          auxiliary feedwater pump suction or all single valves or multiple valves in series      auxiliary feedwater flow.
Valves from the alternate supply auto-         Licensees with plant designs in which the primary      matically open on low pump suction         auxiliary feedwater system water supply passes        pressure. Refer to the response to GS-2 through valves in a single flowpath, but the          and GS-4.         alternate auxiliary feedwater system water supplies         connect to the auxiliary feedwater system pump suction piping downstream of the above valve(s)         should install redundant valves parallel to the above valve(s) or provide automatic opening of the valve(s) from the alternate water supply         upon low pump suction pressure.         The licensee should propose Technical         Specifications to incorporate appropriate         periodic inspections to verify the valve         positions into the surveillance requirements.                                                                                               Rev. 10 WOLF CREEK                                         TABLE 10.4-13B (Sheet 12) C. LONG-TERM RECOMMENDATIONS (Cont.)                                    WCGS POSITION (Cont.)     3. Recommendation GL At least one auxiliary          The WCGS design meets this recommendation.         feedwater system pump and its associated flow path    Refer to the response to GS-5.         and essential instrumentation should automatically         initiate auxiliary feedwater system flow and be         capable of being operated independently of any         alternating current power source for at least 2 hours. Conversion of direct current power         to alternating current power is acceptable.     4. Recommendation GL Licensees having plants          As discussed in the response to GS-4         with unprotected normal auxiliary feedwater            and GL-2 above, the WCGS design includes         system supplies should evaluate the design of          automatic transfer to the alternate water         their auxiliary feedwater systems to determine        source. The alternate source (essential         if automatic protection of the pumps is neces-        service water) is protected from tornados         sary following a seismic event or a tornado.          and is seismic Category I.         The time available to the control room operator,          and the time necessary for assessing the problem and taking action should be considered in deter-         mining whether operator action can be relied on         to prevent pump damage. Consideration should be given to providing pump protection by means such         as automatic switchover of the pump suctions to         the alternate safety-grade source of water, automatic pump trips on low suction pressure, or         upgrading the normal source of water to meet         seismic Category I and tornado protection requirements.     5. Recommendation GL The licensee should upgrade      As stated in the response to GS-7         the auxiliary feedwater system automatic initia-      the auxiliary feedwater system automatic         tion signals and circuits to meet safety-grade        initiation signals and circuits are safety         requirements.                                          grade.                                                                                               Rev. 0 WOLF CREEK TABLE 10.4-14 AUXILIARY FEEDWATER SYSTEM INDICATING, ALARM, AND CONTROL DEVICES                                                           Control Room Indication/Control            Control Room    Local(1)      Alarm Condensate storage tank   suction valve position          X            X ESW suction valve position        X            X Condensate storage tank            X            X            X   level Condensate storage tank   suction header pressure          X Low pump suction pressure          X            X            X Low pump discharge pressure        X            X            X Pump flow control valve   operation                        X            X Pump flow control valve   position                        X            X Auxiliary feedwater flow          X            X Auxiliary feedwater pump   turbine trip & throttle   valve position                  X            X            X Auxiliary feedwater pump   turbine speed                    X            X X(2)  Auxiliary feedwater pump turbine low lube oil pressure                              X Auxiliary feedwater pump turbine high lube oil   temperature                                                X   (1) Local control here means the auxiliary shutdown panel. (2) High/Low Speed and Control system fault alarms.  
that could interrupt all auxiliary feedwater  
 
system flow. Monthly inspections should be performed to verify that these valves are locked and in the open position. These  
 
inspections should be proposed for incorporation into the surveillance requirements of the plant Technical  
 
Specifications. See Recommendation GL-2 for the longer-term resolution of this concern.
: 3. Recommendation GS The licensee has          Throttling auxiliary feedwater flow to avoid stated that it throttles auxiliary feed-        water hammer is not utilized. The system water flow to avoid water hammer. The          design precludes the occurrence of water hammer licensee should reexamine the practice          in the steam generator inlet, as described in of throttling auxiliary feedwater                Section 10.4.7.2.1.
Rev. 10 WOLF CREEK TABLE 10.4-13B (Sheet 2)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 3. system flow to avoid water hammer.
The licensee should verify that the auxiliary feedwater system will  
 
supply on demand sufficient initial flow to the necessary steam genera-tors to assure adequate decay heat  
 
removal following loss of main feedwater flow and a reactor trip from 100 percent power. In cases  
 
where this reevaluation results in an increase in initial auxiliary feedwater system flow, the licensee  
 
should provide sufficient informa-tion to demonstrate that the required initial auxiliary feed-  
 
water system flow will not result in plant damage due to water hammer.
: 4. Recommendation GS Emergency                        The WCGS design includes an automatic procedures for transferring to                        transfer to the alternate sources of alternate sources of auxiliary                        supply. Procedures provide guidance feedwater system supply should be                      to the operator concerning alternate available to the plant operators.                      water sources.
These procedures should include  
 
criteria to inform the operator                        The normal supply from the condensate when, and in what order, the                          storage tank (CST) is through a locked-transfer to alternate water sources                    open, butterfly valve. Periodic sur-  
 
should take place. The following                      veillance verifies valve position.
cases should be covered by the procedures:
Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 3)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
(1)  The case in which the primary water              Opening of valves from the backup ESWS supply is not initially available.              and starting of auxiliary feedwater pumps The procedures for this case should              are timed such that an AFWS start with  
 
include any operator actions required            no suction from the CST is not a mode for to protect the auxiliary feedwater              common failure of all auxiliary feedwater system pumps against self-damage                pumps.  
 
before water flow is initiated.
(2)  The case in which the primary water supply is being depleted. The pro-cedure for this case should provide for transfer to the alternate water  
 
sources prior to draining of the pri-mary water supply.
: 5. Recommendation GS The as-built plant              The turbine-driven pump in the WCGS should be capable of providing the                    design is capable of being auto-required auxiliary feedwater system flow              matically initiated and operated for at least 2 hours from any one                    independent of any alternating auxiliary feedwater pump train, indepen-              current power source for at dent of any alternating current power                least 2 hours. Essential con-  
 
source. If manual auxiliary feedwater                trols, valve operators, other system initiation or flow control is                  supporting systems, and turbine required following a complete loss of                lube oil cooling for the turbine-  
 
alternating current power, emergency                  driven pump are all independent procedures should be established for                  of alternating current power.
manually initiating and controlling the  
 
system under these conditions. Since the water for cooling of the lube oil for the turbine-driven pump bearings may be  
 
dependent on alternating current power,                                                                                          Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 4)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 5. design or procedural changes shall be made to eliminate this dependency as soon as practicable.  
 
Until this is done, the emergency procedures should provide for an individual to be stationed at the  
 
turbine-driven pump in the event of loss of all alternating cur-rent power to monitor pump bearing  
 
and/or lube oil temperatures. If necessary, this operator would operate the turbine-driven pump  
 
in a manual on-off mode until alternating current power is re-stored. Adequate lighting powered  
 
by direct current power sources and communications at local sta-tions should also be provided if  
 
manual initiation and control of the auxiliary feedwater system is needed. See Recommendation GL-3  
 
for the longer-term resolution of this concern.
: 6. Recommendation GS The licensee                    Valve lineups and independent second should confirm flow path                              operator verification of valve lineups availabiity of an auxiliary                          is required on the auxiliary feedwater feedwater system flow train that                      system after maintenance. Verification has been out of service to perform                    of operability is included as part of periodic testing or maintenance as                    functional testing on return from ex-  
 
follows:                                              tended cold shutdown.  
         - Procedures should be implemented to require an operator to determine Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 5)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 6. that the auxiliary feedwater system valves are properly aligned and a second operator to  
 
independently verify that the valves are properly aligned.
The licensee should propose Technical Specifications to assure that prior to plant  
 
startup following an extended cold shutdown, a flow test would be performed to verify the  
 
normal flow path from the primary auxiliary feedwater system water source to the steam  
 
generators. The flow test should be conducted with auxiliary feedwater system  
 
valves in their normal alignment.
: 7. Recommendation GS The licensee                    The WCGS auxiliary feedwater system should verify that the automatic                      is designed so that automatic start auxiliary feedwater system                      initiation signals and circuits signals and associated circuitry                      are redundant and meet safety-are safety grade. If this cannot                      grade requirements. Refer to be verified, the auxiliary system                      Section 7.3.6.  
 
automatic initiation system should be modified in the short-term to meet the functional requirements  
 
listed below. For the longer term,          the automatic initiation signals Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 6)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 7. and circuits should be upgraded to meet safety-grade requirements as indicated in Recommendation GL-
: 5.
(1)  The design should provide for the automatic initiation of the auxiliary feedwater system flow.
(2)  The automatic initiation signals and circuits should be  
 
designed so that a single failure will not result in the loss of auxiliary feedwater  
 
system function.
(3)  Testability of the initiation signal and circuits shall be a feature of the design.
(4)  The initiation signals and circuits should be powered from the emergency buses.
(5)  Manual capability to initiate the auxiliary feedwater system  
 
from the control room should be implemented so that a single failure in the manual circuits will not result in the loss of system function.
Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 7)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 7.  (6)  The alternating current motor-driven pumps and valves in the auxiliary feedwater system should be included  
 
in the automatic actuation (simul-taneous and/or sequential) of the loads to the emergency buses.
(7)  The automatic initiation signals and circuits shall be designed so that  
 
their failure will not result in the loss of manual capability to initiate the auxiliary feedwater system from  
 
the control room.
: 8. Recommendation GS  The licensee should        See response to GS-7 above.
install a system to automatically initiate auxiliary feedwater system flow. This system need not be safety grade; however,          in the short term, it should meet the criteria listed below, which are similar to Item 2.1.7.a of NUREG-0578. For the longer  
 
term, the automatic initiation signals and circuits should be upgraded to meet safety-grade requirements; as indicated in  
 
Recommendation GL-2.
(1)  The design should provide for the automatic initiation of the auxiliary feedwater system flow.
(2)  The automatic initiation signal and circuits should be designed so that a single failure will not result in  
 
the loss of auxiliary feedwater system function.                      Rev. 1 WOLF CREEK TABLE 10.4-13B (Sheet 8)
A. SHORT-TERM RECOMMENDATIONS (Cont.)                                  WCGS POSITION (Cont.)
: 8.  (3)  Testability of the initiating signals and circuits should be a feature of the design.
(4)  The initiating signals and circuits should be powered from the emergency  
 
buses.
(5)  Manual capability to initiate the auxiliary feedwater system from the control room should be retained and should be implemented  
 
so that a single failure in the manual circuits will not result in the loss of system function.
(6)  The alternating current powered motor-driven pumps and valves in  
 
the auxiliary feedwater system should be included in the automatic actua-tion (simultaneous and/or sequen-  
 
tial) of the loads to the emergency buses.
(7)  The automatic initiation signals and circuits should be designed so that their failure will not result in  
 
the loss of manual capability to initiate the auxiliary feedwater sys-tem from the control room.
B. ADDITIONAL SHORT-TERM RECOMMENDATIONS
: 1. Recommendation - The licensee should provide          The existing WCGS design provides the redundant level indication and low-level              following redundant control room indica-alarms in the control room for the auxiliary          tion for condensate storage tank level.
Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 9)
B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.)                        WCGS POSITION (Cont.)
feedwater system primary water supply to              a)  LI-4A shown on Figure 9.2-12.
allow the operator to anticipate the need              b)  P1-24A, P1-25A, or P1-26A- Class 1E to make up water or transfer to an alternate              auxiliary feedwater pump suction water supply and prevent a low pump suction                pressure indication shown on  
 
pressure condition from occurring. The                    Figure 10.4-9.
low-level alarm setpoint should allow at least 20 minutes for operator action,                  Direct correlation between pump suction  
 
assuming that the largest capacity auxiliary          pressure and tank level is achieved by feedwater system pump is operating.                    simple conversion. Exclusion of dynamic piping losses from the conversion results  
 
in a conservative determination of tank level.
Redundant control room tank level alarms are as follows:
a)  LALL-9 shown on Figure 9.2-12.
b)  LAL Class 1E auxiliary feedwater pump low suction pressure alarm shown  
 
on Figure 10.4-9.
Setpoints for both alarms allow at least 20 minutes for operator action,                                                                assuming that the largest capacity auxiliary feedwater pump is operating.
: 2. Recommendation (This recommendation has been WCGS performed a 48-hour, in situ endur-revised from the original recommendation in ance test on all auxiliary feedwater NUREG-0611 - The licensee should perform a            pumps as part of the preoperational test 48-hour endurance test on all auxiliary feed-          program.
water system pumps, if such a test or contin-uous period of operation has not been accom-plished to date. Following the 48-hour pump run, the pumps should be shut down and cooled  
 
down and then restarted and run for 1 hour.
Test acceptance criteria should include                                            Rev. 1 WOLF CREEK TABLE 10.4-13B (Sheet 10)
B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.)                        WCGS POSITION (Cont.)
demonstrating that the pumps remain within design limits with respect to bearing/
bearing oil temperatures and vibration and that pump room ambient conditions  
 
(temperature, humidity) do not exceed environmental qualification limits for safety-related equipment in the room.
: 3. Recommendation - The licensee should                  The WCGS auxiliary feedwater design implement the following requirements as                provides safety-grade (Class 1E) indica-specified by Item 2.1.7.b on page A-32 of              tion in the control room of auxiliary NUREG-0578:                                            feedwater flow to each steam generator.
The design utilizes four independent  
 
Safety-grade indication of auxiliary feed-            Class 1E power supplies. The safety-water flow to each steam generator shall              grade steam generator level indication be provided in the control room. The                  provides a backup method for determining  
 
auxiliary feedwater flow instrument channels          the auxiliary feedwater flow to each shall be powered from the emergency buses              steam generator.
consistent with satisfying the emergency  
 
power diversity requirements for the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the  
 
Standard Review Plan, Section 10.4.9
: 4. Recommendation - Licensees with plants which          This recommendation is not applicable to require local manual realignment of valves to          the WCGS design.
conduct periodic tests on auxiliary feedwater system trains, and where there is only one re-maining auxiliary feedwater system  train available for operation, should propose Technical Specifications to provide that a  
 
dedicated individual who is in communication with the control room be stationed at the manual valves. Upon instruction from the con-  
 
trol room, this operator would realign the valves in the auxiliary feedwater system train          from the test mode to their operational alignment.        Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 11)
C. LONG-TERM RECOMMENDATIONS                                            WCGS POSITION (Cont.)
: 1. Recommendation GL For plants with a                The WCGS design includes automatic manual starting system, the licensee should            initiation of the auxiliary feedwater install a system to automatically initiate            system. Refer to the response to GS-7.
the auxiliary feedwater system flow. This system and associated automatic initation  
 
signals should be designed and installed to meet safety-grade requirements. Manual auxiliary feedwater system start and control  
 
capability should be retained with manual start serving as backup to automatic auxil-iary system initiation.
: 2. Recommendation GL Licensees with plant            The alternate water supply (essential designs in which all (primary and alternate)          service water) connects to the auxiliary water supplies to the auxiliary feedwater              feedwater pump suction piping downstream systems pass through valves in a single flow          of the single, normally locked-open valve path should install redundant parallel flow            in a single flow path from the primary paths (piping and valves).                            water source (condensate storage tank).  
 
Valves from the alternate supply auto-Licensees with plant designs in which the primary      matically open on low pump suction auxiliary feedwater system water supply passes        pressure. Refer to the response to GS-2  
 
through valves in a single flowpath, but the          and GS-4.
alternate auxiliary feedwater system water supplies connect to the auxiliary feedwater system pump  
 
suction piping downstream of the above valve(s) should install redundant valves parallel to the  
 
above valve(s) or provide automatic opening of  
 
the valve(s) from the alternate water supply upon low pump suction pressure.
The licensee should propose Technical Specifications to incorporate appropriate periodic inspections to verify the valve positions into the surveillance requirements.
Rev. 10 WOLF CREEK TABLE 10.4-13B (Sheet 12)
C. LONG-TERM RECOMMENDATIONS (Cont.)                                    WCGS POSITION (Cont.)
: 3. Recommendation GL At least one auxiliary          The WCGS design meets this recommendation.
feedwater system pump and its associated flow path    Refer to the response to GS-5.
and essential instrumentation should automatically initiate auxiliary feedwater system flow and be capable of being operated independently of any alternating current power source for at least  
 
2 hours. Conversion of direct current power to alternating current power is acceptable.
: 4. Recommendation GL Licensees having plants          As discussed in the response to GS-4 with unprotected normal auxiliary feedwater            and GL-2 above, the WCGS design includes system supplies should evaluate the design of          automatic transfer to the alternate water their auxiliary feedwater systems to determine        source. The alternate source (essential if automatic protection of the pumps is neces-        service water) is protected from tornados sary following a seismic event or a tornado.          and is seismic Category I.
The time available to the control room operator,          and the time necessary for assessing the problem  
 
and taking action should be considered in deter-mining whether operator action can be relied on to prevent pump damage. Consideration should be  
 
given to providing pump protection by means such as automatic switchover of the pump suctions to the alternate safety-grade source of water, automatic pump trips on low suction pressure, or upgrading the normal source of water to meet seismic Category I and tornado protection  
 
requirements.
: 5. Recommendation GL The licensee should upgrade      As stated in the response to GS-7 the auxiliary feedwater system automatic initia-      the auxiliary feedwater system automatic tion signals and circuits to meet safety-grade        initiation signals and circuits are safety requirements.                                          grade.
Rev. 0 WOLF CREEK TABLE 10.4-14 AUXILIARY FEEDWATER SYSTEM INDICATING, ALARM, AND CONTROL DEVICES Control Room Indication/Control            Control Room    Local (1)      Alarm Condensate storage tank suction valve position          X            X  
 
ESW suction valve position        X            X  
 
Condensate storage tank            X            X            X level Condensate storage tank suction header pressure          X  
 
Low pump suction pressure          X            X            X Low pump discharge pressure        X            X            X  
 
Pump flow control valve operation                        X            X  
 
Pump flow control valve position                        X            X  
 
Auxiliary feedwater flow          X            X  
 
Auxiliary feedwater pump turbine trip & throttle valve position                  X            X            X  
 
Auxiliary feedwater pump turbine speed                    X            X X (2)  Auxiliary feedwater pump  
 
turbine low lube oil pressure                              X Auxiliary feedwater pump  
 
turbine high lube oil temperature                                                X (1) Local control here means the auxiliary shutdown panel.
(2) High/Low Speed and Control system fault alarms.  
 
Rev. 27 WOLF CREEK TABLE 10.4-15 SECONDARY LIQUID WASTE SYSTEM COMPONENT DATA
 
Secondary Liquid Waste Evaporator              (Note 1)
 
Quantity                                  1
 
Type                                      Forced circulation Design process flow, gpm                  30 Design pressure (vapor body), psig        30 Design temperature (vapor body), F        300 Cooling water requirements (condenser/subcooler)
 
Flow, lb/hr                        685,000 Temperature, in/out, F            105/130 Pressure (max), psig              150
 
Steam requirements (heater)
Flow, lb/hr                        18,000 (min)
Temperature in/out                250 (steam)/250 (liquid)
 
Pressure, psig                    15 Principal design codes                    ASME VIII and TEMA R
 
Quality group                              D (augmented)
Materials of Construction
 
Vapor body                        Inconel 625 Entrainment separator              316L SS Distillate condenser              316L SS
 
Distillate subcooler              316L SS Heater vent gas cooler (shell/tubes)                    Carbon steel/316L SS
 
Condenser vent gas cooler (shell/tubes)                    Carbon steel/316L SS Heater                            Inconel 625
 
Recirculation pump                Alloy 20 Concentrates pumps                Alloy 20 Distillate pump                    316L SS
 
Recirculation piping              Inconel 625 Service (steam and cooling water)  Carbon steel Piping
 
Valves                          Inconel 625,                                                316L SS, and carbon steel
 
SLW Charcoal Adsorber
 
Quantity                                  1 Type                                      Activated carbon Fluid                                      Secondary liquid waste
 
evaporator distillate or floor drain waste Design pressure, psig                      150
 
Rev. 14
 
WOLF CREEK TABLE 10.4-15 (Sheet 2)
Design temperature, F                      200 Design flow, gpm                          35 Design pressure drop (fouled condition), psi            10 to 12 at 35 gpm
 
Volume, ft 3 (charcoal)                    88 Design code                                ASME Section VIII
 
Material                                  304 SS
 
SLW Demineralizer
 
Quantity                                  1 Type                                      Mixed bed Fluid                                        Secondary liquid
 
waste evaporator distillate, floor drain waste, low
 
TDS waste Design pressure, psig                      150 Design temperature, F                      200
 
Design pressure drop (fouled condition), psi            12 to 15 at 100 gpm Flow rate, gpm                            100
 
Resin volume, cu ft                        55 Design code                                ASME Section VIII Material                                  304 SS
 
SLW Oil Interceptor Quantity                                  1


Rev. 27 WOLF CREEK TABLE 10.4-15  SECONDARY LIQUID WASTE SYSTEM COMPONENT DATA Secondary Liquid Waste Evaporator              (Note 1)
Type                                      Gravity separation Design flow, gpm                           150 Fluid                                      Turbine building drains
Quantity                                  1 Type                                      Forced circulation      Design process flow, gpm                   30      Design pressure (vapor body), psig        30      Design temperature (vapor body), F        300      Cooling water requirements              (condenser/subcooler)
Flow, lb/hr                        685,000              Temperature, in/out, F            105/130              Pressure (max), psig              150 Steam requirements (heater)              Flow, lb/hr                        18,000 (min)              Temperature in/out                250 (steam)/250 (liquid)
Pressure, psig                    15      Principal design codes                    ASME VIII and TEMA R Quality group                              D (augmented)      Materials of Construction Vapor body                        Inconel 625              Entrainment separator              316L SS              Distillate condenser              316L SS Distillate subcooler              316L SS              Heater vent gas cooler                (shell/tubes)                    Carbon steel/316L SS Condenser vent gas cooler                (shell/tubes)                    Carbon steel/316L SS              Heater                            Inconel 625 Recirculation pump                Alloy 20              Concentrates pumps                Alloy 20              Distillate pump                    316L SS Recirculation piping              Inconel 625              Service (steam and cooling water)  Carbon steel                Piping Valves                          Inconel 625,                                                316L SS, and carbon                                                steel SLW Charcoal Adsorber Quantity                                  1      Type                                      Activated carbon      Fluid                                      Secondary liquid waste evaporator distillate                                                  or floor drain waste      Design pressure, psig                      150


Rev. 14 WOLF CREEK                          TABLE 10.4-15 (Sheet 2)        Design temperature, F                      200      Design flow, gpm                          35      Design pressure drop              (fouled condition), psi            10 to 12 at 35 gpm Volume, ft3 (charcoal)                    88      Design code                                ASME Section VIII Material                                  304 SS SLW Demineralizer Quantity                                  1      Type                                      Mixed bed      Fluid                                        Secondary liquid waste evaporator                                                  distillate, floor                                                  drain waste, low TDS waste      Design pressure, psig                      150      Design temperature, F                      200 Design pressure drop              (fouled condition), psi            12 to 15 at 100 gpm      Flow rate, gpm                            100 Resin volume, cu ft                        55      Design code                                ASME Section VIII      Material                                  304 SS SLW Oil Interceptor      Quantity                                  1 Type                                      Gravity separation      Design flow, gpm                          150      Fluid                                      Turbine building drains Design pressure                            Atmospheric     Design temperature, F                      225     Design code                                Manufacturer's standard Material                                  304 SS High TDS Collector Tanks Quantity                                  2     Type                                      Vertical, cylindrical, dished-bottom     Fluid                                      Regenerant waste                                                   (high TDS)
Design pressure                            Atmospheric Design temperature, F                      225 Design code                                Manufacturer's standard  
Capacity, gal                              17,000     Design temperature, F                      140     Design pressure, psig                      15 Internals                                  Mixer     Design code                                ASME Section VIII     Material                                  316L SS  
 
Material                                  304 SS High TDS Collector Tanks  
 
Quantity                                  2 Type                                      Vertical, cylindrical, dished-bottom Fluid                                      Regenerant waste (high TDS)  
 
Capacity, gal                              17,000 Design temperature, F                      140 Design pressure, psig                      15  
 
Internals                                  Mixer Design code                                ASME Section VIII Material                                  316L SS  


Rev. 0  
Rev. 0  


WOLF CREEK                         TABLE 10.4-15 (Sheet 3)   SLW Drain Collector Tanks       Quantity                                  2     Type                                      Vertical, cylindrical, dished bottom     Fluid                                      Turbine building floor                                                   drains Capacity, gals                            15,000      Design temperature, F                      200      Design pressure                            Atmospheric Design code                                ASME Section VIII      Material                                  304 SS Low TDS Collector Tanks      Quantity                                  2 Type                                      Vertical, cylindrical,                                                  conical bottom      Fluid                                      Regenerant waste (low TDS)      Capacity, gals                            45,000      Diameter, ft-in.                          24-0 Height, ft-in.                            20-3      Design temperature, F                      150      Design pressure                            Atmospheric Internals                                  Baffles to promote                                                  settling of solids      Material                                  304 SS Design code                                ASME Section VIII  SLW Monitor Tanks Quantity                                  2      Type                                      Vertical, cylindrical, dished bottom      Fluid                                      Processed turbine                                                  building floor drains and con-                                                  densate demin-                                                  eralizer regen-erant wastes,                                                  borated wastes, and                                                  primary water      Capacity, gals                            15,000      Design temperature, F                      200      Design pressure                            Atmospheric Design code                                ASME Section VIII      Material                                  304 SS 
WOLF CREEK TABLE 10.4-15 (Sheet 3)
SLW Drain Collector Tanks Quantity                                  2 Type                                      Vertical, cylindrical, dished bottom Fluid                                      Turbine building floor drains  


Rev. 8 WOLF CREEK                          TABLE 10.4-15 (Sheet 4)  Low TDS Collector Tanks Pumps      Quantity                                  2      Type                                      In-line centrifugal Fluid                                    Regenerant waste                                                  (low TDS)      Design pressure, psig                    250      Design temperature, F                    100      Capacity, gpm                             150      Rated head, ft                            220      NPSH required, ft                        6      Design code                              Manufacturer's standard      Material (wetted surface)                316 SS Motor                                    20 Hp/460 V/3 phase/60 Hz Secondary Liquid Waste Oil Interceptor Transfer Pumps Quantity                                  2      Type                                      In-line centrifugal      Fluid                                    Turbine building floor                                                  drains Design pressure, psig                    300      Design temperature, F                     150      Capacity, gpm                            150 Rated head, ft                            51      Design code                              Manufacturer's standard      Material                                  316 SS Motor                                    5 hp/460 V/3 phase/60 Hz  High TDS Collector Tanks Pumps Quantity                                  2      Type                                      In-line centrifugal Fluid                                    Regenerant waste                                                  (high TDS)      Design pressure, psig                    300 Design temperature, F                    130      Capacity, gpm                            35      Rated head, ft                           255 NPSH required, ft                        8      Design code                              Manufacturer's standard      Material (wetted surface)                Alloy 20 Motor                                    10 Hp/460 V/3 phase/60 Hz 
Capacity, gals                             15,000 Design temperature, F                     200 Design pressure                            Atmospheric


Rev. 12 WOLF CREEK                          TABLE 10.4-15 (Sheet 5)  SLW Drain Collector Tank Pumps      Quantity                                  2      Type                                      In-line centrifugal Fluid                                      Turbine building                                                  floor drains      Design pressure, psig                      300 Design temperature, F                      200      Capacity, gpm                              35      Rated head, ft                            207 NPSH required, ft                          8      Design code                                Manufacturer's standard      Material (wetted surface)                  316 SS Motor                                      10 Hp/460 V/3                                                  phase/60 Hz
Design code                                ASME Section VIII Material                                   304 SS  


SLW Discharge Pumps       Quantity                                  2     Type                                      In-line centrifugal     Fluid                                      Processed secondary                                                   liquid wastes Design pressure, psig                      300     Design temperature, F                      200     Capacity, gpm                              100 Rated head, ft                            250     NPSH required, ft                          7     Design code                                Manufacturer's standard Material (wetted surface)                  316 SS     Motor                                      15 Hp/460 V/3 phase/60                                                   Hz Low TDS Filters (FHF04A, 04B)*       Quantity                                  2     Type                                      Cartridge     Design pressure, psig                      150 Design temperature, F                      250     Particle retention                        (See Note 2 of Table 9.3-13)     Pressure drop, psi @ 100 gpm Clean                              1             Dirty                              25     Design code (vessel)                      ASME Section VIII Material (vessel)                          304 SS  *See Table 9.3-13 Sheet 2 comment High TDS Transfer Tank Quantity                                  1     Type                                      Horizontal     Fluid                                      Regenerant waste (high TDS)
Low TDS Collector Tanks Quantity                                  2
Rev. 15 WOLF CREEK                         TABLE 10.4-15 (Sheet 6)       Capacity, gals                            3,120     Design temperature, F                    130     Design pressure                          Atmospheric     Design code                              ASME Section VIII Material                                  316L SS High TDS Transfer Tank Pumps Quantity                                  2     Type                                      In-line centrifugal Fluid                                    Regenerant waste                                                 (high TDS)     Design pressure, psig                    300 Design temperature, F                    130     Capacity, gpm                            450     Rated head, ft                            78 NPSH required, ft                        8     Design code                              Manufacturer's standard     Material (wetted surface)                Alloy 20 Motor                                    20 Hp/460 V/3 phase/60 Hz Low TDS Transfer Tank Quantity                                  1     Type                                      Horizontal Fluid                                    Regenerant waste                                                 (low TDS)     Capacity, gals                            3,120 Design temperature, F                    130     Design pressure                          Atmospheric     Design code                              ASME Section VIII Material                                  304 SS Low TDS Transfer Tank Pumps Quantity                                  2     Type                                      In-line centrifugal Fluid                                    Regenerant waste                                                 (low TDS)     Design pressure, psig                    300 Design temperature, F                    130     Capacity, gpm                            450     Rated head, ft                            78 NPSH required, ft                        8     Design code                              Manufacturer's standard     Material (wetted surfaces)                316 SS Motor                                    20 Hp/460 V/3 phase/60 Hz  
 
Type                                      Vertical, cylindrical,                                                  conical bottom Fluid                                      Regenerant waste
 
(low TDS)
Capacity, gals                            45,000 Diameter, ft-in.                          24-0
 
Height, ft-in.                            20-3 Design temperature, F                      150 Design pressure                            Atmospheric
 
Internals                                  Baffles to promote settling of solids Material                                  304 SS
 
Design code                                ASME Section VIII SLW Monitor Tanks
 
Quantity                                  2 Type                                      Vertical, cylindrical, dished bottom Fluid                                      Processed turbine building floor
 
drains and con-densate demin-eralizer regen-
 
erant wastes,                                                  borated wastes, and primary water Capacity, gals                            15,000 Design temperature, F                      200 Design pressure                            Atmospheric
 
Design code                                ASME Section VIII Material                                  304 SS
 
Rev. 8
 
WOLF CREEK TABLE 10.4-15 (Sheet 4)
Low TDS Collector Tanks Pumps Quantity                                  2 Type                                      In-line centrifugal
 
Fluid                                    Regenerant waste (low TDS)
Design pressure, psig                    250 Design temperature, F                    100 Capacity, gpm                            150 Rated head, ft                            220 NPSH required, ft                        6 Design code                              Manufacturer's standard Material (wetted surface)                316 SS
 
Motor                                    20 Hp/460 V/3 phase/60 Hz
 
Secondary Liquid Waste Oil Interceptor Transfer Pumps
 
Quantity                                  2 Type                                      In-line centrifugal Fluid                                    Turbine building floor drains
 
Design pressure, psig                    300 Design temperature, F                    150 Capacity, gpm                            150
 
Rated head, ft                            51 Design code                              Manufacturer's standard Material                                  316 SS
 
Motor                                    5 hp/460 V/3 phase/60 Hz High TDS Collector Tanks Pumps
 
Quantity                                  2 Type                                      In-line centrifugal
 
Fluid                                    Regenerant waste (high TDS)
Design pressure, psig                    300
 
Design temperature, F                    130 Capacity, gpm                            35 Rated head, ft                            255
 
NPSH required, ft                        8 Design code                              Manufacturer's standard Material (wetted surface)                Alloy 20
 
Motor                                    10 Hp/460 V/3 phase/60 Hz
 
Rev. 12
 
WOLF CREEK TABLE 10.4-15 (Sheet 5)
SLW Drain Collector Tank Pumps Quantity                                  2 Type                                      In-line centrifugal
 
Fluid                                      Turbine building floor drains Design pressure, psig                      300
 
Design temperature, F                      200 Capacity, gpm                              35 Rated head, ft                            207
 
NPSH required, ft                          8 Design code                                Manufacturer's standard Material (wetted surface)                  316 SS
 
Motor                                      10 Hp/460 V/3 phase/60 Hz
 
SLW Discharge Pumps Quantity                                  2 Type                                      In-line centrifugal Fluid                                      Processed secondary liquid wastes  
 
Design pressure, psig                      300 Design temperature, F                      200 Capacity, gpm                              100  
 
Rated head, ft                            250 NPSH required, ft                          7 Design code                                Manufacturer's standard  
 
Material (wetted surface)                  316 SS Motor                                      15 Hp/460 V/3 phase/60 Hz  
 
Low TDS Filters (FHF04A, 04B)
* Quantity                                  2 Type                                      Cartridge Design pressure, psig                      150  
 
Design temperature, F                      250 Particle retention                        (See Note 2 of Table 9.3-13)
Pressure drop, psi @ 100 gpm  
 
Clean                              1 Dirty                              25 Design code (vessel)                      ASME Section VIII  
 
Material (vessel)                          304 SS  
  *See Table 9.3-13 Sheet 2 comment High TDS Transfer Tank  
 
Quantity                                  1 Type                                      Horizontal Fluid                                      Regenerant waste  
 
(high TDS)  
 
Rev. 15  
 
WOLF CREEK TABLE 10.4-15 (Sheet 6)
Capacity, gals                            3,120 Design temperature, F                    130 Design pressure                          Atmospheric Design code                              ASME Section VIII  
 
Material                                  316L SS High TDS Transfer Tank Pumps  
 
Quantity                                  2 Type                                      In-line centrifugal  
 
Fluid                                    Regenerant waste (high TDS)
Design pressure, psig                    300  
 
Design temperature, F                    130 Capacity, gpm                            450 Rated head, ft                            78  
 
NPSH required, ft                        8 Design code                              Manufacturer's standard Material (wetted surface)                Alloy 20  
 
Motor                                    20 Hp/460 V/3 phase/60 Hz Low TDS Transfer Tank  
 
Quantity                                  1 Type                                      Horizontal  
 
Fluid                                    Regenerant waste (low TDS)
Capacity, gals                            3,120  
 
Design temperature, F                    130 Design pressure                          Atmospheric Design code                              ASME Section VIII  
 
Material                                  304 SS Low TDS Transfer Tank Pumps  
 
Quantity                                  2 Type                                      In-line centrifugal  
 
Fluid                                    Regenerant waste (low TDS)
Design pressure, psig                    300  
 
Design temperature, F                    130 Capacity, gpm                            450 Rated head, ft                            78  
 
NPSH required, ft                        8 Design code                              Manufacturer's standard Material (wetted surfaces)                316 SS  
 
Motor                                    20 Hp/460 V/3 phase/60 Hz  


Rev. 0  
Rev. 0  


WOLF CREEK                         TABLE 10.4-15 (Sheet 7)   SLW Evaporator Feed Filter (FHF05)*       Quantity                                  1     Type                                      Cartridge Design pressure, psig                      150     Design temperature, F                      250     Design flow, gpm                          35 Particle retention             30 micron (max)                    98% (min)             49 micron                          100%
WOLF CREEK TABLE 10.4-15 (Sheet 7)
Pressure drop at 35 gpm             Clean, psi                        1             Dirty, psi                        25 Material, vessel                          316L SS     Design code                                ASME Section VIII Piping and Valves       High TDS and Evaporator Feed Material                                  316L SS     Design code                                ANSI B31.1 Pressure rating, psig                      150       Evaporator Concentrates Discharge Material                                  Incoloy 825     Design code                                ANSI B31.1 Pressure rating, psig                      150       All Others Material                                  304 or 316 SS      Design code                                ANSI B31.1      Pressure rating, psig                      150  *See comments on Sheet 2 of Table 9.3-13. Note 1:  Equipment permanently out of service.
SLW Evaporator Feed Filter (FHF05)
* Quantity                                  1 Type                                      Cartridge  
 
Design pressure, psig                      150 Design temperature, F                      250 Design flow, gpm                          35  
 
Particle retention 30 micron (max)                    98% (min) 49 micron                          100%  
 
Pressure drop at 35 gpm Clean, psi                        1 Dirty, psi                        25  
 
Material, vessel                          316L SS Design code                                ASME Section VIII  
 
Piping and Valves High TDS and Evaporator Feed  
 
Material                                  316L SS Design code                                ANSI B31.1  
 
Pressure rating, psig                      150 Evaporator Concentrates Discharge  
 
Material                                  Incoloy 825 Design code                                ANSI B31.1  
 
Pressure rating, psig                      150 All Others  


Rev. 19  
Material                                  304 or 316 SS Design code                                ANSI B31.1 Pressure rating, psig                      150
}}
  *See comments on Sheet 2 of Table 9.3-13.
Note 1:  Equipment permanently out of service.
 
Rev. 19}}

Latest revision as of 13:07, 6 May 2019

Revision 30 to Updated Final Safety Analysis Report, Chapter 10.0, Steam and Power Conversion System
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WOLF CREEK CHAPTER 10.0 TABLE OF CONTENTS STEAM AND POWER CONVERSION SYSTEM

Section Page

10.1

SUMMARY

DESCRIPTION 10.1-1

10.1.1 GENERAL DISCUSSION 10.1-1 10.1.2 PROTECTIVE FEATURES 10.1-2 10.1.2.1 Loss of External Electrical Load and/or 10.1-2 Turbine Trip 10.1.2.2 Overpressure Protection 10.1-2 10.1.2.3 Loss of Main Feedwater Flow 10.1-2 10.1.2.4 Turbine Overspeed Protection 10.1-2 10.1.2.5 Turbine Missile Protection 10.1-2 10.1.2.6 Radioactivity 10.1-3

10.2 TURBINE GENERATOR 10.2-1

10.2.1 DESIGN BASES 10.2-1

10.2.1.1 Safety Design Bases 10.2-1 10.2.1.2 Power Generation Design Bases 10.2-1 10.2.2 SYSTEM DESCRIPTION 10.2-1

10.2.2.1 General Description 10.2-1 10.2.2.2 Component Description 10.2-3 10.2.2.3 System Operation 10.2-6

10.2.3 TURBINE INTEGRITY 10.2-10

10.2.3.1 Materials Selection 10.2-10 10.2.3.2 Fracture Toughness 10.2-10 10.2.3.3 High Temperature Properties 10.2-10 10.2.3.4 Turbine Design 10.2-11 10.2.3.5 Preservice Inspection 10.2-11 10.2.3.6 Inservice Inspection 10.2-11 10.2.4 EVALUATION 10.2-12 10.

2.5 REFERENCES

10.2-13

10.0-i Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1

10.3.1 DESIGN BASES 10.3-1 10.3.1.1 Safety Design Bases 10.3-1 10.3.1.2 Power Generation Design Bases 10.3-2

10.3.2 SYSTEM DESCRIPTION 10.3-2 10.3.2.1 General Description 10.3-2 10.3.2.2 Component Description 10.3-3 10.3.2.3 System Operation 10.3-5

10.3.3 SAFETY EVALUATION 10.3-6 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-8

10.3.4.1 Preservice Valve Testing 10.3-8 10.3.4.2 Preservice System Testing 10.3-8 10.3.4.3 Inservice Testing 10.3-8

10.3.5 SECONDARY WATER CHEMISTRY (PWR) 10.3-9

10.3.5.1 Chemistry Control Basis 10.3-9 10.3.5.2 Corrosion Control Effectiveness 10.3-10

10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-11

10.3.6.1 Fracture Toughness 10.3-11 10.3.6.2 Material Selection and Fabrication 10.3-11

10.4 OTHER FEATURES OF STEAM AND POWER CONVER- 10.4-1 SION SYSTEM 10.4.1 MAIN CONDENSERS 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 10.4-4 10.4.1.4 Tests and Inspections 10.4-4 10.4.1.5 Instrument Applications 10.4-4

10.0-ii Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 10.4.2 MAIN CONDENSER EVACUATION SYSTEM 10.4-5

10.4.2.1 Design Bases 10.4-5 10.4.2.2 System Description 10.4-5 10.4.2.3 Safety Evaluation 10.4-7 10.4.2.4 Tests and Inspections 10.4-7 10.4.2.5 Instrumentation Applications 10.4-7

10.4.3 TURBINE GLAND SEALING SYSTEM 10.4-7

10.4.3.1 Design Bases 10.4-7 10.4.3.2 System Description 10.4-8 10.4.3.3 Safety Evaluation 10.4-9 10.4.3.4 Tests and Inspections 10.4-9 10.4.3.5 Instrumentation Applications 10.4-10

10.4.4 TURBINE BYPASS SYSTEM 10.4-10

10.4.4.1 Design Bases 10.4-10 10.4.4.2 System Description 10.4-10 10.4.4.3 Safety Evaluation 10.4-12 10.4.4.4 Inspection and Testing Requirements 10.4-12 10.4.4.5 Instrumentation Applications 10.4-13 10.4.5 CIRCULATING WATER SYSTEM 10.4-13

10.4.5.1 Design Bases 10.4-13 10.4.5.2 System Description 10.4-14 10.4.5.3 Safety Evaluation 10.4-15 10.4.5.4 Tests and Inspections 10.4-16 10.4.5.5 Instrumentation Applications 10.4-16

10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-16 10.4.6.1 Design Bases 10.4-17 10.4.6.2 System Description 10.4-17 10.4.6.3 Safety Evaluation 10.4-20 10.4.6.4 Tests and Inspections 10.4-21 10.4.6.5 Instrumentation Applications 10.4-21

10.4.7 CONDENSATE AND FEEDWATER SYSTEM 10.4-21

10.4.7.1 Design Bases 10.4-21 10.4.7.2 System Description 10.4-23

10.0-iii Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 10.4.7.3 Safety Evaluation 10.4-30 10.4.7.4 Tests and Inspections 10.4-31 10.4.7.5 Instrumentation Applications 10.4-32 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-34

10.4.8.1 Design Bases 10.4-34 10.4.8.2 System Description 10.4-35 10.4.8.3 Radioactive Releases 10.4-44 10.4.8.4 Safety Evaluation 10.4-44 10.4.8.5 Tests and Inspections 10.4-45 10.4.8.6 Instrumentation Applications 10.4-46

10.4.9 AUXILIARY FEEDWATER SYSTEM 10.4-46

10.4.9.1 Design Bases 10.4-46 10.4.9.2 System Description 10.4-48 10.4.9.3 Safety Evaluation 10.4-51 10.4.9.4 Tests and Inspections 10.4-53 10.4.9.5 Instrumentation Applications 10.4-53

10.4.10 SECONDARY LIQUID WASTE SYSTEM 10.4-53

10.4.10.1 Design Bases 10.4-54 10.4.10.2 System Description 10.4-54 10.4.10.3 Safety Evaluation 10.4-60 10.4.10.4 Tests and Inspections 10.4-60 10.4.10.5 Instrumentation Applications 10.4-60

10.0-iv Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)

LIST OF TABLES

Number Title

10.1-1 Summary of Important Design Features and Performance Characteristics of the Steam and Power Conversion System

10.2-1 Events Following Loss of Turbine Load with Postulated Equipment Failures

10.3-1 Main Steam Supply System Control, Indicating, and Alarm Devices

10.3-2 Main Steam Supply System Design Data

10.3-3 Main Steam System Single Active Failure Analysis

10.3-4 Deleted

10.4-1 Condenser Design Data

10.4-2 Main Condenser Air Removal System Design Data

10.4-3 Circulating Water System Component Description

10.4-4 Condensate Demineralization System Design

Data 10.4-5 Condensate and Feedwater System Component Failure Analysis

10.4-6 Condensate and Feedwater System Design Data

10.4-7 Feedwater Isolation Single Failure Analysis

10.4-8 Main Feedwater System Control, Indicating, and Alarm Devices

10.4-9 Steam Generator Blowdown System Major Component Parameters

10.4-10 Steam Generator Blowdown System Single Active Failure Analysis

10.4-11 Steam Generator Blowdown System Control, Indicating, and Alarm Devices

10.0-v Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)

Number Title 10.4-12 Auxiliary Feedwater System Component Data

10.4-13 Auxiliary Feedwater System Single Active Failure Analysis

10.4-13A Design Comparisons to Recommendations of Standard Review Plan 10.4.9 Revision 1, "Auxiliary Feedwater System (PWR)" and Branch Technical Position ASB 10-1 Revision 1, "Design Guidelines for Auxiliary Feedwater System Pump Drive and Power Supply Diversity for Pressurized Water Reactor Plant" 10.4-13B Design Comparisons to NRC Recommendations on Auxiliary Feedwater Systems Contained in the March 10, 1980 NRC Letter

10.4-14 Auxiliary Feedwater System Indicating, Alarm, and Control Devices

10.4-15 Secondary Liquid Waste System - Component Data

10.0-vi Rev. 29

WOLF CREEK CHAPTER 10 - LIST OF FIGURES

  • Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference.

Figure# Sheet Title Drawing #* 10.1-1 0 Steam and Power Conversion System 10.1-2 0 Turbine Cycle Heat Balance 100 Percent of Manufacturer's Guaranteed Rating 10.1-3 0 Turbine Cycle Heat Balance Valves Wide Open 105 Percent of Manufacturer's Guaranteed Rating 10.1-4 0 Turbine Cycle Heat Balance-104.5% Thermal Power Uprate and 0 F T HOT Reduction, 1% Steam Generator Blowdown 10.2-1 1 Main Turbine M-12AC01 10.2-1 2 Main Turbine M-12AC02 10.2-1 3 Main Turbine M-12AC03 10.2-1 4 Main Turbine M-12AC04 10.2-1 5 Lube Oil Storage, Transfer and Purification System M-12CF01 10.2-1 6 Lube Oil Storage, Transfer and Purification System M-12CF02 10.2-1 7 Main Turbine Control Oil System M-12CH01 10.2-1 8 Main Turbine Control Oil System M-12CH02 10.3-1 1 Main Steam System M-12AB01 10.3-1 2 Main Steam System M-12AB02 10.3-1 3 Main Steam System M-12AB03 10-3-2 1 Main Steam System 10.4-1 1 Circulating Water & Waterbox Drains System M-12DA01 10.4-1 2 Circulating Water System M-0021 10.4-1 3 Circulating Water Waterbox Venting System M-12DA02 10.4-1 4 Circulating Water Screenhouse Plans M-0004 10.4-1 5 Circulating Water Screenhouse - Sections M-0005 10.4-2 1 Condensate System M-12AD01 10.4-2 2 Condensate System M-12AD02 10.4-2 3 Condensate System M-12AD03 10.4-2 4 Condensate System M-12AD04 10.4-2 5 Condensate System M-12AD05 10.4-2 6 Condensate System M-12AD06 10.4-3 0 Condenser Air Removal M-12CG01 10.4-4 0 Steam Seal System M-12CA01 10.4-5 1 Condensate Demineralizer System M-12AK01 10.4-5 2 Condensate Demineralizer System M-12AK02 10.4-5 3 Condensate Demineralizer System M-12AK03 10.4-6 1 Feedwater System M-12AE01 10.4-6 2 Feedwater System M-12AE02 10.4-6 3 Feedwater Heater Extraction Drains & Vents M-12AF01 10.4-6 4 Feedwater Heater Extraction Drains & Vents M-12AF02 10.4-6 5 Feedwater Heater Extraction Drains & Vents M-12AF03 10.4-6 6 Feedwater Heater Extraction Drains & Vents M-12AF04

10.0-vii Rev. 29 WOLF CREEK CHAPTER 10 - LIST OF FIGURES

  • Refer to Section 1.6 and Table 1.6-3. Controlled drawings were removed from the USAR at Revision 17 and are considered incorporated by reference.

Figure# Sheet TitleDrawing #*

10.4-6 7 Auxiliary Turbines S.G.F.P. Turbine "A" M-12FC03 10.4-6 8 Auxiliary Turbines S.G.F.P. Turbine "B" M-12FC04 10.4-7 1 Condensate Chemical Addition System M-12AQ01 10.4-7 2 Feedwater Chemical Addition System M-12AQ02 10.4-8 1 Steam Generator Blowdown System M-12BM01 10.4-8 2 Steam Generator Blowdown System M-12BM02 10.4-8 3 Steam Generator Blowdown System M-12BM03 10.4-8 4 Steam Generator Blowdown System M-12BM04 10.4-8 5 Steam Generator Blowdown System M-12BM05 10.4-9 0 Auxiliary Feedwater System M-12AL01 10.4-10 0 Auxiliary Turbines Auxiliary Feedwater Pump Turbine M-12FC02 10.4-11 0 Deleted 10.4-12 1 Secondary Liquid Waste System M-12HF01 10.4-12 2 Secondary Liquid Waste System M-12HF02 10.4-12 3 Secondary Liquid Waste System M-12HF03 10.4-12 4 Secondary Liquid Waste System M-12HF04

10.0-viii Rev. 17 WOLF CREEK CHAPTER 10.0 STEAM AND POWER CONVERSION SYSTEM 10.1

SUMMARY

DESCRIPTION The steam and power conversion system is designed to remove heat energy from the reactor coolant in the four steam generators and convert it to electrical energy. The system includes the main steam system, the turbine-generator, the main condenser, the condensate system, the feedwater system, and other auxiliary systems. The turbine cycle is a closed cycle with water as the working fluid. Two stages of reheat and seven stages of regeneration are included in the cycle. The heat input is provided by reactor coolant in the steam generators. Work is performed by the expansion of the steam in the high and low pressure turbines. Steam is condensed and waste heat is rejected by the main condenser. The condensate and feedwater systems preheat and

pressurize the water and return it to the steam generators, thereby closing the cycle.Figure 10.1-1 is an overall flow diagram of the steam and power conversion system. Table 10.1-1 gives the major design and performance data of the system and its major components. Heat balances at manufacturer's rated power and valves wide open (VWO) power are included as Figures 10.1-2 and 10.1-3, respectively. An estimated heat balance at the power rerate target operating condition (104.5% Thermal Power Up Rate and 0 F T HOT Reduction) is included as Figure 10.1-4.

The safety related design features are discussed in the sections of Chapter 10 which are devoted to the individual systems comprising the steam and power conversion system.

10.1.1 GENERAL DISCUSSION The main steam system supplies steam to the high pressure turbine and the second stage of steam reheating. The steam is expanded in the high pressure turbine. High pressure turbine extraction steam supplies the first stage of steam reheating and the sixth and seventh stage feedwater heaters. High pressure turbine exhaust steam is fed to the combined moisture separator

reheaters (MSRs) and the fifth stage feedwater heaters. Steam is dried and superheated in the MSRs before it is supplied to the low pressure turbines and to the steam generator feedwater pump (SGFP) turbines. Extraction steam from the low pressure turbines supplies the low pressure feedwater heaters. The steam generator blowdown (SGB) flash tank steam is fed to the fifth stage

feedwater heaters.

Exhaust steam from the low pressure turbines is condensed and deaerated in the main condenser. Volume change in the secondary side fluid is handled by the surge capacity of the condensate storage tank. Heating of the condensate first occurs in the 10.1-1 Rev. 18 WOLF CREEK reheating hotwells of the main condenser; the heating system is the SGFP turbine exhaust. Condensate is pumped from the condenser hotwells by the main condensate pumps through the condensate demineralizers (when in service) and the low pressure feedwater heaters to the suction of the SGFP. A portion of the condensate is directed to the SGB regenerative heat exchanger to recover additional heat while cooling the blowdown. The heater drain pumps feed the suction of the SGFPs from the heater drain tank. Feedwater is pumped through the high pressure feedwater heaters to the steam generators by means of the SGFPs.10.1.2 PROTECTIVE FEATURES

10.1.2.1 Loss of External Electrical Load and/or Turbine Trip Load rejection capabilities of the steam and power conversion systems are discussed in Section 10.3.

10.1.2.2 Overpressure Protection Overpressure protection for the steam generators is discussed in Section 10.3.

The following components are provided with overpressure protection in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII:

a. MSRs
b. Low pressure feedwater heaters
c. High pressure feedwater heaters
d. Heater drain tank
e. SGB flash tank
f. SGB regenerative heat exchanger 10.1.2.3 Loss of Main Feedwater Flow Loss of main feedwater flow is discussed in Section 10.4.9.

10.1.2.4 Turbine Overspeed Protection Turbine overspeed protection is discussed in Section 10.2.2.3 and 3.5.1.3.

10.1.2.5 Turbine Missile Protection Turbine missile protection is discussed in Sections 10.2.3 and 3.5.1.2. 10.1-2 Rev. 18 WOLF CREEK 10.1.2.6 Radioactivity Under normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system. It is possible for this system to become contaminated by a steam generator tube leakage. In this event, radiological monitoring of the main condenser air removal system

and the steam generator blowdown system, as described in Section 11.5, will

detect contamination.

Equilibrium secondary system activities, based on assumed primary-to-secondary side leakages, are developed in Chapter 11.0. The steam generator blowdown

system and the condensate demineralizer system serve to limit the radioactivity

level in the secondary cycle, as described in Sections 10.4.6 and 10.4.8. 10.1-3 Rev. 0 WOLF CREEK TABLE 10.1-1

SUMMARY

OF IMPORTANT DESIGN FEATURES AND PERFORMANCE CHARACTERISTICS OF THE STEAM AND POWER CONVERSION SYSTEM Nuclear Steam Supply System, Full Power Operation Rated NSSS power, MWt 3,425 Steam generator outlet pressure, psia 1,000 Steam generator inlet feedwater temp, F 444.5 Steam generator outlet steam moisture, % 0.25 Quantity of steam generators per unit 4 Flow rate per steam generator, 10 6 lb/hr 3.785 Nuclear Steam Supply System, Target Power Rerate Operation (104.5% Thermal Power Up Rate and 0 F T HOT Reduction)

NSSS power, MW (th) 3,579 Steam Generator outlet pressure, psia 970 Steam Generator inlet feedwater temp, °F 446 Steam Generator outlet steam moisture, % 0.25 Flow rate per steam generator, 10 6 lb/hr 3.98

Nuclear Steam Supply System, Reduced Thermal Design Flow Operation

NSSS power, MW (th) 3,579 Steam Generator outlet pressure, psia 944 Steam Generator inlet feedwater temp, °F 446 Steam Generator outlet steam moisture, % 0.25 Flow rate per steam generator, 10 6 lb/hr 3.98 Turbine Generator

Secondary Power Uprate Rating, MWe 1268 Turbine type Tandem compound six flow, 1 high pressure turbine, 3 low pressure turbines Operating speed, rpm 1,800 Number of stages 16 Moisture Separator Reheater (MSR)

Stages of reheat 2 Stages of moisture separation 1 Quantity of MSRs per unit 4

Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 2)

Main Condenser

Type Multiple pressure, 3-shell Quantity, per unit 1 Condensing capacity, Btu/hr 7.87 x 10 9 Circulating water flow rate See Section 10.4.5 Circulating water temperature rise See Section 10.4.5

Condenser Vacuum Pumps

Type Rotary, motor driven, water sealed Hogging capacity, each, std. Cfm 72 @ 5 in. Hga Holding capacity, each, std. Cfm 35 @ 1 in. Hga Pump speed, rpm 435 Motor hp, each 150 Motor speed, rpm 1,800 Quantity, per unit 3 Condensate Pumps

Type Vertical, centrifugal motor driven Design Conditions Flow, gpm 7,266 Total head, ft 1,285 Motor hp 3,500 Quantity per unit 3

Feedwater Heaters

Low Pressure Design Primary and Secondary Power Uprates a. No. 1 Quantity per unit 3 3 Duty, Btu/hr 2.056 x 10 8 2.42 x 10 8

b. No. 2 Quantity per unit 3 3 Duty, Btu/hr 1.262 x 10 8 1.31 x 10 8 c. No. 3 Quantity per unit 3 3 Duty, Btu/hr 2.425 x 10 8 2.30 x 10 8
d. No. 4 Quantity per unit 3 3 Duty, Btu/hr 1.276 x 10 8 1.22 x 10 8

Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 3)

High Pressure Design Primary and Secondary Power Uprates e. No. 5 Quantity per unit 2 2 Duty, Btu/hr 2.415 x 10 8 2.40 x 10 8 f. No. 6 Quantity per unit 2 2 Duty, Btu/hr 3.259 x 10 8 3.38 x 10 8

g. No. 7 Quantity per unit 2 2 Duty, Btu/hr 3.354 x 10 8 3.45 x 10 8 Steam Generator Feedwater Pumps Pump type Horizontal, centrifugal Turbine type Multistage noncondensing Quantity per unit 2

Design conditions, pump Flow, gpm 17,620 Total head, ft 2,387 Turbine hp @ 5,560 rpm 14,328

Motor-Driven Feedwater Pump

Type Horizontal, centrifugal

Motor driven Design conditions Flow, gpm 480 Total head, ft 1,820 Motor hp 300 Quantity per unit 1

Heater Drain Pumps Type Vertical, centrifugal Motor driven Design conditions Flow, gpm 5,670 Total head, ft 910 Motor hp 1,500 Quantity per unit 2

Steam Generator Blowdown Regenerative Heat Exchanger Duty, Btu/hr 26.64 x 1O 6 Quantity per unit 1

Rev. 25 WOLF CREEK TABLE 10.1-1 (Sheet 4)

Steam Generator Blowdown Flash Tank Steaming rate, lb/hr 40,000-52,800 (max. blowdown)

Outlet steam pressure, psia 135-185

Quantity per unit 1 Heater Drain Tank Quantity per unit 1 Operating pressure, psia 166.6

Rev. 13

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Rev. 25 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 10.1-4 Turbine Cycle Heat Balance 104.5% Thermal Power Update and 0 °F T HOT Reduction 1% Steam Generator Blowdown

10.2 TURBINE GENERATOR The turbine generator (T-G) receives high pressure steam from the main steam system and converts a portion of its thermal energy into electrical energy.

The T-G also supplies extraction steam and condensate for feedwater heating and

steam for driving the steam generator feedwater pump turbines.

During Refueling 18 (RF18), three replacement LP-steampaths comprised of rotors, inner casings and diaphragms, and a single HP steampath consisting of a rotor and diaphragms were installed. The last stage buckets for the LP rotors increased from 38" to 43". The new DensePack TM HP increased from 7-stages to 9-stages. Each rotor was manufactured by General Electric (GE) from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking, while increasing turbine efficiency.

To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. Therefore, the three LP turbines maintain their original stage numbering, starting with the 8 th stage. This allows all extraction locations to remain numbered per the original design.

10.2.1 DESIGN BASES 10.2.1.1 Safety Design Bases

The T-G serves no safety function and has no safety design basis.

10.2.1.2 Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The T-G is intended for base load

operation. The gross generator outputs as rated reactor power and stretch of

valves wide open (VWO) power are given on Figures 10.1-2 and 10.1-3, respectively. The gross generator output at the power rerate operating condition is given on Figure 10.1-4.

POWER GENERATION DESIGN BASIS TWO - The T-G load change characteristics are

compatible with the instrumentation and control system which coordinates T-G and reactor operation.

POWER GENERATION DESIGN BASIS THREE - The T-G is designed to accept a sudden

loss of full load without exceeding design over-speed.

POWER GENERATION DESIGN BASIS FOUR - The T-G is designed to permit periodic testing of steam valves important to overspeed protection, emergency overspeed

trip circuits, and several other trip circuits under load.

POWER GENERATION DESIGN BASIS FIVE - The failure of any single component will

not cause the rotor speed to exceed the design speed.

POWER GENERATION DESIGN BASIS SIX - Unlimited access to all levels of the

turbine area under all operating conditions is provided.

10.2.2 SYSTEM DESCRIPTION 10.2.2.1 General Description The T-G system is shown in Figure 10.2-1. Performance characteristics are

provided in Section 10.1.

10.2-1 Rev. 25 WOLF CREEK The turbine consists of double-flow, high-pressure, and low-pressure elements in tandem. Moisture separation and reheating of the steam are

provided between the high-pressure and low-pressure elements by four combined moisture separator reheater (MSR) assemblies. Two assemblies are located on each side of the T-G center-line. The generator is

coupled directly to the turbine shaft. It is equipped with an

excitation system coupled directly to the generator shaft.

T-G accessories include the bearing lubrication oil system, turning gear, hydrogen system, seal oil system, stator cooling water system, exhaust hood spray system, steam seal system, and turbine supervisory

instrument (TSI) system.

The analog Electro-Hydraulic Control (EHC) system has been replaced with a new digital Turbine Control system (TCS). The new system utilizes an Ovation-Based Distributed Control system (DCS). Two redundant sets of controllers are used in the turbine control system.

The turbine control system architecture is based on combined functional and hardware redundancy to create a robust and reliable system. In order to increase reliability of the new TCS, the Ovation system is provided with redundancy as follows:

1. Two 100% capable controllers, one primary and one backup dedicated to Over Speed Protection and Trip function - Ovation Emergency Trip System (ETS).
2. Two 100% capable controllers, one primary and one backup dedicated to Turbine Control and providing backup Over Speed Protection and Trip Function - Ovation Operator Auto/Overspeed Protection and Control (OA/OPC).
3. The system is configured to provide cross trips between the two sets of redundant controllers.
4. Diverse Overspeed Protection (DOPS) using Woodward ProTech GII modules. The ETS and the OA/OPC controllers interface with two sets of diverse and independent speed probes, which measure turbine speed. One set consists of three passive speed probes which interface to the ETS controller. The other set consists of three active probes which interface to the OA/OPC controller.

Both of the TCS controllers - OA/OPC and ETS - perform the Emergency Trip function. Each controller has an associated solenoid-operated valve Testable Dump Manifold (TDM) that releases Electro-Hydraulic (EH) oil pressure, and causes the main stop valves, the control valves, the intermediate stop valves, and the intercept valves to rapidly close, thus blocking the flow of steam to the turbine. To prevent both function failure and spurious activation from a single solenoid control circuit failure, each manifold operates on a "two-out-of-three" coincidence voting logic.

An additional set of three passive speed probes interface with the Woodward ProTech GII modules to provide a diverse overspeed trip. DOPS contact outputs trip the turbine through the ETS TDM using "two-out-of-three" coincidence voting logic.

10.2-2 Rev. 27 WOLF CREEK The T-G unit and associated piping, valves, and controls are located completely within the turbine building. There are no safety-related systems or components located within the turbine building (See Figures 1.2-29 through 1.2-42), hence any failures associated with the T-G unit will not affect any safety-related equipment. Failure of T-G equipment does not preclude safe shutdown of the reactor coolant system. There is unlimited access to T-G components and instrumentation associated with T-G overspeed protection, under all operating conditions.

10.2.2.2 Component Description The MSRs, MSR drain tanks, stator water coolers, and stator water demineralier are designed to ASME Section VIII. The balance of the T-G is designed to General Electric (GE) Company Standards.

MAIN STOP AND CONTROL VALVES - Four high pressure, angle body, main stop and control valve chests admit steam to the high pressure (HP) turbine. The primary function of the main stop valves is to quickly shut off the steam flow to the turbine under emergency conditions. The primary function of the control valves is to control steam flow to the turbine in response to the turbine control system. The four sets of valves are located at El. 2033, south of the high pressure turbine shell. The valve chests are made of a copper-bearing, low-carbon steel. The main stop valves are single disc type valves operated in an open-closed mode either by the emergency trip, fluid operated, fast acting valve for tripping, or by a small solenoid valve for testing. The discs are totally unbalanced and cannot open against full differential pressure. An internal bypass valve is provided in the number two main stop valve to pressurize the below seat areas of the four valves.

Springs are designed to close the main stop valve in 0.19 second under

the emergency conditions listed in Section 10.2.2.3.4.

Each main stop valve has one inlet and one outlet. The outlet of each

valve is welded directly to the inlet of a control valve casing. The

four stop valves are also welded together through below-seat

equalizers. Each stop valve contains a permanent steam strainer to prevent foreign matter from entering the control valves and turbine.

The control valves are poppet-type valves with venturi seats. The

valve discs have sperical seats to ensure tight shutoff. The valves

are of sufficient size, relative to their cracking pressure, to require partial balancing. This is accomplished by a skirt on the valve disc sliding inside a balance chamber. When a control valve starts to open, a small internal valve is opened to decrease the pressure in the

balance chamber. Further lifting of the stem opens the main disc.

Each control valve is operated by a single acting, spring-closed

servomotor opened by high pressure fire-resistant fluid through a servo valve. The control valve is designed to close in 0.20 seconds.

HIGH PRESSURE TURBINE - As discussed at the beginning of Section 10.2, a new nine-stage HP turbine was installed in RF18, replacing the

original seven-stage turbine. To maintain configuration consistency, the numbering of the stages for the new 9-stage HP turbine are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the extraction locations to remain

10.2-3 Rev. 27 WOLF CREEK numbered per the original design. The HP turbine receives steam through four pipes, called steams leads, one from each control valve outlet. The steam is expanded axially across nine stages of stationary and moving blades. Steam pressure immediately downstream of the first stage is used as a load reference signal for reactor control.

Extraction steam from the third turbine stage supplies the seventh stage of feedwater heating and the first stage of steam reheating.

Extraction steam from the fifth and seventh turbine stages supplies the sixth and fifth stages of feedwater heating, respectively. Turbine exhaust steam is collected in eight pipes called cold reheat pipes, four at each end of the turbine.

The new HP rotor was forged from a single piece of alloy steel, per GE specification (similar to ASTM A470), employing integral wheels and couplings (monoblock design). The monoblock rotor is designed with modern low stress dovetail profiles. There are nine stages of advanced design buckets (TE and GE -18 rows). The buckets utilize a 12 percent Chromium Alloy, similar to ASTM A479 Type 403.

MOISTURE SEPARATOR REHEATERS - Four horizontal cylindrical-shell, combined moisture separator reheater (MSR) assemblies are installed in the steam lines between the high and low pressure turbines. The MSRs serve to dry and reheat the steam before it enters the low pressure turbine. This improves cycle efficiency and reduces moisture-related erosion and corrosion in the low pressure turbines. Steam from the high pressure turbine is piped into the bottom of the MSR. Moisture is

removed in chevron-type moisture separators, and is drained to the

moisture separator drain tank and from there to the heater drain tank.

The dry steam passes upward across the tube bundle of the first stage reheater. The first stage reheater steam source is extraction steam

from the third HP turbine stage. The reheater is drained to the first

stage reheater drain tank and from there to the sixth feedwater heater.

The dried and reheated steam then passes through the tube bundle of the second stage reheater. The second stage reheater steam source is main steam. The reheater is drained to the second stage reheater drain tank

and from there to the seventh feedwater heater. Safety valves are

provided on the MSR for overpressure protection.

COMBINED INTERMEDIATE VALVES - Two combined intermediate valves (CIV) per LP turbine are provided, one in each steam supply line, called the

hot reheat line, from the MSR. The CIV consists of two valves sharing

a common casing. The two valves are the intercept valve and the

intermediate stop valve. Although they utilize a common casing, these valves have entirely separate operating mechanisms and controls. The function of the CIVs is to protect the turbine against over-speed from

stored steam between the main stop and control valves and the CIVs.

Three CIVs are located on each side of the turbine.

Steam from the MSR enters the single inlet of each valve casing, passes through the permanent basket strainer, past the intercept valve and stop valve disc, and discharges through a single outlet connected to

the LP turbine. The CIVs are located as close to the LP turbine as

possible to limit the amount of controlled steam available for

overspeeding the turbine. Upon loss of load, the intercept valve first closes then throttles steam to the LP turbine, as required, to control speed and maintain synchronization. It is capable of opening against

full system pressure. The intermediate stop valve closes only if the

intercept valves fail to operate properly. It is capable of opening

10.2-4 Rev. 27 WOLF CREEK against a pressure differential of approximately 15 percent of the maximum expected system pressure. The intermediate stop valve and

intercept valve are designed to close in 0.2 second.

LOW PRESSURE TURBINES - As discussed at the beginning of Section 10.2, new LP steam paths were installed in RF18. To maintain configuration

consistency, the numbering of the stages for the new 9-stage HP turbine

are 1, 2, 3, 3a, 4, 5, 5a, 6 and 7. This allows the LP turbine stages to remain numbered per the original design (8 through 14). Each LP turbine receives steam flow from two CIVs. The steam is expanded

axially across seven stages of stationary and moving buckets.

Extraction steam flow from stages 8, 9, 11 and 12 supply the fourth, third, second and first stage of feedwater heating, respectively. The ninth stage extraction is also the normal source of turbine gland sealing steam. The thirteenth turbine stage is a moisture removal

stage where moisture is removed to protect the last stages from erosion

induced by water droplets. This extraction is drained directly to the

condenser.

The LP steam paths were designed using 43-inch last stage buckets on

monoblock rotors with compatible diaphragms and new inner casings. The

steam paths consist of three sets of seven stage, double-flow rotors

without bore, utilizing an alloy similar to ASTM A470 and designed with modern low-stress dovetails.

Forged bucket material utilizes 12 percent Chromium Alloy, similar to

ASTM A470 XM30. The last stage leading edge buckets are flame-hardened

for protection against water droplet erosion and are designed for continuous operation at exhaust pressures up to 5.5 inches HgA. The prior two stages are also flame-hardened for erosion protection.

EXTRACTION NONRETURN VALVES - Upon loss of load, the steam contained

within turbine extraction lines would flow back into the turbine, across the remaining turbine stages, and into the condenser.

Condensate contained in feedwater heaters will flash to steam under

this condition and contribute to the backflow of steam. Extraction

nonreturn valves are installed in the third, fifth, eighth, ninth, and

eleventh stage turbine extraction lines to guard against this backflow of steam and the contribution it would make to a rotor overspeed condition. The nonreturn valves are free-swinging. The eleventh stage

nonreturn valves have double "D" swing plates. The plates are closed

by a torsion spring as flow decreases. For the remaining nonreturn

valves, under normal operation, air bears against a piston which mechanically prevents a coiled spring from assisting in valve closure.

Upon turbine trip, the air is dumped to atmosphere via the turbine

control system's air relay dump valve.

GENERATOR - The generator operates at 1,800 rpm and is rated at

1,409,000 kVA at 75 psig hydrogen pressure and a 0.92 power factor.

The stator core and rotor conductors are cooled by hydrogen circulated

by fans mounted at each end of the generator shaft. Two water-cooled

hydrogen coolers are mounted in the generator frame. A seal oil system

isolated the hydrogen from the atmosphere. The stator conductors are

water cooled.

The rotor consists of layers of field windings embedded in milled

slots. The winding material is silver-bearing copper in preformed

coils, carried in molded glass liners in the slots. The windings are

held radially by steel slot wedges at the rotor outside diameter. The 10.2-5 Rev. 28 WOLF CREEK wedge material maintains its mechanical properties at elevated temperature, which could occur as a result of loss of cooling, for example. The magnetic field is generated by dc power which is fed to the windings through collector rings located outboard of the main generator bearings. The rotor body and shaft is machined from a single, solid steel forging. The material is a nickel-molybdenum-vanadium alloy steel. Detailed examinations and tests are carried out at each stage of rotor manufacture. These include:

a. Material property checks on test specimens taken from the forging
b. Ultrasonic tests for internal flaws
c. Photomicrographs for examination of microstructure
d. Magnetic particle and ultrasonic examination of the bore
e. Surface finish tests of slots for indication of a stress riser The rotor end turns are restrained against centrifugal force by retaining rings. The rings are the highest stressed components of the generator. The retaining ring is shrunk on a machined fit at the end of the rotor body. It is locked against axial and circumferential movement by a locking ring screwed into the retaining ring and keyed to the rotor body. The ring material is a manganese-chromium, alloy steel forging. All retaining ring forgings are tested for chemical composition, tensile properties, Charpy-V notch impact properties, grain size, internal flaws by ultrasonic inspection, surface flaws by dye penetrant inspection, and performance by cyclic hydrostatic testing. 10.2.2.3 System Operation 10.2.2.3.1 Normal Operation

Under normal operation, the main stop valves and CIVs are wide open.

Operation of the T-G is under the control of the TCS OA/OPC controller.

The OA/OPC controller performs speed control, load control and flow control as well as backup overspeed protection.

Speed Control The OA/OPC controller receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket with no mechanical modifications required. The probes are powered by redundant 24VDC power supplies within the drop. The three signals are received into the system via separate modules located on separate I/O branches. The median speed signal is selected to provide speed feedback to the system. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped. A rate of acceleration is calculated from the selected signal to determine appropriate actions of the control valves.

A speed setpoint and a rate are entered by the operator via a graphical interface. The speed control ramps to the speed setpoint at the rate entered by the operator using closed loop control. In startups, when the turbine is identified to be in a critical speed range where high

10.2-6 Rev. 27 WOLF CREEK vibrations can be observed, the control system accelerates the speed to the maximum rate as determined by the turbine manufacturer until the speed is outside the critical range. The control system then returns to the operator pre-set speed rate. The operator cannot enter a critical speed value as a "go to" speed in RPM.

Load Control / Flow Control The OA/OPC controller controls the load of the turbine. The load control has two operator selectable loops, the First Stage Pressure (FSP) or megawatt (MW) loop. When the MW loop is placed into service, the system maintains closed loop control using two new megawatt transducers as feedback. When the first stage pressure loop is placed into service, the system uses three new pressure transmitters as a median selected value for feedback. The load control loops are mutually exclusive where only one can be placed into service at a time.

The load control function generates a flow reference that is sent to the control and intercept valves for position control. Each modulating valves position is controlled by redundant valve positioner modules.

The operator enters a load setpoint and rate in the same manner as the speed control function. The values entered are checked for exceeding limits and are rejected in such situations. The load setpoint of the turbine can be changed manually or automatically depending on circumstances which cause the T-G protection circuits to come into action. For example, stator cooling water system trouble will automatically cause the maximum permissible load to be reduced. The load rates are generated within the system by predefined values. The reactor is capable of accepting these rates without abnormal effect or bypass of steam to the atmosphere or condenser.

The load control receives a speed error signal to correct speed variations while in load control. The error is limited to allow correction in the speed increasing direction only.

10.2.2.3.2 Operation Upon Loss of Load Upon loss of generator load, the EHC system acts to prevent rotor speed from exceeding design overspeed. Refer to Table 10.2-1 for the description of the sequence of events following loss of turbine load.

Failure of any single component will not result in rotor speed exceeding design overspeed (i.e. 120 percent of rated speed). The following component redundancies are employed to guard against overspeed:

a. Main stop valves/Control valves
b. Intermediate stop valves/Intercept valves
c. OA/OPC controller - Primary speed control / Overspeed trip /

Speed detector module trip

d. Fast acting solenoid valves/Emergency trip fluid system (ETS)
e. ETS controller - Overspeed trip / Speed detector module trip /

Diverse overspeed protection system trip

The main stop valves and control valves are in series and have

completely independent operating controls and operating mechanisms.

Closure of either all four stop valves or all four control valves shuts off all main steam flow to the HP turbine. The combined stop and

10.2-7 Rev. 27 WOLF CREEK intercept valves are also in series and have completely independent operating controls and operating mechanisms. Closure of either all six stop valves or all six intercept valves shuts off all MSR outlet steam flow to the three LP turbines.

The OA drop speed control receives speed feedback from three new active speed sensor probes that are installed into the existing speed bracket.

Increase of speed will begin to close the control valves. In the event of a lost speed signal the system operates on the average of the two remaining signals. When the loss of two signals occurs in speed control the turbine is tripped.

Fast acting solenoid valves initiate fast closure of control valves under load rejection conditions that might lead to rapid rotor acceleration. The solenoid valve dumps ETS pressure at the control valve. Valve action occurs when power exceeds load by more than 40 percent and generator current is lost suddenly. The ETS initiates fast closure of the valves whether the fast-acting solenoid valves work or not. The ETS pressure is dumped by either the ETS TDM or the OA/OPC TDM. If speed control should fail, the overspeed trip devices must close the steam admission valves to prevent turbine overspeed. Woodward ProTech GII modules provide a diverse overspeed trip as a replacement for the mechanical trip bolt. It is set to operate at 110 percent of rated speed. Ovation ETS and OA/OPC controller overspeed trip setpoints are 110% (1980 RPM). Ovation SDM hard-wired trips provide a backup overspeed trip set at 111% (1998 RPM). Component redundancy and fail safe design of the ETS hydraulic system and trip circuitry provide turbine overspeed protection. The combination of Ovation ETS and OA/OPC controller trips, hardwired overspeed protection found within the Ovation Speed Detector Modules (SDMs), and Woodward ProTech GII modules provide diverse measures for safeguarding the turbine.

Overspeed trips are initiated through either the ETS TDM or the OA/OPC TDM. Single component failure does not compromise trip protection.

OA/OPC Controller OA/OPC TDM configuration is de-energized to trip and can be actuated by any of the following conditions:

1. The OA/OPC controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the ETS controller.
2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
3. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated.

Loss of both primary and backup 24 Vdc auxiliary power de-energizes the TDM which results in a trip. Loss of power trips the turbine through fail safe circuitry.

ETS Controller The ETS TDM configuration is de-energized to trip and can be actuated by any of the following conditions:

10.2-8 Rev.

27 WOLF CREEK

1. The ETS controller generates a trip output based on application logic that is generated from soft trip inputs, overspeed detection and cross trips from the OA/OPC controller.
2. Ovation speed detector modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
3. Woodward ProTech GII modules use normally closed relay output contacts wired to de-energize the TDM when an overspeed condition occurs.
4. Actuation of both main console hardwired pushbuttons de-energizes the TDM when a manual trip is initiated.

Loss of two-out-of-three 125 Vdc power supplies from the station batteries de-energizes the TDM which results in a trip.

Loss of power trips the turbine through fail safe circuitry. The TDMs are powered via separate systems. The ETS TDM is powered via three independent 125VDC station batteries. The OA/OPC TDM is powered from redundant 24VDC power supplies powered by two separate 120VAC UPS systems. 10.2.2.3.3 Testing Each TDM can be tested online via Ovation HMI displays to verify the solenoids have de-energized. Only one solenoid and one TDM can be tested at a time. The overspeed trip devices can be tested in accordance to the plant operation. The soft overspeed trip can be tested by setting a value below normal operating speed during startup.

The hard-wired trips can be tested independently by removing a speed probe from operation and injecting a signal from a function generator that will exceed the module set threshold. This test will only activate the signal and solenoid for the hardwired circuit.

10.2.2.3.4 Turbine Trips

a. Emergency trip pushbuttons in control room. Two pushbuttons must be pressed simultaneously.
b. Moisture separator high level
c. Low condenser vacuum
d. Low lube oil pressure
e. Deleted
f. Reactor trip
g. Thrust bearing wear
h. Overspeed (ETS TDM and OA TDM)
i. Manual trip handle on TDM stand
j. Loss of stator coolant (2 minute and 3.5 minute trip)
k. Low hydraulic fluid pressure 10.2-9 Rev. 27 WOLF CREEK l. Any generator trip
m. Loss of TDM electrical power
n. Excessive vibration
o. AMSAC 10.2.3 TURBINE INTEGRITY 10.2.3.1 Materials Selection The material used for the new monoblock rotors is a forged nickel-chrome-molybdenum-vanadium alloy that is similar to ASTM Class 6. A GE material specification was used for the actual material in order to tightly control the condition of the resulting forgings. Ranges of key alloying elements were defined; maximum permissible levels of tramp elements were defined; process procedures affecting properties, such as heat treatments were specified; and the permissible ranges or levels of mechanical properties at each of the acceptance test locations were specified. The forging alloys used in the HP and LP rotors are extremely similar. The property differences are due to the range of strengths and properties needed for the nuclear HP and LP rotor applications.

10.2.3.2 Fracture Toughness The original turbine rotors had shrunk on disks and couplings. New turbine rotors were installed in RF18. Each rotor was manufactured by GE from a single piece of alloy steel forging employing integral wheels and couplings (monoblock design), which resulted in reduced rotor stresses and reduced potential for cracking. The brittle fracture failure mechanism in rotors with shrunk on wheels was due to the initiation and growth of stress corrosion cracks to critical size in the exposed wheel keyway surfaces. The probability of this failure mode is dependent on environment, speed, temperature and material properties, as well as inspection methods and inspection intervals.

For a shrunk-on wheel operated at, or near, normal running speed, the probability of bursting and thus of missile generation, was dominated by this fracture mechanism. The new rotors are of monoblock construction and do not have shrunk-on wheels. Therefore, the formerly dominant brittle fracture failure mechanism is eliminated in monoblock rotors. With the installation of the new monoblock rotors, the concern of rotor disk integrity is eliminated.

10.2.3.3 High Temperature Properties Primarily, the life limiting factors for rotors are attributable to the higher temperature dependent phenomena, typically in the range of 650ºF or higher. Material creep, thermal fatigue and embrittlement are the major factors that can limit a rotor's useful life. The Wolf Creek rotor components operate at temperatures less than 575ºF. Therefore, the material creep rupture at high temperatures is not a consideration; and embrittlement and the rotor thermal transient stress that can cause low cycle fatigue are not significant factors. The primary design parameters in the design of the nuclear monoblock rotors are therefore the shaft bending and torsional stresses, centrifugal stress, and 10.2-10 Rev.

27 WOLF CREEK stress corrosion cracking protection. These factors have been properly engineered, with operating conditions and reasonably controlled environment, to design the rotors for the intended life.

10.2.3.4 Turbine Design In the design of the monoblock rotor, the rotor dynamic bending

stresses and torsional stresses were kept to a minimum by maintaining reasonable operating margins between the rotor natural frequencies and the known potential stimulas. The rotor geometry was also optimized to

accommodate manufacturing and operating tolerances such as bearing

misalignment and electrical transients, etc. These design practices

ensure that the potential vibratory stresses are kept below the fatigue strength endurance limit of the component materials.

10.2.3.5 Preservice Inspection

The preservice procedures and acceptance criteria are as follows:

a. The rotor forgings were subjected to an NDT acceptance procedure by the forging vendors and an NDT acceptance

procedure by GE.

b. Preliminary pre-service peripheral ultrasonic examinations were performed on the monoblock rotor forgings. The rotor

forgings were semi-machined to provide a suitable surface for

the ultrasonic inspection. After the final heat treatment, a

battery of NDT testing was performed to ensure rotor structural integrity. Prior to accepting a monoblock forging, extensive specimen testing was performed to assure that the

rotor met the application requirements.

c. All finished machined surfaces are subjected to a magnetic particle test with no flaw indications permissible.
d. Each fully bucketed turbine rotor assembly is spin tested

at 20-percent overspeed.

Additional preservice inspections include air leakage tests performed to determine that the hydrogen cooling system is tight before hydrogen

is introduced into the generator casing. The hydrogen purity is tested

in the generator after hydrogen has been introduced. The generator

windings and all motors are megger tested. Vibration tests are performed on all motor-driven equipment. Hydrostatic tests are performed on all coolers. All piping is pressure tested for leaks.

Motor-operated valves are factory leak tested and inplace tested once

installed.

10.2.3.6 Inservice Inspection

The inservice inspection program for the turbine assembly includes the

disassembly of the turbine and complete inspection of all normally

inaccessible parts, such as couplings, coupling bolts, turbine shafts, low-pressure turbine buckets, and high-pressure rotors. During plant shutdown coinciding with the inservice inspection schedule for ASME Section III components, as required by the ASME Boiler and Presser

Vessel Code,Section XI, turbine inspection is done in sections during

the refueling outages so that in 10 years total inspection has been

completed at least once.

10.2-11 Rev. 27 WOLF CREEK This inspection consists of visual and surface examinations as indicated below:

a. Visual examination of all accessible surfaces of rotors
b. Visual and surface examination of all low-pressure buckets
c. 100-percent visual examination of couplings and coupling bolts

The inservice inspection of valves important to overspeed protection

includes the following:

a. All main stop valves, control valves, extraction nonreturn

valves, and CIVs are tested underload. Operator Workstation

Graphic displays will permit full stroking of the stop valve, control valves, and CIVs. Valve position indication is

provided on the graphic display. No load reduction is necessary before testing main stop valves and CIVs.

Extraction nonreturn valves are tested locally by equalizing

air pressure across the air cylinder. Movement of the valve

arm is observed upon action of the spring closure mechanisms.

b. Main stop valves, control valves, and CIVs are tested quarterly. Extraction nonreturn valves are tested daily.

Closure of each valve during test is verified by direct

observation of the valve motion.

c. All main stop, main control, and CIVs are inspected on a frequency that meets or exceeds the minimum inspection

requirements established by the company's insurance provider (Nuclear Electric Insurance Limited) Loss Control Standards.

These inspections are conducted for:

Wear of linkages and stem packings

Erosion of valve seats and stems

Deposits on stems and other valve parts which could interfere with valve operation Distortions, misalignment

Inspection of all valves of one type will be conducted if any unusual condition is discovered 10.2.4 EVALUATION

The reactor system is a PWR type; hence, under normal operating conditions, there are no significant radioactive contaminants present in the steam and power conversion system.

No radiation shielding is required for the turbine-generator system.

Continuous access to the components of the system for inservice inspection, etc., is possible during all operating conditions. Even in the event of a large primary-to-secondary steam generator leak, the T-G

system will not become contaminated to the extent that access is

precluded.

10.2-12 Rev. 27 WOLF CREEK A full discussion of the radiological aspects of primary-to-secondary leakage, including anticipated operating concentrations of radioactive contamination, anticipated releases to the environment, and limiting

conditions for operation, is included in Chapter 11.0.

10.

2.5 REFERENCES

1. Begley, J. A., and Logsdon, W. A., "Correlation of Fracture

Toughness Charpy Properties for Rotor Steels," Westinghouse, Scientific Paper 71-1E7-MSLRF-P1, July 26, 1971

2. Spencer, R.C., and Timo, D. P., "Starting and Loading of Turbines," General Electric Company, 36th Annual Meeting of the American Power Conference, Chicago, Illinois, April 29-May 1, 1974
3. Engineering Design Summary, WCNOC Turbine Upgrade Retrofit Project, General Electric Company, GE Energy

Engineering Division, Schenectady, New York, Rev. A, ated 25 March 2010. Wolf Creek document number M-800-

00391.

10.2-13 Rev. 27

WOLF CREEK TABLE 10.2-1 EVENTS FOLLOWING LOSS OF TURBINE LOAD WITH POSTULATED EQUIPMENT FAILURES Approximate

Speed-Percent Event 100 Full load is lost. Speed begins to rise.

101 Control and intercept valves begin

to close. As turbine stage

pressures decrease, extraction

nonreturn valves swing closed.

104 Control and intercept valves fully

closed.

109 Peak transient speed with normally

operating control system.

Assume that power/load unbalance

and speed control systems had

failed prior to loss of load.

110 Diverse Overspeed Protection System (DOPS) or OA/ETS soft trip signals all valves to close.

Operation of air relay dump valves releases spring closure mechanisms of extraction nonreturn valves.

111 Backup overspeed trip from OA/ETS Speed Detector Module (SDM) signals all valves to close.

113 All valves full closed, activated

by DOPS trip.

114 All valves fully closed, activated

by OA/ETS SDM trip.

Rev. 27 WOLF CREEK TABLE 10.2-1 (Sheet 2)

Approximate

Speed-Percent Event

119 Peak transient speed with normal

control system failure and

operation of DOPS trip.

120 Peak transient speed with failure

of both normal control systems and

DOPS trips, proper operation of backup OA/ETS SDM overspeed trip.

Rev. 27 WOLF CREEK 10.3 MAIN STEAM SUPPLY SYSTEM The function of the main steam supply system (MSSS) is to convey steam generated in the steam generators by the reactor coolant system to the turbine-generator system and auxiliary systems for power generation.

10.3.1 DESIGN BASES

10.3.1.1 Safety Design Bases The portion of the MSSS from the steam generator to the steam generator

isolation valves is safety related and is required to function following a DBA

and to achieve and maintain the plant in a post accident safe shutdown condition.

SAFETY DESIGN BASIS ONE - The safety-related portion of the MSSS is protected

from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).

SAFETY DESIGN BASIS TWO - The safety-related portion of the MSSS is designed to

remain functional after a SSE and to perform its intended function following postulated hazards such as internal missile, or pipe break (GDC-4).

SAFETY DESIGN BASIS THREE - Component redundancy is provided so that safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).

SAFETY DESIGN BASIS FOUR - The MSSS is designed so that the active components are capable of being tested during plant operation. Provisions are made to allow for inservice inspection of components at appropriate times specified in

the ASME Boiler and Pressure Vessel Code,Section XI.

SAFETY DESIGN BASIS FIVE - The MSSS uses design and fabrication codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power

supply and control functions are in accordance with Regulatory Guide 1.32.

SAFETY DESIGN BASIS SIX - The MSSS provides for isolation of the secondary side of the steam generator to deal with leakage or malfunctions and to isolate nonsafety-related portions of the system.

10.3-1 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SEVEN - The MSSS provides means to dissipate heat generated in the reactor coolant system during hot shutdown and cooldown (GDC-34).

SAFETY DESIGN BASIS EIGHT - The MSSS provides an assured source of steam to operate the turbine-driven auxiliary feedwater pump for reactor cooldown under emergency conditions and for shutdown operations (GDC-34).

10.3.1.2 Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The MSSS is designed to deliver steam from

the steam generators to the turbine-generator system for a range of flows and pressures varying from warmup to rated conditions. The system provides means to dissipate heat during plant step load reductions and during plant startup.

It also provides steam to:

a. The turbine-generator system second stage reheaters
b. The main feed pump turbines and auxiliary feed pump turbine
c. The steam seal system
d. The turbine bypass system
e. The auxiliary steam reboiler
f. The process sampling system
g. Condenser spargers

10.3.2 SYSTEM DESCRIPTION

10.3.2.1 General Description The MSSS is shown in Figure 10.3-1. The system conveys steam from the steam

generators to the turbine-generator system. The system consists of main steam piping, atmospheric relief valves, safety valves, and main steam isolation valves. The turbine bypass system is discussed in detail in Section 10.4.4.

The MSSS instrumentation, as described in Table 10.3-1, is designed to

facilitate automatic operation and remote control of the system and to provide continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the steam line break protection system.

10.3-2 Rev. 11 WOLF CREEK 10.3.2.2 Component Description Codes and standards applicable to the MSSS are listed in Table 3.2-1. The MSSS is designed and constructed in accordance with quality group B and seismic Category I requirements from the steam generator out to the torsional restraint downstream of the main steam isolation valves (MSIV). The remaining piping out

to the turbine-generator and auxiliaries meets ANSI B31.1 requirements. Design

data for the MSSS components are listed in Table 10.3-2.

MAIN STEAM PIPING - Saturated steam from the four steam generators is conveyed

to the turbine generator by four 28-inch-0.D. lines. The lines are sized for a

pressure drop of 25 psi from the steam generators to the turbine stop valves at

turbine manufacturer's guaranteed conditions. Refer to Figure 10.1-2.

Each of the lines is anchored at the containment wall and has sufficient

flexibility to provide for relative movement of the steam generators due to thermal expansion. The main steam line and associated branch lines between the

containment penetration and the first torsional restraint downstream of the MSIV are designed to meet the "no break zone" criteria of NRC BTP MEB 3-1, as described in Section 3.6.

Each line is equipped with:

a. One atmospheric relief valve
b. Five spring-loaded safety valves
c. One main steam isolation valve and associated by-pass isolation valve
d. One low point drain, which is piped to the condenser

through a drain valve

All main steam branch process line connections are made downstream of the isolation valves with the exception of the line to the atmospheric relief valve, connections for the safety valves, lines to the auxiliary feedwater pump turbine, and low point drains and high point vents.

Each steam generator outlet nozzle contains a flow restrictor of 1.4 square feet to limit flow in the event of a MSLB.

Immediately upstream of the turbine stop valves, each main steam pipe is cross

connected, via an 18-inch line, to a 36-inch header to equalize pressure and flow to the four turbine stop valves. The 18-inch equalizing line limits the back flow from the three

10.3-3 Rev. 11 WOLF CREEK intact steam generators in the event of a MSLB. The cross-connecting piping is sized to permit on-line testing of each turbine stop valve without exceeding

allowable limits on steam generator differential pressure. Branch piping downstream of the isolation valves provides steam to the second stage reheaters, steam seal system, main feedwater pump turbines, turbine bypass system, auxiliary steam reboiler, and condenser spargers.

POWER-OPERATED ATMOSPHERIC RELIEF VALVE (ARV)- A power-operated, atmospheric, relief valve is installed on the outlet piping from each steam generator. The four valves are installed to provide for controlled removal of reactor decay

heat during normal reactor cooldown when the main steam isolation valves are

closed or the turbine bypass system is not available. The valves will pass

sufficient flow at all pressures to achieve a 50 F per hour plant cooldown rate. The total capacity of the four valves is a minimum of 10 percent of rated main steam flow at steam generator no-load pressure. The maximum actual

capacity of the relief valve at design pressure is limited to reduce the magnitude of a reactor transient if one valve would inadvertently open and

remain open.

The atmospheric relief valves are air operated carbon steel, 8 inch 1,500 pound

globe valves, supplied by a safety-related air supply (as described in Section

9.3.1), and controlled from Class IE sources. A nonsafety-related air supply

is available during normal operating conditions. The capability for remote manual valve operation is provided in the main control room, the auxiliary shutdown panel and locally at the valves for AB-PV-2 and AB-PV-3. The valves

are opened by pneumatic pressure and closed by spring action.

SAFETY VALVES - The spring-loaded main steam safety valves provide overpressure protection in accordance with the ASME Section III code requirement for the secondary side of the steam generators and the main steam piping. There are five valves installed in each main steam line. Table 10.3-2 identifies the

valves, their set pressure, and capacities. The valves discharge directly to

the atmosphere via vent stacks. The maximum actual capacity of the safety valves at the design pressure is limited to reduce the magnitude of a reactor transient if one of the valves would open and remain open.

MAIN STEAM ISOLATION VALVES AND BYPASS ISOLATION VALVES - One MSIV and

associated bypass isolation valve (BIV) is installed in each of the four main steam lines outside the containment and downstream of the safety valves. The MSIVs are installed to prevent uncontrolled blowdown from more than one steam

generator. The valves isolate the nonsafety-related portions from the safety-

related portions of the system. The valves are bidirectional, double disc, parallel slide gate valves.

10.3-4 Rev. 24 WOLF CREEK The MSIVs are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or close) is accomplished through a series of six electric solenoid pilot valves, which

direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower

Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves

are divided into two trains that are independently powered and controlled.

Either train can independently perform the safety function to fast close the valve. The lower portion of the valve is the system medium chamber, which remains at system pressure during normal operation. The chamber is connected

to the solenoid pilot valve leading to the LPC and UPC through ports internal

to the actuator cylinder wall. The system medium chamber is isolated from the

piston chamber by means of double stem seals and a leak tight backseat. The closure time for MSIVs is a bounding performance curves as a function of the system pressure relative to the closure time (Fig. 10.3-2). As can be seen

from Fig. 10.3-2, the valve is capable of closing within seconds against the

flow associated with line breaks on either side of the valve, assuming the most

limiting normal operating conditions prior to the occurrence of the break.

Valve closure capability is tested in the manufacturer's facility. Preservice and inservice tests are also performed. Preservice and inservice tests are

also performed as discussed in Sections 10.3.4.2 and 10.3.4.3, respectively.

The main steam BIV is used when the MSIVs are closed to permit warming of the main steam lines prior to startup. The bypass valves are air-operated globe valves. For emergency closure, either of two separate solenoids, when de-

energized, will result in valve closure. Electrical solenoids are energized

from a separate Class IE source.

10.3.2.3 System Operation NORMAL OPERATION - At low plant power levels, the MSSS supplies steam to the

steam generator feedwater pump turbines, the auxiliary steam reboiler, and the

turbine steam seal system. At high plant power levels, these components are supplied from turbine extraction steam. Steam is supplied to the second stage steam reheaters in the T-G system when the T-G load exceeds 15 percent.

If a large, rapid reduction in T-G load occurs, steam is bypassed (40 percent

of VWO) directly to the condenser via the turbine bypass system. The system is capable of accepting a 50-percent load rejection without reactor trip and a full load rejection without lifting safety valves. If the turbine bypass

system is not available, steam is vented to the atmosphere via the atmospheric

relief valves (ARV) and the safety valves, as required.

EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, the MSIV and other valves (except to the auxiliary feedpump

turbine) associated with the main steam lines are closed. The ARV may be

employed to remove decay heat and to lower the steam generator pressure to

achieve cold

10.3-5 Rev. 25 WOLF CREEK shutdown. If the atmospheric relief valve for an individual main steam line is unavailable due to the loss of its control gas supply or power supply, the

associated safety valves will provide overpressure protection. The remaining ARVs are sufficient to achieve cold shutdown.

In the event that a DBA occurs which results in a SLIS (i.e. large steam line

break), the MSIV automatically closes. Steam is automatically provided to the

auxiliary feedwater pump turbine from two of four steam lines upon low-low level in two steam generators or loss of offsite power. Redundant check valves are installed in the lines to the turbine to ensure that only one steam

generator will feed a ruptured main steam line and ensure that one steam

generator is available to supply steam to the AFW turbine. The closure of

three out of four MSIVs will ensure that no more than one steam generator can supply a postulated break. In addition, closure of the HP turbine steam stop and steam control valves prevents uncontrolled blowdown of more than one steam

generator following a postulated main steam line break inside the containment.

Reliability of the turbine trip system is discussed in Section 10.2.

Coordinated operation of the auxiliary feedwater system (refer to Section 10.4.9) and ARV or safety valve may be employed to remove decay heat.

10.3.3 SAFETY EVALUATION

Safety evaluations are numbered to correspond to the safety design bases of Section 10.3.1.1.

SAFETY EVALUATION ONE - The safety-related portions of the MSSS are located in

the reactor and auxiliary buildings. These buildings are designed to withstand

the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.

SAFETY EVALUATION TWO - The safety-related portions of the MSSS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.

SAFETY EVALUATION THREE - As indicated by Table 10.3-3, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.

10.3-6 Rev. 19 WOLF CREEK SAFETY EVALUATION FOUR - The MSSS is initially tested with the program given in Chapter 14.0. Periodic inservice functional testing is done in accordance with

Section 10.3.4.

Section 6.6 provides the ASME Boiler and Pressure Vessel Code,Section XI requirements that are appropriate for the MSSS.

SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.3-2 shows that the components meet

the design and fabrication codes given in Section 3.2. All the power supplies

and controls necessary for safety-related functions of the MSSS are Class IE, as described in Chapters 7.0 and 8.0.

SAFETY EVALUATION SIX - Redundant power supplies and power trains operate the

MSIVs to isolate safety and nonsafety-related portions of the system. Branch lines upstream of the MSIV contain normally closed, atmospheric relief valves which modulate open and closed on steam line pressure. The atmospheric relief valves fail closed on loss of air, and the safety valves provide the overpressure protection.

Accidental releases of radioactivity from the MSSS are minimized by the negligible amount of radioactivity in the system under normal operating conditions. Additionally, the main steam isolation system provides controls for reducing accidental releases, as discussed in Chapter 15.0, following a

steam generator tube rupture.

Detection of radioactive leakage into and out of the system is facilitated by area radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).

SAFETY EVALUATION SEVEN - Each main steam line is provided with safety valves that limit the pressure in the line to preclude overpressurization and remove stored energy. Each line is provided with an atmospheric relief valve to

permit reduction of the main steam line pressure and remove stored energy to

achieve an orderly shutdown. The auxiliary feedwater system, which is

described and evaluated in Section 10.4.9, provides makeup to the steam generators consistent with the steaming rate.

SAFETY EVALUATION EIGHT - The steam line to the auxiliary feedwater pump

turbine is connected to a cross-connecting header upstream of the MSIV. This

arrangement ensures a supply of steam to this turbine when the steam generators are isolated. Redundant

10.3-7 Rev. 11 WOLF CREEK check valves are provided in each supply line from the main steam lines to preclude any potential backflow during a postulated main steam line break. The

auxiliary feedwater system is described in Section 10.4.9.

10.3.4 INSPECTION AND TESTING REQUIREMENTS

10.3.4.1 Preservice Valve Testing The set pressures of the safety valves are individually checked during initial startup either by bench testing or with a pneumatic test device. A pneumatic test device is attached to the valve stem. The pneumatic pressure is applied until the valve seat just lifts, as indicated by the steam noise. Combination

of the steam pressure and pneumatic pressure with calibration data furnished by the valve manufacturer verifies the set pressure.

The lift-point of each ARV is verified by channel check and channel calibration.

The MSIVs were checked for closing time prior to initial startup.

10.3.4.2 Preservice System Testing

Preoperational testing is described in Chapter 14.0.

The MSSS is designed to include the capability for testing through the full operational sequence that brings the system into operation for reactor shutdown

and for MSLB accidents, including operation of applicable portions of the

protection system and the transfer between normal and standby power sources.

The safety-related components of the system, i.e. valves and piping, are

designed and located to permit preservice and inservice inspections to the

extent practicable.

10.3.4.3 Inservice Testing The performance and structural and leaktight integrity of all system components

are demonstrated by continuous operation.

The redundant actuator power trains of each MSIV are subjected to the following tests:

a. Closure time - The valves are checked for closure time

at each refueling.

10.3-8 Rev. 11 WOLF CREEK Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is contained in Section 6.6.

10.3.5 SECONDARY WATER CHEMISTRY (PWR) 10.3.5.1 Chemistry Control Basis Steam generator secondary side water chemistry control is accomplished by:

a. A close control of the feedwater chemistry to limit the amount of impurities that can be introduced into the

steam generator

b. The capability of a continuous blowdown of the steam

generators to reduce concentrating effects of the steam

generator

c. Chemical addition to establish and maintain an environment that minimizes system corrosion
d. By post-construction cleaning of the feedwater system
e. Minimizing feedwater oxygen content prior to entry into the steam generator by deaeration in the hotwell
f. The capability of continuous demineralization and

filtration of the condensate system through full-flow, deep bed condensate demineralizers.

Secondary water chemistry is based on the all volatile treatment (AVT) method.

This method employs the use of volatile additives to maintain system pH and to

scavenge dissolved oxygen present in the feedwater. A pH control chemical such as ammonia and/or an or an organic amine is added to establish and maintain alkaline conditions in the feedtrain. Although the pH control chemical is

volatile and will not concentrate in the steam generator, it will reach an equilibrium level which will establish an alkaline condition in the steam

generator.

An oxygen control chemical is added to scavenge dissolved oxygen present in the

feedwater. The oxygen control chemical also tends to promote the formation of

a protective oxide layer on metal surfaces by keeping these layers in a reduced

chemical state.

10.3-9 Rev. 24 WOLF CREEK Both the pH control chemical and the oxygen control chemical can be injected continuously at the discharge headers of the condensate pumps and are added, as

necessary, for chemistry control.

Operating chemistry guidelines for secondary steam generator water have been developed using EPRI guidelines and Westinghouse chemistry recommendations with actual implementation and control being defined and maintained in plant chemistry procedures. Water chemistry monitoring is discussed in Section 9.3.2. The requirements of BTP MTEB 5-3 are met.

The condensate demineralizer system is discussed in Section 10.4.6.

10.3.5.2 Corrosion Control Effectiveness

Alkaline conditions in the feedtrain and the steam generator reduce general

corrosion at elevated temperatures and tend to decrease the release of soluble corrosion products from metal surfaces. These conditions promote formation of a protective metal oxide film and thus reduce the corrosion products released into the steam generator.

An oxygen control chemical also promotes formation of a metal oxide film by the

reduction of ferric oxide to magnetite. Ferric oxide may be loosened from the

metal surfaces and be transported by the feedwater. Magnetite, however, provides an adhesive, protective layer on carbon steel surfaces. An oxygen control chemical also promotes formation of protective metal oxide layers on

copper surfaces. Removal of oxygen from the secondary waters is also essential

in reducing corrosion. Oxygen dissolved in water causes general corrosion that

can result in pitting of ferrous metals, particularly carbon steel. Oxygen is removed from the steam cycle condensate in the main condenser deaerating section. Additional oxygen protection is obtained by chemical injection of an

oxygen control chemical into the condensate stream. Maintaining a residual

level of oxygen control chemical in the feedwater ensures that any dissolved

oxygen not removed by the main condenser is scavenged before it can enter the steam generator.

The presence of free hydroxide (OH) can cause rapid corrosion (caustic stress

corrosion) if it is allowed to concentrate in a local area. Free hydroxide is

avoided by maintaining proper pH control and by minimizing impurity ingress into the steam generator.

AVT control is a technique whereby both soluble and insoluble solids are kept at a minimum within the steam generator. This is accomplished by maintaining

strict surveillance over the possible sources of feedtrain contamination (e.g., main condenser cooling

10.3-10 Rev. 13 WOLF CREEK water leakage, air inleakage, and subsequent corrosion product generation in the low pressure drain system, etc.). Solids are also excluded, as discussed

above, by injecting only volatile chemicals to establish conditions that reduce corrosion and, therefore, reduce transport of corrosion products into the steam generator.

In addition to minimizing the sources of contaminants entering the steam

generator, condensate demineralizers are used when required, and a continuous blowdown from the steam generators is employed to limit the concentration of contaminants. With the low solids level that results from employing the above

procedures, the accumulation of scale and deposits on steam generator heat

transfer surfaces and internals is limited. Scale and deposit formations can

alter the thermal hydraulic performance in local regions which creates a mechanism that allows impurities to concentrate and thus possibly cause corrosion. The effect of this type of corrosion is reduced by limiting the

ingress of solids into the steam generator and limiting their buildup.

The chemical additives, because they are volatile, do not concentrate in the steam generator and do not represent chemical impurities that can themselves cause corrosion.

10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS

10.3.6.1 Fracture Toughness Compliance with fracture toughness requirements of ASME III, Article NC-2300 is

discussed in Section 6.1.

10.3.6.2 Material Selection and Fabrication All pipe, flanges, fittings, valves, and other piping material conform to the

referenced ASME, ASTM, ANSI, or MSS-SP code.

The following code requirements apply:

Stainless Steel Carbon Steel Pipe ANSI B36.19 ANSI B36.10 Fittings ANSI B16.9, B16.11 or ANSI B16.9, B16.11 or B16.28 B16.28

Flanges ANSI B16.5 ANSI B16.5

10.3-11 Rev. 18 WOLF CREEK The following ASME Material Specifications apply specifically:

ASME SA-155 GR KCF 70 Class 1 (impact tested)

ASME SA-155 GR KCF 70 Class 1

ASME SA-106, GR C (impact tested)

ASME SA-106, GR, B

ASME SA-106, GR, B (normalized)

ASME SA-234 GR WPB ASME SA-234 GR WPBW (Mfd from gr 70 plate)

ASME SA-234 GR WPC

ASME SA-105

ASME SA-193 GR B7

ASME SA-194 GR 2H/Grade 7 ASME SA-194 GR 7 ASME SA-216 GR WCB

ASME SA-333 GR 6 (impact tested)

ASME SA-420 GR WPL6 (impact tested)

ASME SA-508 Class 1 (impact tested)

ASME SA-312, TP 304

ASME SA-403, WP-304

ASME SA-403, WP-304 W

ASME SA-182, F-304

ASME SA 672 GR C70 ASME SA 350 GR LF2 (impact tested)

Compliance with the following Regulatory Guides is discussed in Section 6.1:

Regulatory Guide 1.31 - Control of Stainless Steel Welding

10.3-12 Rev. 23 WOLF CREEK Regulatory Guide 1.36 - Nonmetallic Thermal Insulation for Austenitic Stainless Steel

Regulatory Guide 1.37 - Quality Assurance Requirement for Cleaning of Fluid Systems and Associated Components of Water-cooled Nuclear Power Plants

Regulatory Guide 1.44 - Control of the Use of Sensitized Stainless Steel

Regulatory Guide 1.50 - Control of Preheat Temperatures for

Welding of Low-Alloy Steels

Regulatory Guide 1.71 - Welder Qualification for Areas of Limited Accessibility

10.3-13 Rev. 0 WOLF CREEK TABLE 10.3-1 MAIN STEAM SUPPLY SYSTEM CONTROL, INDICATING AND ALARM DEVICES

Device Control Room Local Control Room Alarm Flow rate indication (2) Yes - Yes (4)

Pressure indication (1)(3) Yes (5) - -

Pressure Control Yes - -

(1) For each generator, three devices are involved in 2-out-of-3

logic to generate input to reactor trip, SLIS, and SIS

(2) Two per steamline (3) Total of four per steamline

(4) Steam flow - feed flow mismatch

(5) One per steamline (atmospheric relief valves)

Rev. 24 WOLF CREEK TABLE 10.3-2 MAIN STEAM SUPPLY SYSTEM DESIGN DATA Main Steam Piping (Safety-Related Portion)

Design VWO flowrate at 1,000 psia and 0.25 percent moisture, lb/hr 15,850,801

Power Rerate flowrate at 970 psia and 0.25 percent moisture, lb/hr 15,906,000

Reduced Thermal Design flowrate at 944 psia and 0.25 percent moisture, lb/hr 15,920,000 Number of lines 4 0.D., in. 28 Minimum wall thickness, in. 1.5 Design pressure, psia 1,200 Design temperature, F 600 Design code ASME Section III, Class 2 Seismic design Category I Main Steam Isolation Valves Number per main steam line 1 Closing time, seconds 1.5 to 5 (at normal operating conditions prior to receiving isolation signal) Design code ASME Section III, Class 2 Seismic design Category I Atmospheric Relief Valves Number per main steam line 1 Normal set pressure, psig 1,125 Capacity (each) at 1,107 psia, lb/hr 594,642 Capacity (each) at 100 psia, lb/hr 54,000 Design code ASME Section III, Class 2 Seismic design Category I Main Steam Safety Valves Number per main steam line 5 Orifice area, sq in. 16 Size, in. 6 x 8 x 8 Design code ASME Section III, Class 2 Seismic design Category I Set Pressure Capacity at 3-Percent Accumulation Number (psig) (lb/hr) 1 1185 893,160 2 1197 902,096 3 1210 911,779 4 1222 920,715 5 1234 929,652

Rev. 24 WOLF CREEK TABLE 10.3-2 (SHEET 2)

MAIN STEAM SUPPLY SYSTEM DESIGN DATA The Following information provides the "FLOWRATE PER STEAMLINE" and the "TOTAL SYSTEM FLOWRATE" using regression limits and spring constants (K-RATEs) varying from 25000 to 27770 lbf/in, for the Main Steam Safety Valves (MSSVs).

K-RATE REGRESSION FLOWRATE PER TOTAL SYSTEM LBF/IN LIMIT STEAMLINE LMB/HR FLOWRATE LMB/HR 25000 Lower Limit 4913613 19654452 25000 Regression Line 5131912 20527648 25000 Upper Limit 5149865 20599460 27770 Lower Limit 4212594 16850376 27770 Regression Line 4695591 18782364 27770 Upper Limit 5045732 20182928

Rev. 7 WOLF CREEK TABLE 10.3-3 MAIN STEAM SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component Failure Comments

1. Main steam line iso- Loss of power from one Redundant power supply lation and bypass power supply provided.

valves.

Valve fails to close Closure of three out upon receipt of auto- of four isolation matic signal (SLIS) valves adequate to meet

requirements.

2. Atmospheric relief Loss of power or air Safety valves provide valves to valve fails to modu- overpressure protection late upon high pressure for the associate line.

Atmospheric relief valves on two out of four lines adequate to meet shutdown re-

quirements.

3. Pressure transmitters No signal generated for For each generator protection logic 2-out-of-3 logic reverts to 1-out-of-2 logic, and protection logic is generated by other devices. Refer to Chapter 7.0.

Rev. 0 WOLF CREEK TABLE 10.3-3 (Sheet 2)

Component Failure Comments

4. Main steam line drain Valve fails to close Negligible steam lost line isolation valve upon receipt of auto- from generator. In matic signal (SLIS) addition, three of four intact secondary loops are required to meet safety require-

ments.

5. Steam supply valve to Valve fails to open Redundant valve pro-auxiliary feedpump upon receipt of auto- vides 100 percent of turbine matic signal (AFAS) flow requirements to the auxiliary feed

pump turbine.

Supplied from broken Redundant motor-driven secondary loop and auxiliary feedwater train of power for pump meets 100 per-redundant supply cent of auxiliary feed-

valve lost water requirements.

Rev. 0 WOLF CREEK 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM This section provides discussions of each of the principal design features of the steam and power conversion system.

10.4.1 MAIN CONDENSERS

The main condenser is the steam cycle heat sink. During normal operation, it receives and condenses main turbine exhaust steam, steam generator feedwater

pump turbine exhaust steam, and turbine bypass steam. The main condenser is

also a collection point for other steam cycle miscellaneous flows, drains, and

vents. The main condenser is utilized as a heat sink for reactor cooldown during a normal plant shutdown.

10.4.1.1 Design Bases 10.4.1.1.1 Safety Design Bases

The main condenser serves no safety function and has no safety design basis.

10.4.1.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - The main condenser is designed to function

as the steam cycle heat sink and miscellaneous flow collection point.

POWER GENERATION DESIGN BASIS TWO - The main condenser accommodates up to 40 percent of the VWO main steam flow which is bypassed directly to the condenser

by the turbine bypass system.

POWER GENERATION DESIGN BASIS THREE - The main condenser provides for the removal of noncondensable gases from the condensing steam through the main condenser air removal system, as described in Section 10.4.2.

POWER GENERATION DESIGN BASIS FOUR - The main condenser provides the surge

volume required for the condensate and feedwater system.

POWER GENERATION DESIGN BASIS FIVE - The main condenser provides for deaeration

of the condensate, such that condensate oxygen content should not exceed 7 ppb

under normal full power operating condition.

10.4-1 Rev. 13 WOLF CREEK 10 4.1.2 System Description 10.4.1.2.1 General Description The main condenser is a multipressure, three-shell, deaerating unit. Each

shell is located beneath its respective low-pressure turbine. The tubes in

each shell are oriented transverse to the turbine-generator longitudinal axis.

The three condenser shells are designated as the low-pressure shell, the intermediate-pressure shell, and the high-pressure shell. Each shell has six

tube bundles. Circulating water flows in series through the three single-pass

shells, as shown in Figure 10.4-1.

Exhaust steam from the steam generator feedwater pump turbine is used to reheat the condensate in the condenser. Each hotwell is divided longitudinally by a

vertical partition plate. The condensate pumps take suction from these

hotwells, as shown in Figure 10.4-2.

The condenser shells are located in pits below the turbine building operating floor and are supported above the turbine building foundation. Failure of or

leakage from a condenser shell will only result in a minimum water level in the

condenser pit. Expansion joints are provided between each turbine exhaust

opening and the steam inlet connections of the condenser shell. Water seals are provided around the entire outside periphery of these expansion joints, but are only placed in service (filled with water) during post maintenance testing following new joint installation and in times when it is expected that an expansion joints vacuum seal has been breached. When water seals are filled with water, level indication provides detection of leakage through the expansion joint. The hotwells of the three shells are interconnected by steam-equalizing lines. Four low-pressure feedwater heaters are located in the steam

dome of each shell. Piping is installed for hotwell level control and

condensate sampling.

10.4.1.2.2 Component Description

Table 10.4-1 provides the design data for each condenser shell for both the

closed loop and open loop circulating water systems.

10.4.1.2.3 System Operation

During normal operation, exhaust steam from the low-pressure turbines is

directed into the main condenser shells. The condenser also receives auxiliary

system flows, such as feedwater heater vents and drains and feedwater pump turbine exhaust.

10.4-2 Rev. 29 WOLF CREEK Hotwell level controls provide automatic makeup or rejection of condensate to maintain a normal level in the condenser hotwells. On low water level in a

hotwell, the makeup control valves open and admit condensate to the hotwell from the condensate storage tank. When the hotwell is brought to within normal-operating range, the valves close. On high water level in the hotwell, the condensate reject control valve opens to divert condensate from the

condensate pump discharge (downstream of the demineralizers) to the condensate

storage tank; rejection is stopped when the hotwell level falls to within normal operating range.

Sparger piping is provided for distribution of turbine bypass discharge and

other high temperature drains. Orifices are provided internal to the spargers

where necessary for pressure reduction prior to distribution within the condenser. Where sparger piping cannot be utilized due to space limitations, baffles are provided to direct the discharge away from the tubes and other

condenser components. Pressure reducing orifices are provided in the drains

piping outside the condenser, where required.

The main condenser, with the assistance of auxiliary steam at low loads, deaerates the condensate so that dissolved oxygen should not exceed 7 ppb over

the entire load range. Both the air inleakage and the noncondensable gases

contained in the turbine exhaust are collected in the condenser and removed by

the condenser air removal system.

During the cooling period after plant shutdown, the main condenser removes residual heat from the reactor coolant system via the turbine bypass system.

The main condenser receives up to 40 percent of VWO main steam flow through the

turbine bypass valves. If the condenser is not available to receive steam via the turbine bypass system, the reactor coolant system can be safely cooled down by discharging steam through the atmospheric relief valves or the main steam

safety valves, as described in Section 10.3.

Circulating water leakage occurring within the condenser is detected by monitoring the condensate leaving each hotwell (six monitoring points altogether). This information permits determination of which tube bundle has

sustained the leakage. Steps may then be taken to isolate and dewater that

bundle and its water boxes and, subsequently, repair or plug the leaking tubes.

Section 10.4.6 describes the contaminants allowed in the condensate and the length of time the condenser may operate with degraded conditions without affecting the condensate/feedwater quality for safe operation.

During normal operation and shutdown, the main condenser has a negligible

inventory of radioactive contaminants. Radioactive

10.4-3 Rev. 13 WOLF CREEK contaminants may enter through a steam generator tube leak. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated

operating concentrations of radioactive contaminants, is included in Chapter 11.0. No hydrogen buildup in the main condenser is anticipated.

The failure of the main condenser and the resulting flooding will not preclude

operation of any essential system because the limited safety related

components, instruments and cabling associated with the main steam dumps and turbine trip/reactor trip signals are located well above the expected flood level in the turbine building, and the water cannot reach the equipment located

in the auxiliary building. Refer to Section 10.4.5.

10.4.1.3 Safety Evaluation

The main condenser serves no safety-related function.

10.4.1.4 Tests and Inspections The condenser shells are hydrostatically tested after erection.

The condenser waterboxes, tubesheets, and tubes are hydrostatically tested as a

unit.

The extent of inservice inspection of the main condenser includes the following:

1. Monitor condensate conductivity, temperature, and dissolved oxygen level.
2. When an expansion joint water seal is in service in times when it is expected that the vacuum seal has been breached, check water level in the condenser/turbine connection expansion joint water seal for seal leak detection.

The frequency of these inspections will depend on past condenser operating

experience and the type of problems identified in the previously described

inspections.

10.4.1.5 Instrument Applications The main condenser hotwells are equipped with level control devices for

automatic control of condensate makeup and rejection. Local and remote

indicating devices are provided for monitoring the water level in the condenser shells. High, low, and low-low hotwell water level alarms are provided in the control room.

A sensor is provided to monitor condenser back-pressure. A high back-pressure

alarm is activated at approximately 5 inches Hg absolute (Hga), and turbine

trip is activated at 7.5 inches Hga.

10.4-4 Rev. 29 WOLF CREEK Conductivity and sodium content of the condensate from each condenser shell is monitored to provide an indication of condenser tube leakage.

Turbine exhaust hood temperature is monitored and controlled with water sprays supplied from the condensate pump discharge.

10.4.2 MAIN CONDENSER EVACUATION SYSTEM

Main condenser evacuation is performed by the main condenser air removal system (MCARS). The MCARS removes noncondensable gases and air from the main

condenser during plant startup, cooldown, and normal operation.

10.4.2.1 Design Bases 10.4.2.1.1 Safety Design Bases

The MCARS serves no safety function and has no safety design bases.

10.4.2.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - The MCARS is designed to remove air and

noncondensable gases from the condenser during plant startup, cooldown, and

normal operation.

POWER GENERATION DESIGN BASIS TWO - The MCARS establishes and maintains a

vacuum in the condenser during startup and normal operation by the use of

mechanical vacuum pumps.

10.4.2.2 System Description 10.4.2.2.1 General Description

The MCARS, as shown in Figure 10.4-3, consists of three mechanical vacuum pumps which remove air and noncondensable gases from the main condenser during normal operation and provide condenser hogging during startup.

The seal water cooler uses service water so that the seal water is kept cooler

than the saturation temperature of the condenser at its operating pressure. As described in Section 9.4.4, air inleakage and noncondensable gases that are removed from the condenser and discharged from the pumps are processed through

the charcoal adsorption train and monitored for radioactivity prior to

discharge to the unit vent.

10.4-5 Rev. 13 WOLF CREEK The noncondensable gases and vapor mixture discharged to the atmosphere from the system is not normally radioactive. However, it is possible for the mixture

discharged to become contaminated in the event of primary-to-secondary system leakage. A discussion of the radiological aspects of primary-to-secondary leakage, including anticipated release from the system, is included in Chapter 11.0.

As long as the MCARS is functional, its operation does not affect the reactor coolant system. Should the air removal system fail completely, a gradual

reduction in condenser vacuum would result from the buildup of noncondensable

gases. This reduction in vacuum would cause a lowering of turbine cycle

efficiency which requires an increase in reactor power to maintain the demanded electrical power generation level. The reactor power is limited by the reactor control system, as described in Section 7.7. The reactor protection system, described in Section 7.2, independently guarantees that the reactor is maintained within safe operation limits.

If the MCARS remains inoperable, condenser vacuum decreases to the turbine trip setpoint and a turbine trip is initiated. A loss of condenser vacuum incident

is discussed in Section 15.2.5.

10.4.2.2.2 Component Description MECHANICAL VACUUM PUMPS - The mechanical vacuum pumps are 150 hp motor-driven

pumps which operate at 435 rpm.

SEAL WATER COOLERS - The seal water coolers are shell and tube heat exchangers.

Mechanical vacuum pump seal water flows through the shell side of the coolers, and service water flows through the tubes.

Piping and valves are carbon steel. All piping is designed to ANSI B31.1. The

design parameters of the system are provided in Table 10.4-2.

10.4.2.2.3 System Operation

During normal plant operation, noncondensable gases are removed from the

condenser, and the condenser vacuum is automatically maintained by the condenser vacuum pumps. The vacuum pumps are run as needed to ensure adequate capacity to remove noncondensable gases. Non-running pumps are normally in standby and automatically start on low vacuum.

During startup operation, air is rapidly removed from the condenser by three condenser mechanical vacuum pumps.

During normal operation, the condenser vacuum pump suction header can be lined up as an alternate vacuum source for the Demineralized Water Storage and Transfer System (DWSTS) degasifier tank.

10.4-6 Rev. 11 WOLF CREEK 10.4.2.3 Safety Evaluation The main condenser evacuation system has no safety-related function.

10.4.2.4 Tests and Inspections Testing and inspection of the system is performed prior to plant operation.

Components of the system are continuously monitored during operation to ensure satisfactory operation. Periodic inservice tests and inspections of the

evacuation system are performed in conjunction with the scheduled maintenance

outages.

10.4.2.5 Instrumentation Applications Local indicating devices such as pressure, temperature, and flow indicators are

provided as required for monitoring the system operation. Pressure switches

are provided for automatic operation of the standby mechanical vacuum pump during normal operation.

Volumetric flow indication is provided locally to monitor the quantity of

exhausted noncondensable gases.

A radiation detector is provided in the turbine building HVAC system to monitor the discharge of the condenser mechanical vacuum pumps. The radiation detector

is indicated and alarmed in the control room.

10.4.3 TURBINE GLAND SEALING SYSTEM The turbine gland sealing system (TGSS) prevents the escape of steam from the

turbine shaft/casing penetrations and valve stems and prevents air inleakage to

subatmospheric turbine glands.

10.4.3.1 Design Bases 10.4.3.1.1 Safety Design Basis

The TGSS serves no safety function and has no safety design basis.

10.4.3.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - The TGSS is designed to prevent atmospheric

air leakage into the turbine casings and to minimize steam leakage out of the casings of the turbine-generator and steam generator feedwater pump turbines.

10.4-7 Rev. 0 WOLF CREEK POWER GENERATION DESIGN BASIS TWO - The TGSS returns the condensed steam to the condenser and exhausts the noncondensable gases to the atmosphere.

POWER GENERATION DESIGN BASIS THREE - The TGSS has a capacity to handle steam and air flows resulting from twice the normal packing clearances.

10.4.3.2 System Description 10.4.3.2.1 General Description The TGSS is shown in Figure 10.4-4. It consists of steam seal inlet and exhaust headers, feed and unloading valves, steam packing exhauster, blowers, and associated piping and valves.

10.4.3.2.2 System Operation

The annular space through which the turbine shaft penetrates the casing is

sealed by steam supplied to shaft packings. Where the packing seals against positive pressure, the sealing steam connection acts as a leakoff. Where the packing seals against vacuum, the sealing steam either is drawn into the casing

or leaks outward to a vent annulus that is maintained at a slight vacuum. The

vent annulus also receives air leakage from the outside. The air-steam mixture is drawn to the steam packing exhauster.

Sealing steam is distributed to the turbine shaft seals through the steam-seal

header. Steam flow to the header is controlled by the steam-seal feed valve

which responds to maintain steam-seal header pressure. In case of low steam-

seal header pressure, a pressure regulator signal opens the feed valves to admit steam from the main steam piping upstream of the turbine stop valves, from the auxiliary steam headers, or from ninth stage turbine extraction. In

case of high pressure, the steam packing unloading valve automatically opens to

bypass excess steam directly to the main condenser.

During the startup phase of turbine-generator operation or at low turbine loads, steam is supplied to the turbine gland sealing system from the main

steam piping or auxiliary steam header. During low-load operation, turbine-generator sealing steam is supplied from the main steam system through the

steam-seal feed valve to maintain the necessary steam flow to the steam-seal header. As the turbine-generator load is increased, steam leakage from the control valve packings and turbine high-pressure packings increases, and enters

the steam-seal header. When this leakage is sufficient to maintain steam-seal

header pressure, sealing steam

10.4-8 Rev. 0 WOLF CREEK to all turbine seals, including the low-pressure turbine casings and the main feedwater pump turbine, is supplied entirely from these high-pressure packings.

At full load, more steam leaks from the high-pressure packings than is required by vacuum packings, and excess steam is discharged directly to the main condenser. Steam leak-off from the turbine stop valves feeds into the high-pressure turbine exhaust.

The outer ends of all glands are provided with collection piping which routes the mixture of air and excess seal steam to the steam packing exhauster. The steam packing exhauster is a shell and tube heat exchanger; the steam-air

mixture passes into the shell side, and service water flows through the tube

side. The steam packing exhauster is maintained at a slight vacuum by a motor-

operated blower, which discharges to the atmosphere. There are two blowers mounted in parallel which provide 100-percent redundancy. Condensate from the steam-air mixture drains to the main condensers, while noncondensables are

exhausted to the atmosphere.

The mixture of noncondensable gases discharged to the atmosphere by the steam packing exhauster blower is not normally radioactive; however, in the event of significant primary-to-secondary system leakage due to a steam generator tube

leak, it is possible for the mixture discharged to be radioactively

contaminated. Primary-to-secondary system leakage is detected by the radiation

monitors in either the main steam sample system or the condenser air removal system. A full discussion of the radiological aspects of primary-to-secondary system leakage is included in Chapter 11.0.

In the absence of primary-to-secondary leakage, failure of the turbine gland

seal system will result in no leakage of radioactivity to the atmosphere. A failure of this system would, however, result in a loss of condenser vacuum.

10.4.3.3 Safety Evaluation The TGSS has no safety-related function.

10.4.3.4 Tests and Inspections The system was tested, in accordance with written procedures, during the

initial testing and operation program. Since the TGSS is in constant use during normal plant operation, the satisfactory operation of the system components is evident.

10.4-9 Rev. 13 WOLF CREEK 10.4.3.5 Instrumentation Applications A pressure controller is provided to maintain steam-seal header pressure by providing signals to the steam-seal feed valve.

Local and remote indicators, as well as alarm devices, are provided for

monitoring the operation of the system.

10.4.4 TURBINE BYPASS SYSTEM

The turbine bypass system (TBS) has the capability to bypass main steam from

the steam generators to the main condenser in a controlled manner to minimize

transient effects on the reactor coolant system of startup, hot shutdown and cooldown, step load reductions in generator load, and cycling the main turbine stop and control valves. The TBS is also called the steam dump system.

10.4.4.1 Design Bases 10.4.4.1.1 Safety Design Bases

The TBS serves no safety function and has no safety design basis.

10.4.4.1.2 Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The TBS has the capacity to bypass 40

percent of the VWO main steam flow to the main condenser.

POWER GENERATION DESIGN BASIS TWO - The TBS is designed to bypass steam to the main condenser during plant startup and to permit a normal manual cooldown of the reactor coolant system from a hot shutdown condition to a point consistent

with the initiation of residual heat removal system operation.

POWER GENERATION DESIGN BASIS THREE - The TBS will permit a 50-percent electrical step-load reduction without reactor trip. The system will also allow a turbine and reactor trip from full power without lifting the main steam

safety valves.

10.4.4.2 System Description

10.4.4.2.1 General Description

The TBS is shown on Figure 10.3-1, Main Steam System. The system consists of a manifold connected to the main steam lines upstream

10.4-10 Rev. 18 WOLF CREEK of the turbine stop valves and lines from the manifold with regulating valves to each condenser shell. The system is designed to bypass 40 percent of the VWO

main steam flow directly to the condenser.

The capacity of the system, combined with the capacity of the RCS to accept a

10-percent step-load change, provides the capability to shed 50 percent of the

turbine-generator rated load without reactor trip and without the operation of

relief and safety valves. A load rejection in excess of 50 percent is expected to result in reactor trip and operation of the main steam atmospheric relief valves. The operation of the main steam, atmospheric, relief valves and spring-loaded safety valves prevents overpressurization of the main steam

system.

There are 12 turbine bypass valves. Seven valves discharge into the low pressure condenser, four valves discharge into the intermediate condenser, and

a single valve discharges into the high pressure condenser. The system is

arranged in this manner to allow for the differences in the heat sink

capacities of the three condenser shells. The heat sink capacity of any one condenser shell is limited by the administrative limit of 5.5 inches Hga (for 100% power operation) condenser pressure imposed on turbine operation by the turbine-generator manufacturer. The low pressure condenser is the largest heat sink, since it normally operates at the lowest pressure.

The steam bypassed to the main condenser is not normally radioactive. In the event of primary-to-secondary leakage, it is possible for the bypassed steam to

become radioactively contaminated. A full discussion of the radiological

aspects of primary-to-secondary leakage is contained in Chapter 11.0.

10.4.4.2.2 Component Description

The TBS contains 12 air-actuated carbon steel, 8 inch, 1,500 pound globe

valves. The valves are pilot-operated, spring-opposed, and fail closed upon

loss of air or loss of power to the control system. Sparger piping distributes the steam within the condenser. Isolation valves permit maintenance of the bypass valve while the plant is in operation.

10.4.4.2.3 System Operation

The TBS, during normal operating transients for which the plant is designed, is automatically regulated by the reactor coolant temperature control system to

maintain the programmed coolant temperature. The programmed coolant

temperature is derived from the high pressure turbine first stage pressure, which is a load

10.4-11 Rev. 28 WOLF CREEK reference signal. The difference between programmed reactor coolant average temperature and measured reactor coolant average temperature is used to

activate the steam dump system under automatic control. The system operates in two fundamental modes. In one mode, two groups of six valves each trip open sequentially in approximately 3 seconds. This operational mode is activated during a large reactor-to-turbine power mismatch. In the second mode, four

groups of three valves each modulate open sequentially in approximately 10

seconds. A logic diagram is shown in Figure 7.2-1 (Sheet 10).

When the plant is at no load (and there is no turbine load reference), while

cycling the main turbine stop and control valves, and during plant cooldown the

system is operated in a pressure control mode. The measured main steam system

pressure is compared against the pressure set by the operator in the control room. The valves to any one condenser shell are prevented from opening when the pressure in that shell reaches 5.0 in Hga.

The turbine bypass control system can malfunction in either the open or closed

mode. The effects of both these potential failure modes on the NSSS and turbine system are addressed in Chapter 15.0. If the bypass valves fail open, additional heat load is placed on the condenser. If this load is great enough, the turbine is tripped on high-high condenser pressure. Ultimate overpressure

protection for the condenser is provided by rupture discs. If the bypass

valves fail closed, the atmospheric relief valves permit controlled cooldown of the reactor.

10.4.4.3 Safety Evaluation The TBS serves no safety function and has no safety design basis. There is no safety-related equipment in the vicinity of the TBS. All high energy lines of the TBS are located in the turbine building.

10.4.4.4 Inspection and Testing Requirements Before the system is placed in service, all turbine bypass valves are tested for operability. The steam lines are hydrostatically tested to confirm leaktightness. The bypass valves may be tested while the unit is in operation.

System piping and valves are accessible for inspection.

The turbine bypass system includes the capability to inservice test the turbine bypass valves by closing the upstream manual isolation valves and cycling the

turbine bypass valves from the control room. Turbine bypass valves are cycled

during normal plant operation at least annually.

10.4-12 Rev. 11 WOLF CREEK 10.4.4.5 Instrumentation Applications The turbine bypass control system is described in Section 7.7. Hand switches in the main control room are provided for selection of the system operating mode.

Pressure controllers and valve position lights are also located in the main control room.

10.4.5 CIRCULATING WATER SYSTEM The circulating water system (CWS) within the standard power block consists of

the circulating water piping, on-line condenser tube cleaning system, and water box venting subsystem.

The circulating water for cycle heat rejection from the main condenser is provided by an open circulating water system using a man-made cooling lake.

10.4.5.1 Design Bases 10.4.5.1.1 Safety Design Bases

The CWS serves no safety-related function.

10.4.5.1.2 Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The CWS supplies cooling water at a

sufficient flow rate to condense the steam in the condenser, as required by the

turbine cycle heat balance.

POWER GENERATION DESIGN BASIS TWO - Two out of three operating circulating water pumps are automatically secured in the event of gross leakage into the condenser pit to prevent flooding of the turbine building.

POWER GENERATION DESIGN BASIS THREE - The cooling lake removes the design heat load from the circulating water during all design weather conditions.

10.4-13 Rev. 13 WOLF CREEK 10.4.5.2 System Description 10.4.5.2.1 General Description The CWS consists of the main condenser, circulating water screenhouse, traveling screens, circulating water pumps, water box venting pumps, water box venting tanks, piping, valves, seal tanks, and instrumentation, as shown in Sheets 1 through 4 of Figure 10.4-1. The physical arrangement of the circulating water screenhouse is shown in Sheets 4 and 5 of Figure 10.4-1. The major components of the CWS are shown in Table 10.4-3.

The CWS provides cooling water for the removal of heat from the main condensers

and rejects heat to a heat sink. The water box venting subsystem helps to fill the condenser water boxes during startup and removes accumulated air and other gases from the water boxes during normal operation.

10.4.5.2.2 Component Description

Codes and standards applicable to the CWS are listed in Table 3.2-1. The system is designed and constructed in accordance with quality group D

specifications. Table 10.4-3 provides the design parameters for major

components in the circulating water system.

Three one-third capacity motor-driven, vertical, wet-pit circulating water pumps pump the circulating water from the cooling lake to the main condenser.

They are designed to operate through the expected range of cooling lake levels.

The heated water discharged from the condenser is returned to the cooling lake

through a CWS discharge structure. The main circulating water pipes from the circulating water screenhouse to the power block and from the power block to the discharge structure have an inside diameter of 144 inches.

Expected circulating water inlet temperature range is 32 to 95 degrees F. The temperature rise across the condenser is about 32.5 degrees F at full power, three circulating water pump operation.

Freeze protection to prevent ice blockage at the circulating water screenhouse is accomplished by a warming line that routes a portion of the circulating water condenser discharge to the inlet of the screenhouse pump bays.

Provisions for intermittent biocide addition to reduce the buildup of slime and biological growth in the CWS are provided.

Anti-scale chemical feed equipment is provided to inject scale inhibitor/dispersant into the CWS to inhibit mineral scale and disperse suspended solids.

10.4-14 Rev. 13 WOLF CREEK Each circulating water pump is equipped with a discharge butterfly valve that permits a pump to be isolated while operating the system with the remaining

pumps. The condenser has a permanent tube cleaning system installed to improve plant efficiency. Sponge balls are circulated from the condenser outlet stand pipes to the condenser inlet stand pipes by a ball pump. A strainer screen located in the outlet stand pipes is used to catch the sponge balls and allow the ball pumps to circulate them back through the condenser tubes.

The CWS by design prevents any release of radioactive material from the steam

system into the circulating water. The circulating water passing through the

condenser is maintained at a higher pressure than the shell or condensing side.

Therefore, any leakage (such as from a condenser tube) is from the circulating water into the shell side of the condenser.

10.4.5.2.3 System Operation

The CWS operates continuously during power generation, including startup and shutdown. The isolation valves in the standard power block are controlled by

locally mounted hand switches. There are motor operated butterfly valves on the discharge of each of the circulating water pumps that are controlled by local and main control board handswitches and the pump starting and stopping sequence.

In addition, level switches are included in the condenser pit to stop 2 of 3 circulating water pumps and close their pump discharge valves to 25% open upon a high pit water level indication and thus reduce the water flow rate to the pit. In any case, one circulating water pump will remain in operation and must be manually secured. The level switch is set to stop all but one running circulating water pump at a water level of 5 feet above the bottom of the condenser pit. High water level in the sumps in the condenser pit is alarmed to the control room. The water level trip is set high to prevent inadvertent trips from unrelated failures, such as a sump overflow.

The CWS is filled by starting the service water system. The service water can

fill the circulating water only to the tops of the circulating water discharge

weirs (approximate El. 2000). The water box venting pumps are manually started to fill the remaining portion of the CWS. During normal operation, the venting pumps operate automatically to remove air and other noncondensable gases.

Approximately one-sixth of the tubes of each of the three condensers can be

isolated by closing associated inlet and outlet water box isolation valves.

Draining of any condenser water box that is selected is initiated by closing

the condenser isolation valves and opening the drain connection and a vent

valve on the water box. When the suction standpipe of the condenser drain pump

is filled, the pump is manually started. A low level switch is provided in the

standpipe, on the suction side of the drain pump. This switch automatically stops the pump in the event of low water level in the standpipe to protect the pump from cavitation.

10.4.5.3 Safety Evaluation The CWS is not a safety-related system; however, a flooding analysis of the turbine building was performed on the CWS which

10.4-15 Rev. 13 WOLF CREEK postulated a complete rupture of a single expansion joint. It was assumed that the flow into the condenser pit consists of the water which can drain from both

the upstream and downstream side of the break. For conservatism, it was assumed that the condenser circulating water isolation valves do not fully close, sump volumes in the condenser pit were neglected, and the sump pumps were not operable. A complete description of the CWS flooding analysis is provided in Appendix 3B.

10.4.5.4 Tests and Inspections Preoperational testing is described in Chapter 14.0. The performance and

structural and leak tight integrity of all system components are demonstrated

by continuous operation.

All active components of the system (except the main condenser and piping) are

accessible for inspection during station operation.

Performance, hydrostatic, and leakage tests were conducted on the CWS butterfly valves in accordance with applicable codes as described in Chapter 14.0.

10.4.5.5 Instrumentation Applications

Temperature monitors are provided at the inlet and outlet water boxes of each condenser shell section.

Indication is provided in the control room to identify open and closed

positions of motor-operated circulating water pump discharge butterfly valves.

10.4.6 CONDENSATE CLEANUP SYSTEM The condensate cleanup function is performed by the condensate demineralizer

system (CDS). The CDS is designed to maintain the required purity of feedwater for the steam generators by filtration to remove corrosion products and by ion exchange to remove condenser leakage impurities. The secondary side water chemistry requirements are given in Section 10.3.5.

10.4-16 Rev. 13 WOLF CREEK 10.4.6.1 Design Bases 10.4.6.1.1 Safety Design Bases The CDS serves no safety function and has no safety design bases.

10.4.6.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - The CDS removes dissolved and suspended solids from the condensate prior to startup.

POWER GENERATION DESIGN BASIS TWO - The CDS removes impurities entering the

secondary cycle from condenser leaks that would otherwise deposit or increase corrosion rates in the secondary cycle.

POWER GENERATION DESIGN BASIS THREE - The CDS removes corrosion products from the condensate and any drains returned to the condenser hotwell so as to limit

any accumulation in the secondary cycle.

POWER GENERATION DESIGN BASIS FOUR - The CDS limits the entry of dissolved

solids into the feedwater system in the event of large condenser leaks, such as

a tube break, to permit a reasonable amount of time for plant shutdown.

10.4.6.2 System Description 10.4.6.2.1 General Description

The CDS consists of demineralizer vessels, regeneration tanks, pumps, piping, instrumentation, and controls, as shown in Figure 10.4-5. The CDS components are located in the turbine building at El. 2000.

10.4.6.2.2 Component Description

Codes and standards applicable to the CDS are listed in Table 3.2-2. The system is designed and constructed in accordance with quality group D

requirements. Design data for major components of the CDS are listed in Table

10.4-4.

CONDENSATE DEMINERALIZER VESSELS - The six 20-percent-capacity spherical vessels with deep-bed regenerable mixed strong acid cation/strong base anion resins, are constructed of carbon steel and lined with natural rubber. The design flowrate is approximately 53 gpm per square foot of bed, and the bed depth is approximately 36 inches.

10.4-17 Rev. 12 WOLF CREEK REGENERATION TANKS - The three resin regeneration tanks are the resin separation and cation regeneration tank, anion regeneration tank, and the resin

mixing and storage tank. All tanks are constructed of carbon steel and lined with natural rubber.

MISCELLANEOUS EQUIPMENT - Miscellaneous equipment includes two sulfuric acid

feed pumps (one standby), two caustic soda feed pumps (one standby), two sluice

water pumps (one standby), one sulfuric acid day tank, one caustic soda day tank, one resin addition hopper with eductor, one caustic dilution hot water tank, one waste collection tank, piping, instrumentation, and controls. In

addition, one sulfuric acid and one caustic feed pump, which take suction from

their respective day tanks, are included to feed chemicals into the high TDS

tanks for neutralization of pH adjustment.

10.4.6.2.3 System Operation

The CDS is operated as necessary to maintain feed-water purity levels. The

condensate demineralizers are capable of both hydrogen or ammonia/amine cycle operation in continuous or intermittent service.

The ammonia/amine cycle operation with negligible condenser leakage will allow

an extended demineralizer run. Operation with large condenser leakage requires

that the demineralizer beds be run in the hydrogen cycle to meet secondary side chemistry requirements. Allowable condenser inleakage is limited to levels that will not require continuous regeneration of a demineralizer bed more than once every 2 days.

Condensate flow is passed through up to five of the six demineralizer vessels, which are piped in parallel. The service run for each demineralizer vessel terminates by either high differential pressure across the vessel or high

cation conductivity or sodium content in the demineralizer effluent water.

Alarms for each of these monitoring points are provided on the local control

panel. The local control panel is equipped with the appropriate instruments and

controls to allow the operators to perform the following operations:

a. Remove an exhausted demineralizer from service and replace it with a standby unit

10.4-18 Rev. 14 WOLF CREEK b. Initiate resin transfer from the demineralizer vessel into the cation regeneration tank

c. Initiate resin transfer from the resin mixing and storage tank to the empty demineralizer vessel
d. Initiate a complete resin regeneration process
e. Initiate a resin wash-air scrub process without chemical regeneration

On termination of a service run, the exhausted demineralizer vessel is taken

out of service, and a standby unit is put in service by remote manual operation from the local control panel. The resin from the exhausted vessel is transferred to the cation regeneration tank. The anion and cation resins are

hydraulically separated. The anion resin is transferred to the anion

regeneration tank. Each resin is then backwashed, chemically regenerated, rinsed, and transferred to the resin mixing and storage tank for final rinsing and mixing.

The regeneration process used is a cation/anion separation process which

facilitates ammonia cycle operation. The hydraulic process effectively

separates and isolates the respective resin components; hence, the technique ensures complete conversion of both resins to the desired regenerated form.

This eliminates the possibility of either sodium or sulfate leaching into the

condensate stream. During the wash-air scrub process, there is no chemical regeneration involved. This process is used for crud removal when the resin bed has been exhausted by high differential pressure.

A final rinse is performed on the demineralizer before it is placed in service.

The rinse is monitored by conductivity analyzers, and the process is terminated

when the required conductivity is obtained.

Regenerant chemicals are 66-degrees Baume sulfuric acid and 50-percent liquid caustic soda. Dilution of the sulfuric acid and caustic soda to the required application concentrations and temperatures is accomplished at the time of use

in closed low-pressure systems employing in-line mixing tees.

Regenerant wastes are segregated by total dissolved solid (TDS) content and directed to the low or high TDS tanks in the secondary liquid waste

10.4-19 Rev. 12 WOLF CREEK system. Low TDS waste is generated in the initial backwash and during the final stages of resin rinsing following chemical regeneration. The backwash is

usually high in particulate content. The high TDS is generated from the chemical regeneration and the initial stages of the rinsing after chemical

regeneration. These values vary depending on how the system is operated.

The high and low TDS waste can be processed by either the wastewater treatment

facility as shown in Figs. 9.2-24 and 9.2-25, or the secondary liquid waste system as described in Section 10.4.10.

The demineralizer system includes all isolation valves, piping for vessels, post strainers, and equipment necessary for resin transfer. There is also a

recirculation line to the condenser for purging aerated water from any vessel being placed in service.

10.4.6.2.4 Radioactivity

Under normal operating conditions, there is insignificant radioactivity present in the steam and power conversion system. It is possible for the cycle to become contaminated through a steam generator tube leak. Based on a postulated

primary-to-secondary leak rate, the equilibrium secondary system activities are

developed in Chapter 11.0. The condensate demineralizers reduce the

radioactivity level in the secondary cycle, as described in Chapter 11.0.

Based on the condensate activity and the bed run times, the radioactivity that concentrates on the demineralizer beds will not reach a significant level. The

small quantity of radioactive material introduced to the secondary liquid waste

system is discussed in Section 10.4.10.

Radiation levels near the demineralizers can be limited by increasing the

frequency of regeneration of the beds to remove the radioactive material from

the resin beds. Administrative controls can be implemented to limit personnel

access, if required.

10.4.6.3 Safety Evaluation The CDS serves no safety function.

10.4-20 Rev. 12 WOLF CREEK 10.4.6.4 Tests and Inspections Preoperational testing of the CDS, as described in Chapter 14.0, ensured the proper functioning of the equipment and instrumentation. The system operating parameters are monitored during power operation.

10.4.6.5 Instrumentation Applications Continuous, on-line instrumentation is provided to monitor equipment performance in service or during the regeneration cycle. Local and control room alarms annunciate trouble in the system. Systematic analysis of local samples is performed to monitor the accuracy of the automatic equipment. Flow

and differential pressure are continually monitored, in addition to ionic concentration for both influent and effluent streams.

10.4.7 CONDENSATE AND FEEDWATER SYSTEM

The function of the condensate and feedwater system (CFS) is to receive condensate from the condenser hotwells and deliver feedwater, at required pressure and temperature, to the four steam generators.

10.4.7.1 Design Bases 10.4.7.1.1 Safety Design Bases The portion of the CFS from the steam generator to the steam generator isolation valves is safety related and is required to function following a DBA

and to achieve and maintain the plant in a post accident safe shutdown condition.

SAFETY DESIGN BASIS ONE - The safety-related portion of the CFS is protected

from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).

SAFETY DESIGN BASIS TWO - The safety-related portion of the CFS is designed to

remain functional after an SSE or to perform its intended function following

postulated hazards such as internal missiles, or pipe break (GDC-4).

SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC- 34).

10.4-21 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS FOUR - The CFS is designed such that the active components are capable of being tested during plant operation. Provisions are made to

allow for inservice inspection of components at appropriate times specified in the ASME Boiler and Pressure Vessel Code,Section XI.

SAFETY DESIGN BASIS FIVE - The CFS is designed and fabricated to codes

consistent with the quality group classification assigned by Regulatory Guide

1.26 and the seismic category assigned by Regulatory Guide 1.29. The power supply and control functions are in accordance with Regulatory Guide 1.32.

SAFETY DESIGN BASIS SIX - For a main feedwater line break inside the

containment or an MSLB, the CFS is designed to limit high energy fluid to the

broken loop and to provide a path for addition of auxiliary feedwater to the three intact loops.

SAFETY DESIGN BASIS SEVEN - For a main feedwater line break upstream of the main feedwater isolation valve (outside of the containment), the CFS is

designed to prevent the blowdown of any steam generator and to provide a path for the addition of auxiliary feedwater.

SAFETY DESIGN BASIS EIGHT - The CFS is designed to provide a path to permit the

addition of auxiliary feedwater for reactor cooldown under emergency shutdown

conditions (GDC-34).

10.4.7.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - The CFS is designed to provide a continuous

feedwater supply to the four steam generators at required pressure and temperature under anticipated steady-state and transient conditions.

POWER GENERATION DESIGN BASIS TWO - The CFS is designed to control the

dissolved oxygen content and pH in the turbine cycle and the steam generators.

POWER GENERATION DESIGN BASIS THREE - The CFS is designed to maintain feedwater flow following a 50-percent step reduction in electrical load.

POWER GENERATION DESIGN BASIS FOUR - The CFS is designed to provide heated

feedwater to the steam generators during startup and shutdown to minimize thermal stresses and preclude steam generator feedwater nozzle cracking.

10.4-22 Rev. 0 WOLF CREEK 10.4.7.2 System Description 10.4.7.2.l General Description The CFS, as shown in Figures 10.4-2 and 10.4-6, consists of three condensate pumps, two 67-percent capacity turbine-driven steam generator feedwater pumps, one 480 gpm capacity motor-driven feedwater pump, four stages of low-pressure

feedwater heaters, and three stages of high-pressure feedwater heaters, piping, valves, and instrumentation. The condensate pumps take suction from the condenser hotwell and discharge the condensate into one common header which

feeds the condensate demineralizers. The condensate demineralizers may be by-

passed. Downstream of the condensate demineralizers, the header branches into

three parallel trains. Each train contains four stages of low-pressure feedwater heaters. The trains join together at a common header which branches into two lines which go to the suction of the steam generator feedwater pumps.

The turbine-driven feedwater pumps discharge the feedwater into two cross-connected parallel trains. Each of the two trains contains three stages of

high-pressure feedwater heaters. Another feedwater path is provided to allow the low pressure feedwater heaters and the turbine-driven feed pumps to be bypassed during start-up and shut-down. The motor-driven feedwater pump in

this path discharges into the common header downstream of the turbine-driven

feed pumps and upstream of the high-pressure feedwater heaters. Downstream of

the high-pressure feedwater heaters, the two trains are then joined into a common header, which divides into four lines which connect to the four steam generators. Each of the four lines contains a main feedwater control valve and

main feedwater bypass control valve, a feedwater flow element, a power-operated

main feedwater isolation valve (MFIV), an auxiliary feedwater connection, a

chemical injection connection, and a check valve.

The condensate and feedwater chemical injection system, as shown in Figure

10.4-7, is provided to inject an oxygen control chemical and the pH control

chemical into the condensate pump discharge downstream of the condensate

demineralizers and additional oxygen and pH control chemicals into the four main feedwater lines connecting with the four steam generators. Injection points are shown in Figure 10.4-6.

During normal power operation, the continuous addition of oxygen and pH control

chemicals to the condensate system is under automatic control, with manual control optional. As discussed in Section 10.3 5, the addition of the pH control chemical and oxygen control chemical establishes the design pH

according to the condensate and feedwater system chemistry requirements and

establishes a constant initial oxygen control chemical residual in the feed-

water system so that oxygen inleakage can be scavenged.

10.4-23 Rev. 23 WOLF CREEK The following measures have been taken to protect personnel from any toxic effects of chemicals:

a. The pH control chemical and oxygen control chemical solution and measuring tanks are provided with a 5-psig nitrogen blanket to minimize vapors in the general atmosphere of the turbine building.
b. The concentrated ammonium hydroxide and hydrazine are diluted to less than a 17-percent chemical solution.
c. Corrosion-resistant construction materials (stainless steels) are used throughout the storage and injection equipment.
d. Chemical mixing is accomplished by closed-loop recirculation with centrifugal recirculation pumps. No external tank mixers are used to agitate tank contents.
e. Ammonium hydroxide and hydrazine drum unloading is accomplished with air-driven drum bung pumps, which are nonsparking and pose no electrical hazard to personnel.

The manually controlled feedwater chemical addition system is provided for special plant conditions, such as hydrostatic test, hot standby, layup, etc.

These conditions require high levels of pH and oxygen control chemical residual to minimize corrosion in the steam generators.

Component failures within the CFS which affect the final feedwater temperature or flow have a direct effect on the reactor coolant system and are listed in

Table 10.4-5. Occurrences which produce an increase in feedwater flow or a decrease in feedwater temperature result in increased heat removal from the

reactor coolant system, which is compensated for by control system action, as described in Section 7.7. Events which produce the opposite effect, i.e., decreased feedwater flow or increased feedwater temperature, result in reduced

heat transfer in the steam generators. Normally, automatic control system

action is available to adjust feedwater flow and reactor power to prevent

excess energy accumulation in the reactor coolant system, and the increasing reactor coolant temperature provides a negative reactivity feedback which tends to reduce reactor power. In the absence of normal control action, either the

high outlet temperature or high

10.4-24 Rev. 12 WOLF CREEK pressure trips of the reactor by the reactor protection system are available to assure reactor safety. Loss of all feedwater, the most severe transient of

this type, is examined in Chapter 15.0.

Refer to Section 5.4 for a discussion of steam generator design features to

preclude fluid flow instabilities, such as water hammer. The feedwater

connection on each of the steam generators is the highest point of each

feedwater line downstream of the MFIV. The feedwater lines contain no high point pockets which, if present, could trap steam and lead to water hammer.

The horizontal run length from the feedwater nozzle of each steam generator is

minimized. The routing of the main feedwater lines is shown in Figures 1.2-12, 1.2-15, and 1.2-17.

During refuel 5, temporary non-safety related instrumentation was added for monitoring the temperature stratification occurring inside the Feedwater

piping. The non-safety auxiliary feedwater pump (NSAFP) minimum recirculation discharges to the condensate reject line to the Condensate Storage Tank as shown in Figure 10.4-2.

10.4.7.2.2 Component Description

Codes and standards applicable to the CFS are listed in Table 3.2-1. The CFS is designed and constructed in accordance with quality group B and seismic

Category I requirements from the steam generator out to the torsional restraint

upstream of the main feedwater isolation valves. The remaining piping of the

CFS meets ANSI B31.1 requirements. Branch lines out to and including isolation valves for the auxiliary feedwater and chemical injection are designed and constructed in accordance with quality group B and seismic Category I

requirements. Refer to Tables 10.1-1 and 10.4-6 for design data. Safety-

related feedwater piping materials are discussed in Section 10.3.6.

MAIN FEEDWATER PIPING - Feedwater is supplied to the four steam generators by four 14-inch carbon steel lines. Each of the lines is anchored at the

containment wall and has sufficient flexibility to provide for relative

movement of the steam generators due to thermal expansion. The main feedwater

line and associated branch lines between the containment penetration and the torsional restraint upstream of the MFIV are designed to meet the "no break zone" criteria, as described in NRC BTP MEB-3-1 (refer to Section 3.6).

MAIN FEEDWATER ISOLATION VALVES - One main feedwater isolation valve (MFIV) is

installed in each of the four main feedwater lines outside the containment and downstream of the feedwater control valve. The MFIVs are installed to prevent uncontrolled blowdown from more than one steam generator in the event of a

feedwater pipe rupture in the turbine building. The main feedwater check valve

provides backup isolation. The MFIVs isolate the nonsafety-related portions

from the safety-related portions of the system. In the event of a secondary

cycle pipe rupture inside the containment, the MFIV limits the quantity of high energy fluid that

10.4-25 Rev. 27 WOLF CREEK enters the containment through the broken loop and provides a pressure boundary for the controlled addition of auxiliary feedwater to the three intact loops.

The valves are bi-directional, double disc, parallel slide gate valves. The valves are designed to utilize the system fluid (main steam) as the motive force to open and close. The actuator is of simple piston, with the valve stem attached to both the discs and the piston. The valve actuation (open or clsoe) is accomplished through a series of six electric solenoid pilot valves, which direct the system fluid to either the Upper Piston Chamber (UPS) or the Lower Piston Chamber (LPC), or a combination thereof. The six solenoid pilot valves are divided into two trains that are independently powered and controlled.

Either train can independently perform the safety function to fast close the valve. Electrical solenoids are energized from separate Class 1E sources.

MAIN FEEDWATER CONTROL VALVES AND CONTROL BYPASS VALVES - The MF control valves are air-operated angle valves which automatically control feedwater between 30

percent and full power. The bypass control valves are air-operated globe valves, which are used during startup up to 25-percent power. The MF control valves and bypass control valves are located in the turbine building.

In the event of a secondary cycle pipe rupture inside the containment, the main

feedwater control valve (and associated bypass valve) provide a diverse backup

to the MFIV to limit the quantity of high energy fluid that enters the

containment through the broken loop. For emergency closure, either of two separate solenoids, when de-energized, results in valve closure. Electrical solenoids are energized from separate Class 1E sources.

MAIN FEEDWATER CHECK VALVES - The Main Feedwater check valves are located in

Area 5 inside the auxiliary building, upstream of the auxiliary feedwater connection and downstream of the main feedwater isolation valves. In the event of a secondary cycle pipe rupture outside containment, the main feedwater check

valves provide a diverse backup to the MFIV to ensure the pressure boundary of

any intact loop not receiving auxiliary feedwater.

In the event of a feedwater line rupture outside containment in the turbine building the feedwater check valve will close and terminate blowdown from the

steam generator.

CHEMICAL ADDITION LINE CHECK VALVES AND ISOLATION VALVES - The check valves are located downstream from the isolation valves in the chemical addition lines.

The check valves provide a diverse backup to the isolation valves to ensure the

pressure boundary. The normally closed isolation valves are air-operated valves which fail closed.

10.4-26 Rev. 24 WOLF CREEK CONDENSATE PUMPS - The three condensate pumps are motor driven and operate in parallel. Valving is provided to allow individual pumps to be removed from

service. Pump capacity is sufficient to meet full power requirements with two of the three pumps in operation.

LOW-PRESSURE FEEDWATER HEATERS - Parallel strings of closed feedwater heaters

are located in the condenser necks. The No. 1, 2, 3 and 4 heaters have

integral drain coolers, and their drains are cascaded to the next lower stage feedwater heater in each case. The drains from No. 1 heaters are dumped to the main condenser. Feedwater leaving the No. 4 heaters is headered and goes to

the steam generator feed pumps. The heater shells are carbon steel, and the

tubes are stainless steel.

HIGH-PRESSURE FEEDWATER HEATERS - Parallel strings of three high-pressure feedwater heaters with integral drain coolers in heaters 6 and 7 are used. The

No. 7 heaters are drained to the No. 6 heaters which, in turn, drain to the heater drain tank. The No. 5 heaters drain directly to the heater drain tank.

The heater shells are carbon steel, and the tubes are stainless steel. A bypass line around the parallel strings of high-pressure feedwater heaters may be used to lower the temperature of the feedwater inlet to the steam generators such that reactor thermal power can be maximized within the licensed limit.

Isolation valves and bypasses are provided which allow each string of high-pressure and low-pressure heaters to be removed from service. System operability is maintained at reduced power with the parallel heaters and bypass line.

Provisions are made in all heater drain lines, except No. 5, which drains via the heater drain tank, to allow direct discharge to the condenser in the event the normal drain path is blocked.

HEATER DRAIN TANK - A single heater drain tank drains the shells of No. 5 and

No. 6 feedwater heaters and provides reservoir capacity for drain pumping. The heater drain tank is installed in such a way that the No. 5 heaters drain freely by gravity flow. The drain level is maintained within the tank by a

level controller in conjunction with a heater drain pump.

The heater drain tank is provided with an alternate drain line to the main condenser for automatic dumping upon high level. The alternate drain line is also used during startup and shutdown when it is desirable to bypass the drain

piping for feedwater quality purposes.

HEATER DRAIN PUMPS - Two motor-driven heater drain pumps operate in parallel, taking suction from the heater drain tank and discharging it into the suction of the steam generator feed pumps.

10.4-27 Rev. 11 WOLF CREEK The piping arrangement allows each heater drain pump to be individually removed from service while operating the remaining pump.

STEAM GENERATOR FEEDWATER PUMPS - The steam generator feedwater pumps (SGFP) operate in parallel and discharge to the high-pressure feedwater heaters. The pumps take suction following the No. 4, low-pressure feedwater heaters and

discharge through the high-pressure feedwater heaters. Each pump is turbine

driven with independent speed-control units. Steam for the turbines is supplied from the main steam header at low loads and from the moisture separator reheater outlet during normal operation.

Isolation valves are provided which allow each steam generator feed pump to be

individually removed from service, while continuing operations at reduced capacity.

PUMP RECIRCULATION SYSTEMS - Minimum-flow control systems are provided to allow all pumps in the main condensate and feedwater trains to pump at the

manufacturer's recommended minimum flow rate to prevent damage.

MOTOR-DRIVEN FEEDWATER PUMP - One motor-driven feedwater pump (MDFP) is

provided to feed heated feedwater to the steam generators during start-up and

shutdown conditions. The pump takes suction from the steam generator blowdown

regenerative heat exchanger and discharges through the high-pressure feedwater heaters.

10.4.7.2.3 System Operation

STARTUP OPERATION - Feedwater can be provided to the steam generators using the condensate and feedwater system or the auxiliary feedwater system. Feedwater preheating requires the normal feedwater system in operation. Feedwater preheating is used to minimize thermal stresses on the feedwater piping and steam generator feedwater nozzles. At low pressures the condensate pumps can provide sufficient pressure to provide flow to the generators. Above condensate pressure a feedwater pump must also be used. A motor-driven feedwater pump (MDFP) is provided that may be used to provide feedwater at low powers(~1.5%) until there is adequate steam flow to operate the main feedwater pumps. The condensate system is used to provide a suction source for the MDFP.

If the MDFP is used, the condensate flow path to this pump will bypass the low-pressure feedwater heaters. This condensate is directed to the steam generator blowdown regenerative heat exchanger, where it will be heated by the discharge from the steam generator blowdown flash tank if the steam generator blowdown (SGBD) system is in service. The feedwater flowpath then is directed through the high pressure feedwater system to the steam generators. The vapor from the SGBD flash tank is normally routed to the heater drain tank. The vapor in the heater drain tank enters the No. 5 high-pressure heaters which in turn will heat the feedwater for the steam generators.

Additional heating can be provided from main steam using portions of the auxiliary steam and the extraction steam systems to the No. 6 high-pressure heaters. Main steam can also be used to the No. 6 and 7 high-pressure heaters using additional portions of the main steam system and controls. During this time, two condenser steam dumps, AB UV-34 and AB UV-35, will be isolated. This feedwater preheating is removed from service prior to 25% thermal power. The feedwater is generally operated to maintain feedwater temperature to within 250 o F of the steam generator temperature.

10.4-28 Rev. 15 WOLF CREEK SHUTDOWN OPERATION - During shutdown operation several possible paths can be used. First the condensate system may be used alone when steam generator

pressure is low. At higher required feedwater pressure the MDFP or the main feedwater pumps will be used. The feedwater may be preheated using the SGBD system through the regenerative heat exchanger when the SGBD system is in service. Additional heating can be utilized from the steam generator flash

tank vapor. The steam generator flash tank is normally aligned to the heater

drain tank where the vapor flows up to the No. 5 high-pressure heaters adding heat to the feedwater system. When below 25%, main steam can be used to heat the feedwater by using portions of the auxiliary steam system and the

extraction steam system to the No. 5 high-pressure heaters. The feedwater is

preheated to minimize thermal stresses on the feedwater piping and steam

generator feedwater nozzles. This system generally maintains feedwater temperature to within 250 o F of the steam generator temperature. If these systems are not available, then auxiliary feedwater will be used. Auxiliary feedwater does not provide preheating to the feedwater.

NORMAL OPERATION - Under normal operating conditions, system operation is automatic. Automatic level control systems control the levels in all feedwater heaters, the heater drain tank, and the condenser hotwells. Feedwater heater

levels are controlled by modulating drain valves. Control valves in the

discharges of the heater drain pumps control heater drain pump flows in

reaction to the level in the heater drain tank.

A bypass line around the parallel strings of high-pressure feedwater heaters

may be used to lower the temperature of the feedwater inlet to the steam

generators such that reactor thermal power can be maximized within the licensed

limit. Three valves, two in the makeup line to the condenser from the condensate

storage tank and another valve in the return line to the condensate storage

tank, control the level in the condenser.

At very low power levels, feedwater is supplied by the motor-driven feedwater pump. Once sufficient steam pressure has been established, an SGFP turbine is

started, and from this low power level, to approximately 20-percent power, feedwater flow is under the control of the feedwater bypass control valves and

their control system. At between 20 and 30 percent power, feedwater flow is being transferred from the feedwater bypass control valves to the main feedwater control valves. SGFP turbine speed is under manual control.

At greater than 30-percent power, feedwater flow is controlled by the main

feedwater control valves, and SGFP turbine speed is automatically controlled.

The steam generator feedwater pump turbines are controlled by a speed signal from the feed pump speed control system. The control system utilizes

measurements of steam generator steam flow, feedwater pressure, and steam

pressure to produce this signal. The pump speed is increased or decreased in

accordance with the speed signal by modulating the flow of steam admitted to

the pump turbine drivers.

The feedwater flow to each steam generator is controlled by a three-element

feedwater flow control system to maintain a programmed water level in the steam

generator. The feedwater controllers regulate the feedwater control valves and

feedwater pump speed by continuously comparing steam generator water level with the programmed level and feedwater flow with the pressure-compensated steam flow signal.

10.4-29 Rev. 21 WOLF CREEK Ten-percent step load and 5-percent per minute ramp changes are accommodated without major effect in the CFS. The system is capable of accepting a 50-

percent step load rejection. Under this transient, heater drain pump flow is lost, and the high pressure feedwater heater drain flows are dumped to the condenser via the heater drain tank. The condensate pumps pass full feedwater flow until heater drain pump flow is restored.

EMERGENCY OPERATION - In the event that the plant must be shut down and offsite power is lost, or a DBA occurs which results in a feedwater isolation signal, the MFIV and other valves associated with the main feedwater lines are closed.

Coordinated operation of the auxiliary feedwater system (refer to Section

10.4.9) and the main steam supply system (refer to Section 10.3) is employed to

remove decay heat.

10.4.7.3 Safety Evaluation Safety evaluations are numbered to correspond to the safety design bases of

Section 10.4.7.1.1.

SAFETY EVALUATION ONE - The safety-related portions of the CFS are located in

the reactor and auxiliary buildings. These buildings are designed to withstand

the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.

SAFETY EVALUATION TWO - The safety-related portions of the CFS are designed to

remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as out-lined in Section 7.4, can be achieved and maintained.

SAFETY EVALUATION THREE - The CFS safety functions are accomplished by redundant means, as indicated by Table 10.4-7. No single failure compromises the system's safety functions. All vital power can be supplied from either

onsite or offsite power systems, as described in Chapter 8.0.

SAFETY EVALUATION FOUR - Preoperational testing of the CFS is performed as described in Chapter 14.0. Periodic inservice functional testing is done in accordance with Section 10.4.7.4.

Section 6.6 provides the ASME Boiler and Pressure Vessel Code Section XI

requirements that are appropriate for the CFS.

SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of

this system and supporting systems. Table 10.4-6 shows that the components

meet the design and fabrication codes given in Section 3.2. All the power

supplies and controls necessary for the safety-related functions of the CFS are Class 1E, as described in Chapters 7.0 and 8.0.

SAFETY EVALUATION SIX - For a main feedwater line break inside the containment

or an MSLB, the MFIVs located in the auxiliary building and the main feedwater

control valves located in the turbine building are automatically closed upon receipt of a feedwater isolation signal or low-low steam generator level signal. For each intact loop, the MFIV and main feedwater control valve.

10.4-30 Rev. 19 WOLF CREEK and associated redundant isolation of the chemical addition line will close, forming a pressure boundary to permit auxiliary feedwater addition. The

auxiliary feedwater system is described in Section 10.4.9.

SAFETY EVALUATION SEVEN - For a main feedwater line break upstream of the MFIV, the MFIVs are supplied with redundant power supplies and power trains to ensure

their closure to isolate safety and nonsafety-related portions of the system.

Branch lines downstream of the MFIVs contain normally closed, power-operated valves which close on a feedwater isolation signal. These valves fail closed on loss of power.

Releases of radioactivity from the CFS due to the main feedwater line break are

minimal because of the negligible amount of radioactivity in the system under normal operating conditions. Additionally, following a steam generator tube rupture, the main steam isolation system provides controls for reducing

accidental releases, as discussed in Section 10.3 and Chapter 15.0. Detection of radioactive leakage into and out of the system is facilitated by area

radiation monitoring (discussed in Section 12.3.4), process radiation monitoring (discussed in Section 11.5), and steam generator blowdown sampling (discussed in Section 10.4.8).

SAFETY EVALUATION EIGHT - In the event of loss of offsite power, loss of the

steam generator feedwater pumps, or other situations which may result in a loss of main feedwater, the feedwater isolation signal automatically isolates the feedwater system and permit the addition of auxiliary feedwater to allow a

controlled reactor cooldown under emergency shutdown conditions. The auxiliary

feedwater system is described in Section 10.4.9.

10.4.7.4 Tests and Inspections 10.4.7.4.1 Preservice Valve Testing

The MFIVs and feedwater control valves were checked for closing time prior to initial startup.

10.4.7.4.2 Preoperational System Testing

Preoperational testing of the CFS was performed as described in Chapter 14.0.

10.4.7.4.3 Inservice Inspections

The performance and structural and leaktight integrity of all system components

are demonstrated by continuous operation.

The feedwater flow venturi is inspected for fouling and cleaned, as necessary, once every 18 months.

10.4-31 Rev. 13 WOLF CREEK The redundant actuator power trains of each MFIV are subjected to the following tests:

a. Closure time - The valves are checked for closure time at each refueling.

Additional discussion of inservice inspection of ASME Code Class 2 and 3 components is presented in Section 6.6.

10.4.7.5 Instrumentation Applications

The main feedwater instrumentation, as described in Table 10.4-8, is designed

to facilitate automatic operation, remote control, and continuous indication of system parameters. As described in Chapter 7.0, certain devices are involved in the secondary cycle pipe rupture protection system.

The feedwater flow to each steam generator is controlled by a three-element

feedwater flow control system to maintain a programmed water level in the steam generator. The three-element feedwater controllers regulate the feedwater control valves by continuously comparing the feedwater flow and steam generator

water level with the programmed level and the pressure-compensated steam flow

signal (refer to Section 7.7).

The steam generator feedwater pump turbine speed is varied to maintain a programmed pressure differential between the steam header and the feed pump discharge header. The pump speed is increased or decreased in accordance with

the speed signal by modulating the steam pressure at the inlet of the pump

turbine drivers.

Both SGFP turbines are tripped upon any one of the following:

a. High-high level in any one steam generator
b. Feedwater isolation signal from the engineered safety features actuation system
c. Any condition which actuates safety injection (refer to Section 7.3)

10.4-32 Rev. 24 WOLF CREEK d. Trip of all condensate pump motors

e. High feedwater system pressure One turbine trips when any one of the following directly affects it:
a. Low lube oil pressure
b. Turbine overspeed
c. Low vacuum
d. Thrust bearing wear
e. Hydraulic Pressure Unit (HPU) header pressure
f. Turbine trip header oil pressure A flow element with a transmitter is installed on the discharge of each of the condensate and heater drain pumps. The transmitters provide the automatic

signals to open the minimum flow valves for the pumps.

A flow element is installed on the suction of each of the steam generator feedwater pumps to provide the control signal to open the minimum recirculation valves for the steam generator feedwater pumps.

Pressure transmitters are located in the main feedwater header to provide the feedwater system pressure to the speed-control system for the steam generator feedwater pump turbines. A flow element with two flow transmitters is located on the inlet to each of the four steam generators to provide signals for the

three-element feedwater control system.

The total water volume in the condensate and feedwater system is maintained through automatic makeup and rejection of condensate to the condensate storage tank. The system makeup and rejection are controlled by the condenser hotwell

level controllers.

The system water quality is automatically maintained through the injection of an oxygen control chemical and a pH control chemical into the condensate system. The pH control chemical and oxygen control chemical injection is

controlled by pH and the oxygen control chemical residual in the system, which

is continuously monitored by the process sampling system.

10.4-33 Rev. 27 WOLF CREEK Instrumentation, including pressure indicators, flow indicators, and temperature indicators, required for monitoring the system is provided in the

control room.

10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM

The steam generator blowdown system (SGBS) helps to maintain the steam

generator secondary side water within the chemical specifications prescribed by the NSSS supplier. Heat is recovered from the blowdown and returned to the feedwater system. Blowdown is then either treated to remove impurities before

being returned to the condenser, or discharged to the lake.

10.4.8.1 Design Bases 10.4.8.1.1 Safety Design Basis

Portions of the SGBS are safety-related and are required to function following

a DBA and to achieve and maintain the plant in a post accident safe shutdown condition. The following safety design bases have been met:

SAFETY DESIGN BASIS ONE - The safety-related portion of the SGBS is protected

from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).

SAFETY DESIGN BASIS TWO - The safety-related portion of the SGBS remains

functional after an SSE or performs its intended function following a

postulated hazard, such as internal missile, or pipe break (GDC-4).

SAFETY DESIGN BASIS THREE - Safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power (GDC-34).

SAFETY DESIGN BASIS FOUR - The active components of the SGBS are capable of being tested during plant operation. Provisions are made to permit inservice inspection of components at appropriate times specified in the ASME Boiler and

Pressure Vessel Code,Section XI.

SAFETY DESIGN BASIS FIVE - The SGBS is designed and fabricated to codes consistent with the quality group classification assigned by Regulatory Guide 1.26 and the seismic category assigned by Regulatory Guide 1.29. The power

supply and control functions are in accordance with Regulatory Guide 1.32.

10.4-34 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS SIX - The capability of isolating components or piping of the SGBS is provided. This includes isolation of components to deal with

leakage or malfunctions and isolation of nonsafety-related portions of the system. An isolation valve is provided in each main line which automatically closes to isolate the secondary side of the steam generator in the event of a DBA.

SAFETY DESIGN BASIS SEVEN - The containment isolation valves for the steam generator drain line are selected, tested, and located in accordance with the requirements of 10 CFR 50, Appendix A, General Design Criteria 54 and 56, and

10 CFR 50, Appendix J, Type C testing.

10.4.8.1.2 Power Generation Design Bases POWER GENERATION DESIGN BASIS ONE - The SGBS is designed to ensure that

blowdown treatment is compatible with the condensate and feedwater to ensure an effective secondary system water chemistry control program.

POWER GENERATION DESIGN BASIS TWO - The SGBS is designed to accommodate flows up to 44,000 pounds per hour (nominally 90 gpm) per steam generator, while

returning to the feedwater system a sizable portion of the heat removed from

the steam generators.

POWER GENERATION DESIGN BASIS THREE - During normal operation without primary-to-secondary leakage, the SGBS is designed to process blowdown to meet the

chemical composition limits for release to the environment or for return to the

condenser hotwell/condensate storage tank.

POWER GENERATION DESIGN BASIS FOUR - During periods of abnormal operation with a primary-to-secondary steam generator leak, the SGBS maintains the plant effluent within the radiological specification for plant discharge.

POWER GENERATION DESIGN BASIS FIVE - Portions of the SGBS use design and fabrication codes consistent with quality group D (augmented) as assigned by Regulatory Guide 1.143 for radioactive waste management systems.

10.4.8.2 System Description 10.4.8.2.1 General Description The SGBS is shown in Figure 10.4-8. The system consists of a flash tank, a regenerative heat exchanger, a nonregenerative heat exchanger, filters, demineralizers, a surge tank, and discharge and drain pumps.

10.4-35 Rev. 3 WOLF CREEK The SGBS is designed to control the secondary side water chemistry, in conjunction with the condensate and feedwater chemical addition system and the

condensate demineralizer system, to meet water chemistry specifications. The SGBS serves to remove impurities in the blowdown that originate from sources such as primary-to-secondary leakage, main condenser leakage, sodium carry-over from deep-bed condensate demineralizers, and the corrosion and wear of other

secondary cycle components and piping.

Each of the four steam generators has its own blowdown and sample lines. The total continuous blowdown range of 60-360 gpm is provided to administratively

permit blowdown to match the variable and cyclic nature of the sources of

contamination.

The steam generator blowdown fluid (blowdown) is extracted from the steam generators through a blowdown sparger ring located in the shell side of the

steam generator just above the tube sheet, where impurities are expected to accumulate.

The blowdown flow rate from each steam generator is controlled manually using throttling valves just upstream of the blowdown flash tank. The flashed vapor

from the flash tank is sent to the number five feedwater heater (or to the

condenser or atmosphere during startup).

The liquid effluent from the flash tank is first cooled in the regenerative heat exchanger (heat recovery medium is a portion of the condensate flow) and

then further cooled by the nonregenerative heat exchanger (cooling medium is

service water). The fluid may then be filtered and/or demineralized before

being returned to the condenser or before being discharged.

The operator has the option of discharging the blowdown to the environment or returning the blowdown to the condenser. Any limitations on discharges from the plant are within the limits defined by the Offsite Dose Calculation Manual (ODCM). Leak detection from the SGBS is provided by visual examination and by the floor drain system described in Section 9.3.3.

Section 3.6 provides an evaluation that demonstrates that the pipe routing is physically separated from essential systems to the maximum extent practical.

Protection mechanisms that may be required to mitigate the dynamic effects of

piping ruptures are also discussed in Section 3.6.

10.4-36 Rev. 18 WOLF CREEK 10.4.8.2.2 Component Description

Codes and standards applicable to the SGBS are listed in Tables 3.2-1 and 10.4-

9. The SGBS is designed and constructed in accordance with the following quality group requirements: Steam generator blowdown lines from the steam generators to the outer SGBS isolation valve are quality group B and are

seismic Category I. The flash tank, regenerative heat exchanger, and

nonregenerative heat exchangers, which contain minimal radioactivity, are located in the turbine building; all other components are located in seismically designed buildings. Components downstream of the outer SGB

isolation valve are quality group D (augmented). Design data for the SGBS

components are listed in Table 10.4-9.

STEAM GENERATOR BLOWDOWN FLASH TANK - The flash tank pressure is maintained between 185 and 135 psia. This causes the high-temperature high-pressure

blowdown liquid to be flashed (i.e., reduced in temperature and pressure). The four steam generator blowdown lines enter the flash tank tangentially at

equally spaced distances around the tank.

STEAM GENERATOR REGENERATIVE BLOWDOWN HEAT EXCHANGERS - The heat exchanger

cools the blowdown from the flash tank. The heat exchanger is of shell and

welded tube design. The cooling medium is condensate water.

STEAM GENERATOR NONREGENERATIVE HEAT EXCHANGER - The heat exchanger cools the blowdown from the flash tank or the regenerative heat exchanger to 120° F

before it flows to the demineralizers. The heat exchanger is of shell and

welded tube design. The cooling medium is service water.

STEAM GENERATOR BLOWDOWN FILTER - This filter removes particulate matter from the steam generator blowdown fluid before it flows to the demineralizers. This serves to extend the operating life of the demineralizer resins. Unfiltered blowdown is normally discharged to the lake.

STEAM GENERATOR BLOWDOWN MIXED-BED DEMINERALIZERS - Two sets of two parallel, 50-percent capacity, mixed-bed demineralizers normally operated one set at a

time are provided in the blowdown treatment train. Conductivity monitors are located downstream of the demineralizers to signal exhaustion of the upstream bed. When the in-service set of demineralizers is exhausted, the set of demineralizers with the fresh resin is placed into service. The exhausted set of demineralizers is then removed from service, the resin replaced and this

freshly recharged set of demineralizers is left in standby until the in-service

demineralizer set exhausts. Blowdown that is not demineralized is normally discharged to the lake.

10.4-37 Rev. 18 WOLF CREEK STEAM GENERATOR BLOWDOWN SURGE TANK - The surge tank collects the blowdown water prior to discharge from the system, and provides the necessary suction

head for the discharge pumps.

STEAM GENERATOR BLOWDOWN BYPASS DISCHARGE PIPING - The bypass piping allows for the option to direct blowdown flow to the lake without using the surge tank or the discharge pumps. The piping is connected to the inlet line to the surge tank and reconnected to the blow down discharge line upstream of BMFO0054.

STEAM GENERATOR BLOWDOWN DISCHARGE PUMP - The inline centrifugal pumps are

provided to pump the treated blowdown water from the surge tank to the plant

discharge, or recycle the blowdown water through the demineralizer train. One

pump is normally in service unless bypassed. A second pump serves as a backup.

STEAM GENERATOR DRAIN PUMP - Two inline centrifugal pumps are provided to pump

the blowdown to the process train or the secondary cycle to drain a steam

generator.

BLOWDOWN LINES - Blowdown from each of the four steam generators is conveyed to the SGB flash tank by four 4-inch lines. Each of the lines is anchored at the

containment wall and has sufficient flexibility to provide for relative

movement of the steam generators due to thermal expansion. The blowdown line

and associated branch lines between the reactor building penetration and the first torsional restraint, past the blowdown isolation valve (BIV) are designed to meet the "no break zone" criteria, as described in NRC BTP MEB 3-1.

BLOWDOWN ISOLATION VALVES - One BIV is installed in each of the four blowdown

lines outside the containment. The BIVs are installed to prevent uncontrolled blowdown from more than one steam generator. Failure of the blowdown isolation valve for an unaffected steam generator after an MSLB results in blowdown from

that steam generator to the blowdown flash tank. This steam loss has less

effect on the primary system than does the steam lost as a result of other

failures discussed in Section 15.1.5. The valves isolate the nonsafety-related portions from the safety-related portions of the system. The valves are air-operated globe valves which fail closed. For emergency closure, either of two

safety-related solenoids is deenergized to dump air supplied to the valve

actuator. The electrical solenoids are energized from separate Class 1E

sources and are tripped upon receipt of a SGBSIS (AFAS) signal.

An additional nonsafety-related solenoid is provided which is de-energized to

close the BIV upon receipt of a high radiation level signal or other system-

related trip signals.

SAMPLE ISOLATION VALVES - Three safety-related sample isolation valves (SIV) are installed in each of the four sample lines. Two are inside the containment (one from each sample point), and one is outside. The SIVs are installed to

prevent uncontrolled blow-down from more than one steam generator. The valves

isolate the

10.4-38 Rev. 23 WOLF CREEK nonsafety-related portions from the safety-related portions of the system. The valves are solenoid operated, are energized from separate Class 1E sources, and

tripped upon receipt of a SGBSIS (AFAS) signal.

An additional nonsafety-related solenoid valve is provided outside the containment which is de-energized to close upon receipt of a high radiation

level signal or other system-related trip signal.

INSULATION - Portions of the sample lines associated with the containment penetration and the safety related portions of the drain lines have insulation

designed to withstand the effects of a loss-of-coolant accident or other high

energy line break. The purpose of the insulation is to mitigate the thermal

transfer of heat into the water due to containment heat-up following a LOCA/HELB, and limit the potential build-up of internal pressure in the pipe due to the expansion of the water. The insulation is designed not to lose its

insulation capability during and after the event.

10.4.8.2.3 System Operation During full power operation, the SGBS can be operated in one of several

different modes, depending upon the type and level of contamination in the

blowdown. The operator determines, based on prior knowledge of secondary cycle

water chemistry conditions and radioactivity levels in conjunction with ODCM limitations and state and local discharge permit restrictions, the extent of processing required by the blowdown system.

NORMAL OPERATION WITH FULL SYSTEM PROCESSING - Normally, the SGBS is operated, utilizing the full processing capability of the system with heat recovery.

Figure 10.4-8 shows valve positions aligned to process the blowdown fluid

through the demineralizer processing portion of the system and then to the

secondary cycle.

The blowdown flash tank pressure is normally maintained from 185 psia to a minimum of 135 psia (corresponding to No. 5 feedwater heater pressure at

approximately 80-percent power) by a backpressure control valve in the flash

tank vent line. Depending upon station load, approximately 23 to 30 percent of

the blowdown flow will be flashed into vapor. This flow, containing about half of the total blowdown heat energy, is returned to the feedwater system via the No. 5 feedwater heater shell.

The remaining saturated fluid from the flash tank is first cooled by the regenerative heat exchanger to an intermediate temperature ( 190°F) and then further cooled by the nonregenerative heat exchanger to 120°F. Level control valves in each of the processing flow paths (to the condenser, condensate

storage tank, and blowdown surge tank) maintain a level in the flash tank that

provides an elevation head on the fluid entering the heat exchangers for suppression of further fluid flashing.

Additional heat recovery is attained with the regenerative heat exchanger which

uses a portion of the condensate flow (less than 2 percent of VWO flow) for

cooling water. This condensate flow is diverted from the condensate system downstream of the condensate

10.4-39 Rev. 14 WOLF CREEK demineralizers and is returned to the heater drain tank. The outlet temperature from the regenerative heat exchanger is normally maintained at 190 F with the temperature control valve provided in the line to the heater drain tank to control the condensate flow through the regenerative heat exchanger. During periods of low blowdown flow rates, a lower regenerative outlet temperature can be obtained.

Cooling water for the nonregenerative heat exchanger is service water. A

three-way temperature control valve is provided in the bypass line around the

nonregenerative heat exchanger to maintain a high service water flow rate

through the shell side of the heat exchanger, during periods of low service water temperatures and low blowdown flow rates.

The high service water flow rates are required to minimize particle deposition within the heat exchanger and thereby reduce the fouling tendency of the heat

exchanger.

Following the flash tank and heat exchangers, the liquid portion of the

blowdown is directed through a radiation monitor prior to processing through

two filters in parallel and two sets of two parallel 50-percent capacity

demineralizers operated in series. In addition, strainers are provided upstream of each filter and downstream of each demineralizer. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam

generator tube failure. The processing system is designed to operate

continuously provided the resin beds are periodically replaced. The effluent

water normally meets the specifications for water purity and radioactivity for return to the condenser hotwell. Resin bed exhaustion is signaled by a high conductivity alarm from either of two conductivity meters; the first is located

in the common line downstream of the first set of parallel demineralizers, and the second is located in the common line downstream of the second set of

parallel demineralizers. A high conductivity alarm indicates exhaustion of the upstream beds. After replacing the resin in the exhausted beds, the order of flow through the parallel beds in series is reversed.

The processed blowdown can be sent either to the condenser or discharged to the

environment. If the blowdown is to be discharged directly to the environment, the fluid is directed into the steam generator blowdown surge tank or to the steam generator blowdown bypass discharge piping. From the surge tank, the fluid is pumped by the discharge pumps to the radwaste building discharge line through a radiation monitor. The surge tank level is controlled by a level

valve in the discharge line from the pumps. Level instrumentation is provided on the surge tank to prevent damage to the discharge pumps on loss of level.

The steam generator blowdown bypass discharge piping will allow blowdown fluid to be taken off up stream of the surge tank, which will allow the surge tank and the discharge pumps to be bypassed. This will allow the option to use the system pressure to discharge the blowdown fluid to the lake without the discharge pumps or surge tank.

10.4-40 Rev. 23 WOLF CREEK Upon indication of high activity by the radiation monitors, the blowdown discharge valve is closed and the discharge pumps are stopped, automatically terminating discharge, and the blowdown isolation valve in each blowdown line is closed, thereby automatically terminating blowdown. High level in the surge tank terminates blowdown by automatically closing the blowdown isolation valves and the flash tank level control to the blowdown surge tank. In addition, discharge of blowdown to the environment is automatically terminated on a low

dilution water flow signal. A flow path can be established to allow the fluid in the surge tank to be reprocessed through the processing portion of the blowdown system.

During periods of primary-to-secondary leakage, the blowdown fluid is purified

by the processing portion of the blowdown system to limit any radioactive contamination of the secondary system.

OPERATION WITHOUT BLOWDOWN PROCESSING - As permitted by the type and level of

the contaminants in the blowdown fluid, the operator can determine the extent of system processing required to meet the chemistry requirements for either discharge or return to the condenser. The radiation monitor alarms and terminates blowdown on a high reading indicative of a steam generator tube

failure, and alarms only when the operator should be made aware that processing

may be required. A bypass flow path can be established from a point downstream

of the heat exchangers to either the condenser or the surge tank for periods of operation where processing within the blowdown system is not desired.

During normal operating conditions with no significant radioactive contaminants

in the system and where the chemistry of the blowdown fluid meets the ODCM

limitations for release restrictions, the processing portion of the system can be bypassed and the fluid can be discharged. When discharging, the fluid is directed to the surge tank and through the radiation monitor to the environment.

Also, during periods of normal plant operation with the condensate demineralizers in service and with insignificant radioactive contaminants in the system, the processing portion of the blowdown system (i.e. filters and

demineralizers) can be bypassed and the fluid can be returned directly to the

condenser, provided that the feedwater remains within the chemistry

specifications.

OPERATION WITH REGENERATIVE HEAT EXCHANGER OUT OF SERVICE - During periods of

operation when the regenerative heat exchanger is out of service, a bypass line

is provided to permit continued oper-

10.4-41 Rev. 23 WOLF CREEK ation. The maximum blowdown rate is then limited by the nonregenerative heat exchanger's capacity for reducing the fluid temperature to less than 120 F. System operation downstream of the heat exchangers continues to be based on the processing requirements to maintain the chemistry specifications.

OPERATION WITH THE NONREGENERATIVE HEAT EXCHANGER OUT OF SERVICE - In this

mode, three-way temperature control valve in the bypass line around the nonregenerative heat exchangers is manually maintained open. The temperature control valve which maintains blowdown fluid outlet temperature from the

regenerative heat exchanger is set for approximately 150øF. This temperature

setting may require that the demineralizers be bypassed in order to prolong

resin life and preclude the possibility of eluting the radioactivity that has been adsorbed by the resin. With the flash tank venting to the condenser, the total steam generator blowdown then is limited to about 50,000 lbs/hr.

USE OF THE STEAM GENERATOR BLOWDOWN DEMINERALIZERS BY THE SECONDARY LIQUID WASTE (SLWS) - As a backup to the SLWS demineralizer, interties have been provided between the SLWS and the steam generator blowdown system to allow the processing of SLWS low TDS waste by either of the two sets of two parallel steam generator blowdown demineralizers. The system is designed so that blowdown can be processed by the set of demineralizers not being used for

processing the low TDS waste.

SAMPLING - The blowdown system sample points are arranged to provide

selectively extracted samples from each of the steam generator drums, each

individual blowdown line, and the surge tank. The nuclear sample connection

from the blowdown lines is located as close to the steam generator as possible to minimize transit time from the steam generator water mass to the point of use and to ensure maximum sample quality.

The process sampling system is normally used to continuously determine the chemical composition of the liquid in each of the steam generators. The process sample extraction points are located in the turbine building.

10.4-42 Rev. 14 WOLF CREEK A continuous inline radioactivity monitor is provided to detect the presence of activity which would indicate a primary-to-secondary leak. Anytime the

unprocessed blowdown activity level exceeds 1.0 x 10

-5 Ci/gm (excluding tritium), periodic samples are taken at the nuclear sampling station and analyzed in the hot lab to ascertain the affected steam generator and to monitor any increase in primary-to-secondary leakage. The nuclear sampling

system is capable of receiving intermittent or continuous samples from either

each of the steam generator drums or each of the individual blowdown lines.

The chemical composition is continuously monitored by the process sampling system.

STARTUP AND SHUTDOWN OPERATION - The startup and shutdown operations of the

blowdown system are the same as for normal operation, except that the secondary cycle is not able to receive the flash tank vent fluid. When feedwater is not flowing through the No. 5 feedwater heater, the flash tank vent is directed to

the condenser. If condenser vacuum is not being maintained, the vent is directed to the atmosphere. In the event that the condensate pumps (which

would provide condensate cooling flow for the regenerative heat exchanger) or the heater drain tank are unavailable, it is possible for the liquid blowdown to be returned to the environment or the condensate storage tank rather than

the condenser. Under these conditions, the total steam generator blowdown flow

is limited by the capability of the nonregenerative heat exchanger to maintain

cooled blowdown below the required limits. When demineralization or discharge to the environment is required, a 120°F limit is maintained. If the blowdown is being directed to the condensate storage tank, the blowdown is cooled to a maximum of 120 F. During shutdown with the steam generator depressurized, the steam generator drain pumps may be employed to drain and dispose of or process steam generator water. A connection is available to the suction side of the condensate pumps

for processing of the liquid through the condensate demineralizers and bypassing the condenser.

Wet layup capabilities are provided to protect the steam generators from

corrosive attack during inactive periods. This is achieved by ensuring the

exclusion of oxygen and controlling the pH of the water mass inside the steam

generators.

EMERGENCY OPERATION - The isolation valves of the blowdown and sample systems

are closed automatically by the signal from system radiation monitors, by the

condenser air removal exhaust monitor, and/or by the SGBSIS (AFAS) signal. All

of these valves are capable of being remotely closed from the control room.

10.4-43 Rev. 10 WOLF CREEK Following a radiation monitor alarm, or start of the auxiliary feedwater system, the sample system isolation valves may be reopened from the control

room. This capability permits identification, and subsequent isolation, of the steam generator responsible for fission product transfer from the primary to the secondary system. After reset of the AFAS, the blowdown system isolation valves may be reopened from the control room.

10.4.8.3 Radioactive Releases In the event radioactivity is transmitted to the secondary side of the steam

generator, it will show up in the blowdown fluid. For conditions of primary-to-secondary leakage, all blowdown fluid is processed and returned to the main condenser. Any discharge of radioactive fluid from this system is considered unlikely.

If the blowdown fluid is being discharged to the environment and the activity

level in the discharged fluid approaches the limit defined by the ODCM, the

radiation monitor in the discharge line alarms and automatically terminates discharge and blowdown. In addition, blowdown discharge to the environment is automatically terminated on a low dilution water flow signal.

When discharging to the environment, the discharge temperature is between 60-

120°F, exit pressure is35-150 psig, and the flow rate is a maximum of 270 gpm.

The operating criteria for the secondary side blowdown system are dictated by

the need for limiting the secondary side build-up of dissolved solids. The

equilibrium radioactive concentrations based on a assumed primary-to-secondary

leakrate are given in Chapter 11.0 for the steam generators.

10.4.8.4 Safety Evaluation Safety evaluations are numbered to correspond to the safety design bases in

Section 10.4.8.1.

SAFETY EVALUATION ONE - The safety-related portions of the SGBS are located in

the reactor and auxiliary buildings. These buildings are designed to withstand

the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections 3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of these buildings.

10.4-44 Rev. 26 WOLF CREEK SAFETY EVALUATION TWO - The safety-related portions of the SGBS are designed to remain functional after a SSE. Sections 3.7(B).2 and 3.9(B) and (N) provide

the design loading conditions that were considered. Sections 3.5 and 3.6 provide the hazards analyses to assure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained.

SAFETY EVALUATION THREE - The component and system description for the SGBS

shows that complete redundancy is provided and, as indicated by Table 10.4-10, no single failure will compromise the system's safety functions. All vital power can be supplied from either onsite or offsite power systems, as described

in Chapter 8.0.

SAFETY EVALUATION FOUR - Periodic inservice functional testing is done in accordance with Section 10.4.8.5. Section 6.6 provides the ASME Boiler and Pressure Vessel Code,Section XI requirements that are appropriate for the

SGBS.

SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. Table 10.4-9 shows that the components meet the design and fabrication codes given in Section 3.2. All the power

supplies and control function necessary for the safety functions of the system

are Class 1E, as described in Chapters 7.0 and 8.0.

SAFETY EVALUATION SIX - Section 10.4.8.2 describes provisions made to identify

and isolate leakage or malfunction and to isolate the steam generator water

inventory from the nonsafety-related portions of the system.

SAFETY EVALUATION SEVEN - Sections 6.2.4 and 6.2.6 provide the safety evaluation for the system containment isolation arrangement and testability for

the steam generator drain line penetration.

10.4.8.5 Tests and Inspections

The performance and structural and leaktight integrity of all system components is demonstrated by continuous operation.

The SGBS is testable through the full operational sequence that brings the system into operation for reactor shutdown and for DBAs, including operation of

applicable portions of the protection system and transfer between normal and

standby power.

10.4-45 Rev. 19 WOLF CREEK The safety-related components are located to permit preservice and inservice inspections.

10.4.8.6 Instrumentation Applications The SGBS instrumentation, as described in Table 10.4-11, is designed to

facilitate automatic operation, remote control, and continuous indication of

system parameters. As described in Chapter 7.0, certain devices are involved in the protection system.

The process radiation monitors provided downstream of the steam generator

blowdown flash tank and in the plant discharge line are discussed in Section

11.5. 10.4.9 AUXILIARY FEEDWATER SYSTEM

The auxiliary feedwater system (AFS) is a reliable source of water for the

steam generators. The AFS, in conjunction with safety valves in the main steam lines, is a safety-related system, the function of which is to remove thermal energy from the reactor coolant system by releasing secondary steam to the

atmosphere. The AFS also provides emergency water following a secondary side

line rupture. Removal of heat in this manner prevents the reactor coolant

pressure from increasing and causing release of reactor coolant through the pressurizer relief and/or safety valves.

The auxiliary feedwater system may also be used following a reactor shutdown in

conjunction with the condenser dump valves or atmospheric relief valves, to

cool the reactor coolant system.

10.4.9.1 Design Bases 10.4.9.1.1 Safety Design Bases

SAFETY DESIGN BASIS ONE - The AFS is protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external

missiles (GDC-2).

SAFETY DESIGN BASIS TWO - The AFS is designed to remain functional after an SSE or to perform its intended function following a postulated hazard, such as internal missile, or pipe break (GDC-4).

10.4-46 Rev. 19 WOLF CREEK SAFETY DESIGN BASIS THREE - The safety functions can be performed, assuming a single active component failure coincident with the loss of offsite power. The

system requirements may be met with a complete loss of ac power (GDC-34).

SAFETY DESIGN BASIS FOUR - The AFS is designed so that the active components are capable of being tested during plant operation. Provisions are made to

allow for inservice inspection of components at appropriate times specified in

the ASME Boiler and Pressure Vessel Code,Section XI.

SAFETY DESIGN BASIS FIVE - The AFS is designed and fabricated consistent with

the quality group classification assigned by Regulatory Guide 1.26 and the

seismic category assigned by Regulatory Guide 1.29. The power supply and

control functions are in accordance with Regulatory Guide 1.32.

SAFETY DESIGN BASIS SIX - The AFS, in conjunction with the condensate storage

tank (classified as special scope) or essential service water system, provides feedwater to maintain sufficient steam generator level to ensure heat removal from the reactor coolant system in order to achieve a safe shutdown following a main feedwater line break, a main steamline break, or an abnormal plant situation requiring shutdown. The auxiliary feedwater system is capable of

delivering full flow when required, after detection of any accident requiring auxiliary feedwater (refer to Chapter 15.0).

SAFETY DESIGN BASIS SEVEN - The capability to isolate components or piping is provided, if required, so that the AFS safety function is not compromised.

This includes isolation of components to deal with leakage or malfunctions and

to isolate portions of the system that may be directing flow to a broken

secondary side loop.

SAFETY DESIGN BASIS EIGHT - The AFS has the capacity to be operated locally as

an alternate, redundant means of feedwater control, in the unlikely event that

the control room must be evacuated.

10.4.9.1.2 Power Generation Design Bases

The AFS has no power generation design bases. The condensate and feedwater

system is designed to provide a continuous feedwater supply to the steam

generators during startup normal plant operation, and shutdown. Refer to Section 10.4.7.

10.4-47 Rev. 16 WOLF CREEK 10.4.9.2 System Description 10.4.9.2.1 General Description The system consists of two motor-driven pumps, one steam turbine-driven pump, and associate piping, valves, instruments, and controls, as shown on Figure

10.4-9 and described in Table 10.4-12. Figure 10.4-10 shows the piping and

instrumentation for the steam turbine.

Each motor-driven auxiliary feedwater pump will supply 100 percent of the

feedwater flow required for removal of decay heat from the reactor. The

turbine-driven pump is sized to supply up to twice the capacity of a motor-

driven pump. This capacity is sufficient to remove decay heat and to provide adequate feedwater for cooldown of the reactor coolant system at 50ºF/hr within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of a reactor trip from full power.

Normal flow is from the condensate storage tank (CST) to the auxiliary

feedwater pumps. Two redundant safety-related back-up sources of water from the essential service water system (ESWS) are provided for the pumps. For a more detailed description of the automatic sequence of events, refer to Section

10.4.9.2.3.

Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the

safety grade water source.

The condensate storage tank has sufficient capacity to allow the plant to remain at hot standby for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and then cool down the primary system at an average rate of 50°F per hour to a temperature of 350°F. Initially, sensible

and decay heat is removed from the reactor coolant system to reduce the

temperature from a full-power operation average temperature of 588°F to a

nominal hot standby temperature of 500°F. Subsequently, the reactor is brought down to 350°F at 50°F/hr. Refer to Section 9.2.6 for a description of the condensate storage system.

The non-safety auxiliary feedwater pump (NSAFP), installed in the Condensate

Storage and Transfer System (CSTS), functions to provide an alternate source of cooling water to the steam generators through the Auxiliary Feedwater system as shown in Figure 10.4-9. The NSAFP is powered from the Station Blackout Diesel Generators (SBO DGs) as described in section 8.3.1.1.1.3. The SBO DGs and NSAFP will be manually aligned as deemed necessary.

Hose connections are available for connection of a portable auxiliary feedwater pump in the event of an extended loss of all AC power. These connections

support implementation of beyond-design-basis external event Phase 2 coping

strategies to maintain or restore core cooling as described in Appendix 3D.

In order to remove decay heat by the steam generators, auxiliary feedwater must be supplied to the steam generators in the event that the normal source of feedwater is lost. The minimum required flow rate is 470 gpm for decay heat

removal during plant normal cooldown. The single active failure for Chapter 15

events that take credit for auxiliary feedwater flow for decay heat removal

assumes one of the two motor-driven auxiliary feedwater pumps is operable. The overall minimum auxiliary feedwater flow rate is 563 gpm to fulfill the acceptance criteria for the feedline break analysis in Section 15.2.8.

Provisions are incorporated in the AFS design to allow for periodic operation

to demonstrate performance and structural and leaktight integrity. Leak detection is provided by visual examination and in the floor drain system described in Section 9.3.3.

10.4-48 Rev. 30 WOLF CREEK 10.4.9.2.2 Component Description

Codes and standards applicable to the AFS are listed in Tables 3.2-1 and 10.4-

12. The AFS is designed and constructed in accordance with quality groups B and C and seismic Category I requirements.

MOTOR-DRIVEN PUMPS - Two auxiliary feedwater pumps are driven by ac-powered

electric motors supplied with power from independent Class 1E switchgear busses. Each horizontal centrifugal pump takes suction from the condensate storage tank, or alternatively, from the ESWS. Pump design capacity includes

continuous minimum flow recirculation, which is controlled by restriction

orifices.

TURBINE-DRIVEN PUMP - A turbine-driven pump provides system redundancy of auxiliary feedwater supply and diversity of motive pumping power. The pump is a

horizontal centrifugal unit. Pump bearings are cooled by the pumped fluid.

Pump design capacity includes continuous minimum flow recirculation. Power for

all controls, valve operators, and other support systems is independent of ac power sources.

Steam supply piping to the turbine driver is taken from two of the four main

steam lines between the containment penetrations and the main steam isolation

valves. Each of the steam supply lines to the turbine is equipped with a locked-open gate valve, normally closed air-operated globe valve with air-operated globe bypass to keep the line warm, and two nonreturn valves. Air-

operated globe valves are equipped with dc-powered solenoid valves. These

steam supply lines join to form a header which leads to the turbine through a

normally closed, dc motor-operated mechanical trip and throttle valve. The main steam system is described in Section 10.3.

The steam lines contain provisions to prevent the accumulation of condensate.

The turbine driver is designed to operate with steam inlet pressures ranging

from 92 to 1,290 psia. Exhaust steam from the turbine driver is vented to the atmosphere above the auxiliary boiler building roof. Refer to Safety Evaluation Two for a discussion of the design provisions for the exhaust line.

PIPING AND VALVES - All piping in the AFS is seamless carbon steel. Welded

joints are used throughout the system, except for flanged connections at the pumps.

The piping from the ESWS to the suction of each of the auxiliary feedwater

pumps is equipped with a motor-operated butterfly valve, an isolation valve, and a nonreturn valve. Each line from the condensate storage tank is equipped with a motor-operated gate

10.4-49 Rev. 11 WOLF CREEK valve and a nonreturn valve. Each motor-driven pump discharges through a nonreturn valve and a locked-open isolation valve to feed two steam generators

through individual sets of a locked open isolation valve, a normally open, motor-operated control valve, a check valve followed by a flow restriction orifice, and a locked-open globe valve. The turbine-driven pump discharges through a nonreturn valve, a locked-open gate valve to each of the four steam

generators through individual sets of a locked-open isolation valve, a normally

open air-operated control valve, followed by a nonreturn valve, a flow restriction orifice, and a locked-open globe valve.

The turbine-driven pump discharge control valves are positionable, air operated

valves. At each connection to the four main feedwater lines, the auxiliary

feedwater lines are equipped with check valves.

The system design precludes the occurrence of water hammer in the main

feedwater inlet to the steam generators. For a description of prevention of water hammer, refer to Section 10.4.7.2.1.

TANKS - Three standby water accumulator tanks are provided in the pump suction piping to the turbine-driven pump to ensure that there is adequate safety grade water volume to accomplish a swap over from the non-safety grade water source to the safety grade water source.

10.4.9.2.3 System Operation NORMAL PLANT OPERATION - The AFS is not required during normal power generation. The pumps are placed in standby, lined up with the condensate

storage tank, and are available if needed.

EMERGENCY OPERATION - In addition to remote manual-actuation capabilities, the AFS is aligned to be placed into service automatically in the event of an

emergency. See section 7.3.6.1.1 for a description of this operation.

The common water supply header from the condensate storage tank contains a locked-open, 12-inch, butterfly isolation valve. Correct valve position is

verified by periodic surveillance. In the case of a failure of the water

supply from the condensate storage tank, the normally closed, motor-operated

butterfly valves from the ESWS are automatically opened on low suction header pressure. Valve opening time and pump start time are coordinated to ensure adequate suction pressure with either onsite or offsite power available.

If a motor-driven pump supplying two of the three intact steam generators fails

to function, the turbine-driven pump automatically starts when a low-low level is reached in two of the four steam generators. During all of the above emergency conditions, the normally open control valves are remote manually

operated.

During all of the above emergency conditions, the motor-driven pump normally

open control valves are automatically operated to limit runout flow under all secondary side pressure conditions. This is required to prevent pump suction cavitation at high flow rates. The turbine-driven pump design includes a lower

NPSH requirement. Therefore, the turbine-driven pump control valves are remote

manually operated.

10.4-50 Rev. 25 WOLF CREEK Low pump discharge pressure alarms assists alerting in the operator to a secondary side break. The operator then determines which Steam Generator is

faulted, and closes the appropriate discharge control valves. For a postulated unisolable double-ended secondary system pipe rupture, refer to Chapter 15.0 for further information on the required operator actions and times assumed in

the applicable accident analysis.

10.4.9.3 Safety Evaluation

Safety evaluations are numbered to correspond to the safety design bases in

Section 10.4.9.1.1.

SAFETY EVALUATION ONE - The AFS is located in the auxiliary building, except for the Turbine Driven Auxiliary Feedwater Pump exhaust pipe and the section of pump recirculation piping mentioned in the note below. This building is

designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other appropriate natural phenomena. Sections

3.3, 3.4, 3.5, 3.7(B), and 3.8 provide the bases for the adequacy of the structural design of the auxiliary building. (See the discussion in Safety Evaluation Two, pertaining to the exhaust steam from the turbine driver during a SSE.)

NOTE: To avoid pump damage due to overheating while operating with no delivered flow, the Motor Driven Auxiliary Feedwater Pumps (MDAFWPs) and the Turbine Driven

Auxiliary Feedwater Pump (TDAFWP) require minimum flows of 75 gpm and 120 gpm

respectively. To satisfy this requirement, each pump has a recirculation line

that joins to common header ALO45DBC-3" and returns to the condensate storage tank (CST). The common recirculation line transitions from safety-related to non-safety related/non-seismic at the Auxiliary Feedwater System to CST pipe

chase, becoming line ALO46DBC-3". The CST pipe chase and the CST are not

seismically qualified.

If a hazard (i.e. tornadoes, floods, missiles, pipe breaks, fires, and seismic events) resulted in the non-safety related portion of the recirculation header

becoming crimped such that recirculation flow was restricted in conjunction

with an AFS actuation signal, the potential for pump damage could exist.

To eliminate that potential, an alternate flow path has been designed such that even in the event of a recirculation line obstruction, sufficient cooling flow

will be available.

The AFW system is designed to remain functional after a tornado missile impact.

As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the driver is routed from the auxiliary building wall through the auxiliary boiler building. The portion of the turbine driver exhaust stack that exits the auxiliary building has been analyzed and is not expected to crimp and inhibit the ability of the TDAFWP to deliver design flow rates. The impact from a credible missile will cause the exhaust line to sever by any of the postulated tornado missile scenarios thus not inhibiting the function of the exhaust line.

SAFETY EVALUATION TWO - The AFS is designed to remain functional after a SSE.

Sections 3.7(B).2 and 3.9(B) provide the design loading conditions that were

considered. Sections 3.5 and 3.6 provide the hazards analyses to ensure that a safe shutdown, as outlined in Section 7.4, can be achieved and maintained. For a more complete description of motor qualification, refer to Sections 3.10(B)

and 3.11(B).

10.4-51 Rev. 30 WOLF CREEK As shown on Figures 10.4-10 and 3.6-1, Sheet 49, the exhaust steam from the turbine driver is routed from the auxiliary building wall through the auxiliary boiler building, which is designed to UBC seismic requirements and is not expected to fail during a seismic event. If the auxiliary boiler building were to catastrophically fail and the exhaust line were sheared off completely, the AFP turbine would operate properly.

Even if the exhaust line were to crimp significantly, the AFP turbine driven pump would still deliver design flow rates. The back pressure on the turbine

may be increased significantly before the required flow rates are not

available. The TDAFWP is capable of delivering design flow even with a local

constriction of 50 percent of the free area of the exhaust line. This type of failure is not considered to be credible. However, the exhaust line and its support are re-classified as special scope, II/I, to assure they will not be

degraded and thus affect the operation of the Auxiliary Feedwater Pump Turbine.

Breaks in seismic Category I piping are not postulated during a seismic event.

Thus an MSLB or MFLB inside containment or in the steam tunnel are not postulated following a seismic event and the design of the exhaust line does

not enter into the evaluation of these breaks.

For a seismically induced MSLB in the turbine building, various single failures can be postulated, none of which result in adverse conditions even if the AFP turbine is inoperable. If an MSLIV fails to close, one steam generator blows

down; however, two motor driven AFW pumps are available to feed three intact

steam generators. If one motor driven pump train fails for any reason, the

other motor driven pump feeds two steam generators as required. In this case, the break has been isolated by the MSLIV, and all four steam generators are intact.

SAFETY EVALUATION THREE - Complete redundancy is provided and, as indicated by

Table 10.4-13, no single failure compromises the system's safety functions.

All vital power can be supplied from either onsite or offsite power systems, as described in Chapter 8.0.

The turbine-driven pump is energized by steam drawn from two main steam lines

between the containment penetrations and the main steam isolation valves. All valves and controls necessary for the function of the turbine-driven pump are energized by the Class 1E dc power supplies. Turbine bearing lube oil is

circulated by an integral shaft-driven pump. Turbine and pump bearing oil is

cooled by pumped auxiliary feedwater.

SAFETY EVALUATION FOUR - The AFS is initially tested with the program given in Chapter 14.0. Periodic operational testing is done in accordance with Section

10.4.9.4.

Section 6.6 provides the ASME Boiler and Pressure Vessel Code,Section XI

requirements that are appropriate for the AFS.

SAFETY EVALUATION FIVE - Section 3.2 delineates the quality group

classification and seismic category applicable to this system and supporting

systems. Table 10.4-12 shows that the components meet the design and

fabrication codes given in Section 3.2. All the power supplies and control functions necessary for safe function of the AFS are Class 1E, as described in Chapters 7.0 and 8.0.

10.4-52 Rev. 30 WOLF CREEK SAFETY EVALUATION SIX - The AFS provides a means of pumping sufficient feedwater to prevent damage to the reactor following a main feedwater line break inside the containment, or a main steamline break incident, as well as to cool down the reactor coolant system at a rate of 50 F per hour to a temperature of 350 F, at which point the residual heat removal system can operate. Pump capacities, as shown in Table 10.4-12, and start times are such that these objectives are met. Restriction orifices located in the pump discharge lines and automatic flow control valves for the motor-driven pumps

limit the flow to the broken loop so that adequate cooldown flow (470 gpm) can be provided to the other steam generators for removal of reactor decay heat and so that containment design pressure is not exceeded. Pump discharge head is

sufficient to establish the minimum necessary flowrate against a steam

generator pressure corresponding to the lowest pressure setpoint of the main

steam safety valves. The maximum time period required to start the electric motors and the steam turbine which drive the auxiliary feedwater pumps is chosen so that sufficient flowrates are established within the required time

for primary system protection. Refer to Chapter 15.0.

SAFETY EVALUATION SEVEN - As discussed in Sections 10.4.9.2 and 10.4.9.5 and Chapter 15.0, adequate instrumentation and control capability is provided to permit the plant operator to quickly identify and isolate the auxiliary

feedwater flow to a broken secondary side loop. Isolation from nonsafety-

related portions of the system, including the condensate storage tank, is

provided as described in Section 10.4.9.2.

SAFETY EVALUATION EIGHT - The AFS can be controlled from either the main

control room or the auxiliary shutdown panel. Refer to Section 7.4 for the

control description.

10.4.9.4 Tests and Inspections

Preoperational testing is described in Chapter 14.0. The performance and

structural and leaktight integrity of system components is demonstrated by

periodic operation.

The AFS is testable through the full operational sequence that brings the

system into operation for reactor shutdown and for DBA, including operation of

applicable portions of the protection system and the transfer between normal

and standby power sources.

The safety-related components, i.e., pumps, valves, piping, and turbine, are

designed and located to permit preservice and inservice inspection.

10.4.9.5 Instrumentation Applications

The AFS instrumentation is designed to facilitate automatic operation and

remote control of the system and to provide continuous indication of system

parameters.

Redundant condensate storage tank level indication and alarms are provided in the control room. The backup indication and alarms use auxiliary feedwater

pump suction pressure by converting it to available tank level. Both alarms

provide at least 20 minutes for operator action (e.g., refill the tank),

assuming that the largest capacity auxiliary feedwater pump is operating.

10.4-53 Rev. 30 WOLF CREEK Pressure transmitters are provided in the discharge and suction lines of the auxiliary feedwater pumps. Auxiliary feedwater flow to each steam generator is indicated by flow indicators provided in the control room. If the condensate supply from the storage tank fails, the resulting reduction of pressure at the pump suction is indicated in the control room.

Flow transmitters and control valves with remote control stations are provided on the auxiliary feedwater lines to each steam generator to indicate and allow control of flow at the auxiliary shutdown panel and in the control room. Flow

controllers for the motor-driven pump control valves position the valves to

limit the flow to a preset value throughout the full range of downstream operating pressures.

Position indication in the control room is provided on the ESFAS status panel

for the manual isolation valve in the auxiliary feedwater pump suction header

from the condensate storage tank.

A flow element and indicator is provided in each auxiliary feedwater pump

minimum recirculation line to facilitate periodic performance testing.

Table 10.4-14 summarizes AFS controls, alarms, indication of status, etc.

10.4.10 SECONDARY LIQUID WASTE SYSTEM

The function of the secondary liquid waste system (SLWS) is to process

condensate demineralizer regeneration wastes and potentially radioactive liquid waste collected in the turbine building. Processed liquid waste may be reused in the plant or discharged to the environment.

10.4.10.1 Design Bases 10.4.10.1.1 Safety Design Bases

The SLWS is not a safety-related system, and its failure does not compromise

any safety-related system or prevent a safe shutdown of the reactor.

10.4.10.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - During normal plant operation, the SLWS is

utilized to the extent required to meet chemical composition limits for release

to the environment or for recyle of processed fluids back to the condenser.

POWER GENERATION DESIGN BASIS TWO - The SLWS processes recyclable turbine

building waste during normal operation with the radioactivity levels identified

in Appendix 11.1A.

POWER GENERATION DESIGN BASIS THREE - During abnormal operation, the SLWS has provisions to receive from nonradioactive turbine building sumps liquids that may be radioactively contaminated. This condition could occur if, for example, condensation from the turbine building air coolers contained radioactive

contamination or if during maintenance a major component's normal drainage path

was not available.

10.4-54 Rev. 30 WOLF CREEK POWER GENERATION DESIGN BASIS FOUR - The SLWS processes condensate demineralizer regeneration waste products for recycle back to the condenser or discharge to the environment. The SLWS is designed to accept and process condensate demineralizer regeneration wastes resulting from the regeneration of one demineralizer vessel every 2 days.

POWER GENERATION DESIGN BASIS FIVE -

The SLWS includes cross-connections with the steam generator blowdown system to provide improved reliability by providing back-up demineralization capability.

10.4.10.2 System Description 10.4.10.2.1 General Description

The SLWS consists of several tanks and pumps, a demineralizer, a charcoal

adsorber, an oil interceptor, and three filters, as shown in Figure 10.4-12.

Turbine building wastes consist of wastes collected in turbine building floor

and equipment drains and condensate demineralizer regeneration wastes. The

turbine building drains are segregated into two categories. The first category

consists of drains which could include potentially radioactive turbine cycle leakage. The other category consists of nonradioactive sources.

The potentially radioactive turbine building drains are collected, as described

in Section 9.3.3, in specific sumps throughout the turbine building and sent to

the SLW drain collector tanks for processing. Drain processing is based on operator knowledge of secondary system chemistry and radioactive contamination, in conjunction with Technical Specification limitations and state and local

discharge permit restrictions. In all cases, the waste is processed through an

oil interceptor to remove oil which might be present in the sumps. In

addition, the waste may be processed by filtration, and/or demineralization.

The nonradioactive waste is normally discharged without processing (except for oil removal) through the oily waste system. However, provisions exist to

monitor the radioactivity of the nonradioactive waste and to divert it to be

processed if necessary. All discharges from the standard power block are

monitored for radioactivity levels, and the discharge is automatically terminated if the activity is above permissible levels or dilution flow rate is insufficient. The discharge from the SLWS oil interceptor pumps can be routed

to either the low or high total dissolved solids (TDS) collection tanks. The

routing of turbine effluents can be used to provide adequate dilution for pH

neutralization for discharge to the environment without using contaminated lines.

The condensate demineralizer regeneration waste is divided into two types --

high and low total dissolved solids (TDS).

High TDS waste results from the acid and caustic rinses used when chemically regenerating spent resins. Low TDS waste results from the initial backflushing of unregenerated resin and the final rinsing of the regenerated resin to remove

the acid and caustic. These high and low TDS wastes are collected separately in

two high and two low TDS collector tanks.

These input streams are retained within the appropriate collection tanks and then processed by various combinations of filtration, crud sedimentation, charcoal adsorption, and demineralization. The processed SLW liquids can then

10.4-55 Rev. 30 WOLF CREEK be collected in either or both of the two SLW monitor tanks, sampled and returned to the condenser, or discharged. The monitor tanks provide holdup and isolation in conjunction with sampling to ensure that the chemical and radioactivity limits for discharge or recycle are met.

The SLW drain collector tanks are sized based on 10,000 gpd of leakage in all areas of the turbine building. Since the SLWS normally receives only 7,200 gpd from these drains, the 15,000 gallon SLW drain collector tanks can each receive drainage for at least 2 days. This delay provides the surge capacity to facilitate repair, maintenance, or inspection that may be required on the process equipment or abnormal usage demands which may be made of the SLWS. The SLW drain collector tank pumps are cross-connected to take suction from either tank. A recirculation line from the pumps' discharge to either tank is provided to allow the tank contents to be mixed so that accurate sampling can be accomplished. The SLW drain collector tank contents are then processed and sent to the SLW monitor tanks. The SLW monitor tanks have the same design features, including two pumps, as the SLW drain collector tanks.

After being sampled in the SLW monitor tanks, the processed water is either

returned to the condenser or discharged. The distribution header connection

for the laundry water storage tank is for makeup to the recyclable laundry

system. This makeup is necessary to replenish the water lost in the laundry's dryer.

In addition, the floor drain system described in Section 9.3.3 provides leakage

detection capabilities to assure that any abnormal leakage is detected and

repaired.

10.4.10.2.2 Component Description

Codes and standards applicable to the SLWS are listed in Table 3.2-1. Major

components are described in Table 10.4-15.

10.4.10.2.3 System Operation

Turbine Building Recyclable Drains

The turbine building recyclable drains are collected in drain sumps throughout the turbine building. These sumps are normally

aligned to discharge, via the sump pumps, to the secondary liquid waste (SLW)

oil interceptor. After passing through the oil interceptor, the de-oiled water

is pumped, via the SLW oil interceptor transfer pumps, to the SLW drain collector tanks. Two drain collector tanks are provided so that one is available for accepting wastes while the other is being sampled or processed.

Prior to processing the SLW drain collector tank contents, a sample is taken to

determine the optimum means of processing. The options available are:

a. Filtration
b. Charcoal adsorption
c. Demineralization

10.4-56 Rev. 30 WOLF CREEK or any combination of these options. Two SLW drain collector tank pumps are available to pump the drain fluids to the radwaste building for processing.

The operator selects the appropriate tank/pump combination, starts the pump, and, when ready, opens an air-operated valve located at the discharge of the drain collector tank pumps. The drain fluid is first passed through a wye strainer to remove all gross particulates, then it is passed through a cartridge filter to remove particulates in the 30-micron range. This scheme (strainer/filter) maximizes filter cartridge life. A bypass is provided around the strainer and/or filter combination. The wye strainer is provided with a local blow-off connection for ease of cleaning.

Processed water from the liquid Waste Process Skid is typically directed to the Secondary Liquid Waste (SLW) Monitor Tanks. The SLW charcoal absorber and SLW demineralizers are optional for removing trace organics and dissolved solids.

These components are typically bypassed. The charcoal absorber and the

demineralizer have wye strainers at their discharge to remove charcoal and

resin fines. The blowdown ports of these wye strainers are directed to the secondary spent resin storage tank to minimize waste handling.

Secondary Liquid Waste Monitoring and Discharge

The processed water, is sampled and monitored while being recirculated in the SLW monitor tanks. Two monitor tanks are provided so that one is available for accepting water while the other is being sampled and discharged. The water in

the monitor tanks is sampled to assure that the proper chemistry exists for

discharge to the environment at the operator's option.

If the operator decides to discharge to the environment, a radiation monitor is provided to isolate the discharge line on high radiation. In addition, the

discharge line is also isolated by a low dilution flow signal.

If, for any reason, the SLW monitor tank water does not meet the necessary chemical requirements for discharge or recycle, the water may be reprocessed through liquid radwaste demineralizer skid.

10.4-57 Rev. 30 WOLF CREEK Condensate Demineralizer Regenerant Wastes

The condensate demineralizer system and the regeneration process are described in Section 10.4.6.

High Total Dissolved Solids (TDS) Wastes

High TDS wastes are wastes that result from the acid and caustic rinses used to regenerate condensate demineralizer resins. These wastes (though high in dissolved solids) are generally low in crud content. These wastes flow by

gravity from the demineralizer regeneration system to the high TDS transfer

tank located in the condenser pit of the turbine building. These waste fluids

are then pumped by either or both of the high TDS transfer tank pumps to the high TDS collector tanks.

Two high TDS collector tanks are provided to accept the wastes. Mixers are provided on the high TDS collector tanks to effectively mix the tank contents

to obtain an accurate sample. After sampling the tank contents, the operator adds any necessary chemicals to adjust the pH. The chemical storage tanks and metering pumps are provided as part of the condensate demineralizer

regeneration system. This step is normally not required as the condensate

demineralizer regeneration system should control the outlet fluids to an

acceptable pH range for processing in the SLW equipment. After pH adjustment, the mixers continue to operate to again ensure even distribution of tank contents. The operator next chooses the proper tank and pump combination (using the high TDS collector tank pumps) and starts the pump to prepare for

discharge to either the liquid radwaste system or the wastewater treatment system. If the operator chooses to discharge to the wastewater treatment system, the tank contents shall be sampled to ensure the wastes have a pH greater than 2 and lessthan 12.5; thus ensuring that they are not classified as hazardous wastes. The operator must manually isolate the path to the radwaste

building prior to aligning the pumps and tanks for discharge. The wastewater treatment system radioactivity monitor 1-HF-RE-95, monitors both the high and low TDS wastewaters prior to discharge to the wastewater treatment facility/system. The monitor monitors the wastewater treatment system influent

discharge line upstream of the isolation valve. The high radioactivity alarm

shall close the isolation valve to prevent the discharge of radioactive fluid

to the wastewater treatment system. If the high TDS wastes were to become radioactive they shall be processed through the radwaste building.

Low Total Dissolved Solids (TDS) Wastes

Low TDS wastes are wastes that result from the resin washing, flushing, and sluicing operations that are a part of the condensate demineralizer regeneration process. These wastes (though low in dissolved solids) are

relatively high in crud content. These wastes flow by gravity from the

demineralizer regeneration system to the low TDS transfer tank in the condenser

pit of the turbine building. These waste fluids are then pumped by either or

both low TDS transfer tank pumps to the two low TDS collector tanks. These tanks are designed to promote settling of crud and are provided with a nozzle to drain off the settled crud.

10.4-58 Rev. 19 WOLF CREEK Two low TDS collector tank pumps are provided for pumping the waste to processing equipment. If insufficient time has been allowed for clarification

of the waste, the low TDS collector tanks can be processed through a local bag filter and returned to the collector tanks. When the operator is ready to process the low TDS collector tanks, he selects the proper tank/pump combination, starts the pump, and, when ready to initiate processing, opens an

air-operated valve located at the discharge of the low TDS collector tank

pumps. The waste then flows to the radwaste building where it passes through a wye

strainer and one of two low TDS filters. This strainer/filter combination

extends filter cartridge life by removing all large particulates prior to the

filters. The waste next flows to the SLW demineralizer, and processing is completed as described previously.

If the SLW demineralizer is not available and the plant can be operated at one-half the maximum steam generator blowdown rate, the option exists to process

the low TDS wastes via two of the steam generator blowdown demineralizers.

If the operator chooses to discharge the low TDS wastes through the wastewater

treatment system, the operator must isolate the flowpath to the radwaste

building. The contents of the low TDS waste collector tank shall be sampled to

ensure that the pH is between 2 and 12.5. The operator then chooses the proper tank and pump combination, starts the pump and begins discharge to the wastewater treatment system. The discharge line to the wastewater treatment

facility is monitored by radioactivity monitor 1-HF-RE-95. The high

radioactivity monitor shall close the isolation valve downstream of the monitor

on a high radioactivity alarm to prevent discharge to the wastewater treatment facility.

Abnormal Operation

If abnormally large amounts of nonradioactively contaminated drainage collect in the turbine building recyclable sumps, such as a fire deluge, then the SLW system can be bypassed completely and the water discharged via the oily waste

discharge pipe.

System Releases Liquid effluents from the SLWS may be recycled to the secondary system via the

condenser or may be discharged to the environment.

Prior to discharge to the environment, the effluent is isolated within the appropriate monitor tank. The tank contents are recirculated to assure that they are well mixed and then sampled to assure that the release would not

exceed release limits. The discharge to the environment passes through a

process radiation monitor, which automatically closes the discharge valve on

high radioactivity. The method of processing secondary liquid wastes and

whether to recycle or discharge the processed wastes depend on the radioactivity concentrations. The radioactivity content of the SLWS releases is limited, along with radioactivity in other liquid releases, so as not to

exceed Offsite Dose Calculation Manual.

The radioactivity releases provided in Section 11.1 and Appendix 11.1.A are based on the analytical models of the GALE code and do not reflect the normal variations in the concentrations of radioactive isotopes in the secondary

system which depend on the status of the fuel, primary-to-secondary leakage, operation of the steam generator blowdown system, and extent of removal of radioisotopes from secondary steam to the MSR and high pressure heater drains (which are recycled directly to the steam generators). 10.4-59 Rev. 10 WOLF CREEK It is estimated that the annual liquid volume released from the SLWS will be approximately 2,100,000 gallons (7,200 gallons per day with an 80-percent plant

capacity factor). As described above, the releases would be on a batch basis from the SLW monitor tank. The discharge rate is 90 gpm (80 minutes per day) and the temperature less than 135 F. 10.4.10.3 Safety Evaluation The secondary liquid waste system is not a safety-related system.

10.4.10.4 Tests and Inspections Preoperational testing is performed as described in Chapter 14.0.

Continuous operation demonstrates the operability, performance, and structural and leaktight integrity of all system components.

10.4.10.5 Instrumentation Applications The SLWS instrumentation is designed to facilitate automatic operation, remote

control, and continuous indication of system parameters, as described in

10.4.10.2.3.

10.4-60 Rev. 14 WOLF CREEK TABLE 10.4-1CONDENSER DESIGN DATA (Note 1)

ItemType Multipressure, 3-shell Design duty, Btu/hr-total 3 7.8696 x 10 9 shellsShell pressure w/80°F circ. 2.34/2.89/3.64 water, inches HgaWaterbox circulating flow, gpm 500,000 (Site A/E design value)

Tubeside temperature rise, °F 31.5 Design pressure-shell Full vacuum to 15 psig

Hotwell storage capacity - 159,000 total 3 shells, gallonsDesign pressure-channel, psig 70 and full vacuum

Number of tubes 59,796

Tube material Main bundle 304 S.S.

Air cooler 304 S.S.

Impingement area 304 S.S.

Surface area, sq. ft. 900,000 Overall Shell dimensions, feetLPIPHP Length 292929 Width 394551 Height 787878 Number of tube passes 1

Steam flow, 1b/hr Normal 7,940,886 Maximum 8,270,751 Circulating Water Temp, °F Design 80

Maximum 90 Steam temperature, °F Normal (avg.) 114

Maximum (without turbine bypass) 134

Maximum (with turbine bypass) 141 Rev. 13 WOLF CREEK TABLE 10.4-1 (Sheet 2)

Applicable codes and standards: ASME Sect. VIII, Div. 1, ANSI Standards, HEI Standards for Steam Sur-face CondensersEffluent oxygen content, ppb 7 Notes:1.The data in this table reflects the original engineering specification for the condenser. The data may not reflect actual operating values. Rev. 13 WOLF CREEK TABLE 10.4-2 MAIN CONDENSER AIR REMOVAL SYSTEM DESIGN DATA Component Description Condenser Mechanical Vacuum Pumps Quantity 3 Type Rotary water ring

Holding capacity 35 SCFM @ 1" Hga

Hogging capacity 72 SCFM @ 5" Hga

Speed 435 rpm Cooling water flow 630 gpm Motor Data Horsepower 150 Speed 1,800 rpm

Electrical requirements 460 Volt, 60 Hz, 3 Seal Water Coolers Quantity 3 Type Straight tube

Heat exchanged 14,600 Btu/hr Shell Side Tube Side Fluid Seal water Service water Total fluid entering 90 gpm 630 gpm Design pressure, psig 150 250

Design temperature, F 300 300

Test pressure, psig 225 375 Piping and Valves Material Carbon steel Design temperature, F 175

Design pressure, psig 225 Charcoal bed adsorber and filters are described in Section 9.4.4.

Rev. 5 WOLF CREEK TABLE 10.4-3 CIRCULATING WATER SYSTEM COMPONENT DESCRIPTION Circulating Water Pumps Quantity 3 Type Vertical, wet-pit Capacity, each (gpm) 166,700

Total developed head at normal operating level, approx (ft) 74Circulating Water Piping (Power Block, above floor) MaterialCarbon steel Outside diameter, in.120 Type of interface connectionFlanged Code (pipe)AWWA-C201 Code (flange)AWWA-C207, Class D Design pressure, psig70 at water boxes Site interfaceNone Circulating Water Piping (Power Block, below floor)MaterialCast-in-place concreteInside dimension, in.120 inches square Type of interfaceconnectionFlangedCode (pipe)ACICode (flange)AWWA-C207, Class DDesign pressure, psig85 at El. 1,970Site interfaceWelded joint Circulating Water Expansion Joints Type Rubber Design pressure, psig 70 Design temperature, °F 125 Circulating Water Valves

Type Butterfly Operator Electric motor Design pressure, psig 70

Design temperature, °F 125

Code AWWA Rev. 13 WOLF CREEK TABLE 10.4-3 (Sheet 2)

Water Box Venting Pumps Quantity 3 Type Rotary Capacity, acfm (each pump) 775 Suction pressure, inches Hg. abs 5Motor Horsepower50 Speed, rpm690 Design codeMS Water Box Venting Tank Quantity 1 Capacity, gal 700 Design pressure, min/max psig Full vacuum/15

Design temperature, °F 150 Design code ASME Section VIIIVenting System Seal Tank Quantity 1 Capacity, gal 53 Design pressure, psig 15

Design temperature, °F 150 Design code ASME Section VIII Condenser Drain Pump

Quantity 1 Type Centrifugal Capacity, gpm 900 Total head, feet 88 Motor horsepower 30

Design code MS Cooling Lake

Type Man-made Normal operating level

(ft, MSL) 1,087

Capacity (acre-ft) 111,280 Nominal surface area (acres)

at normal operating level 5,090 Rev. 13 WOLF CREEK TABLE 10.4-4 CONDENSATE DEMINERALIZER SYSTEM DESIGN DATA Demineralizer Vessels Quantity 6 Design pressure, psig 700 Design temperature, °F 140 Design flow per vessel, gpm 4,560 Diameter (I.D.) 10'-6" Type Spherical-rubber lined Regeneration Equipment

Cation regeneration tank

Quantity 1 Design pressure, psig 75

Design temperature, °F 140

Diameter 7'-6" Height 13'-6" Type Vertical cylindrical-

rubber lined Anion regeneration tank Quantity 1 Design pressure, psig 75

Design temperature, °F 140

Diameter 6'-6" Height 11'-0" Type Vertical cylindrical-

rubber lined Resin mixing and storage tank

Quantity 1 Design pressure, psig 75

Design temperature, °F 140

Diameter 7'-6" Height 10'-6" Type Vertical cylindrical-

rubber lined Rev. 12 WOLF CREEK TABLE 10.4-4 (Sheet 2)

Acid day tank Quantity 1 Design pressure Atm. Design temperature,°F 100

Diameter 3'-6" Height 6'-0" Type Vertical cylindrical- lined - High Bake Phenolic Caustic day tank Quantity 1 Design pressure Atm.

Design temperature, °F 100 Diameter 4'-0" Height 4'-6" Type Vertical cylindrical-

unlined Sluice water pump

Quantity 2 (one standby)

Type Centrifugal-inline Capacity, gpm 320

Head, ft 127 Acid metering pump

Quantity 2 (one standby)

Type Positive displacement Capacity, gph 210

Differential pressure, psi 65 Caustic metering pump

Quantity 2 (one standby) Type Positive displacment Capacity, gph 280 Differential pressure, psi 65 Waste collection tank

Quantity 1 Design pressure Atm.

Design temperature,°F 140

Diameter 3'-6" Height 5'-0" Special feature Mounted in strainer Rev. 10 WOLF CREEK TABLE 10.4-4 (Sheet 3)

Resin addition hopper Quantity 1 Diameter 2'-0" Height 2'-0" Capacity, ft3 7 Design pressure Atm.

Design temperature Amb.

Special feature Filling by eductor Rev. 0 WOLF CREEK TABLE 10.4-5 CONDENSATE AND FEEDWATER SYSTEM COMPONENT FAILURE ANALYSIS Component Failure Effect On Train Failure Effect on System Failure Effect on RCS Condensate pump None. Condenser hotwells Operation continues at full None are interconnected. capacity, using parallel

pumps (condensate pump runout capacity is 50 percent).

No. 1, 2, 3, One train of No. 1, 2, 3, Operation continues at reduced None. No. 5 feedwater heater or 4 feedwater and 4 feedwater heaters capacity, using parallel is designed to maintain heater is shut down. Remaining feedwater heaters. Load normal outlet feedwater

trains continue to operate. must not exceed that which temperature under this con-is required to protect the dition.

Turbines from excessive

exhaust flow.

Heater drain Extraction steam to both Operation continues at re- Reactor control system

tank No. 5 feedwater heaters duced capacity. reduces reactor power to must be isolated. Drains compensate for reduced feed-from Nos. 6 and 7 feed- water temperature.

water heaters are dumped to condenser.

Heater drain None. Parallel pump with 50 percent of HP feedwater Reactor control system pump condensate pumps have suf- heater drains are dumped reduces reactor power to ficient capacity to handle to condenser. compensate for reduced feed-

full load. water temperature.

Steam generator None. Two parallel trains Operations may continue at Reactor control system feedwater pump are interconnected. reduced capacity, using par- reduces reactor power to allel pump if the reactor compensate for reduced feed-does not trip. Steam gener- water flow.

ator feedwater pump runout capacity is 67 percent. No. 5, 6, or 7 One train is shut down. Operation continues at reduced Reactor control system feedwater heater capacity, using parallel reduces reactor and generator feedwater heaters. Load must output power to compensate not exceed that which is for reduced feedwater required to protect the temperature. Turbines from excessive exhaust flow. Rev. 11 WOLF CREEK TABLE 10.4-6 CONDENSATE AND FEEDWATER SYSTEM DESIGN DATA Main Feedwater Piping (Safety-Related Portion)

Power Rerate Flowrate, lb/hr 16,082,021 Design (VWO) flowrate, lb/hr 15,850,801 Number of lines 4 Nominal size, in. 14 Schedule 80 Design pressure, psig 1,185 Design temperature, F 450 Design code ASME Section III, Class 2 Seismic design Category I

Feedwater Isolation Valves Number per main feedwater line 1 Closing time, sec 5 (at normal operating conditions prior to receiving isolation signal) Body design pressure, psig 1,950 Design temperature, F 450 Design code ASME Section III, Class 2 Seismic design Category I Feedwater Control Valves

Number per main feedwater line 1 Closing time, sec 5 Design code ASME Section III, Class 3 Seismic design None

Rev. 24 WOLF CREEK TABLE 10.4-7 FEEDWATER ISOLATION SINGLE FAILURE ANALYSIS Component Failure Comments Main feedwater Valve fails to close upon receipt MFIV will close, providing control valve of automatic signal (FIS) adequate isolation to limit (MFCV) (1) high energy fluid addition Loss of power from one power Valve fails closed upon loss supply of either train of power Main feedwater Same as main feedwater control Same as main feedwater control bypass control valve valve valve. MFBCV (1)

Main feedwater Valve fails to close upon receipt MF control valve and MF check isolation valve of automatic signal (FIS) valve close as required to (MFIV) isolate The MF control valve (and bypass control valve) serve to limit the addition of high energy fluid into the containment following a main feedwater line rupture inside the containment or a main steam line break Loss of power from one power Valve fails closed upon loss of supply either train of power Main feedwater Valve fails to close MFIV will close, providing check valve adequate isolation (1) Valve is only required following pipe rupture of feedwater line inside containment or following a MSLB.

Rev. 0 WOLF CREEK TABLE 10.4-7 (Sheet 2)

Component Failure Comments Chemical addition Valve fails to close upon receipt Associated check valve will isolation valve of automatic signal (FIS) close, providing adequate isolation Loss of power for valve operation Valve fails closed Chemical addition Valve fails to close Chemical addition isolation check valve valve will close, providing adequate isolation Auxiliary feedwater Valve fails to open properly Remaining two intact steam check valve generators will provide adequate auxiliary feedwater Steam generator No signal generated for protection 2-out-of 4 logic reverts to narrow range level logic from one transmitter 2-out-of 3 logic, and protection (Four per steam logic is generated by other generator) channel devices Loss of one of four logic 2-out-of 4 logic reverts to channels 2-out-of 3 logic, and protection logic is gen-

erated by other channel devices Rev. 0 WOLF CREEK TABLE 10.4-8 MAIN FEEDWATER SYSTEM CONTROL, INDICATING, AND ALARM DEVICES Control Room Control Room Device Indication/Control Local Alarm___

Flow rate (1) Yes No Yes (1)Steam gener-ator level (narrow range)(2) Yes No Yes Steam gener-ator level (wide range) Yes No No Feedpump Speed Yes No Yes (1) Steam flow - Feedwater flow mismatch

(2) Four per steam generator - Involved in 2-out-of-4 logic to generate input to reactor trip, auxiliary feed pump start, turbine trip, and feedwater isolation signals.

Rev. 0 WOLF CREEK TABLE 10.4-9 STEAM GENERATOR BLOWDOWN SYSTEM MAJOR COMPONENT PARAMETERS Steam Generator Blowdown Discharge Pump Type Inline centrifugal Number 2

Design temperature, F 200 Design pressure, psig 150 Process fluid Blowdown

Design flow, gpm 270 Discharge head, ft 290 Code Manufacturer's standard

Material Stainless steel Steam Generator Blowdown Regenerative Heat Exchanger

Type Two stacked, BFU, two pass shell/two pass U-tube

Installation Horizontal Number 1 Eff. heat transfer area, ft 2 1,090 Fluid Tube Blowdown fluid Shell Condensate fluid

Design flow Tube, lb/hr 140,000 Shell, lb/hr 200,000

Design temperature, F Shell side 400 Tube side 600

Design pressure, psig Shell side 700 Tube side 300

Design codes TEMA R and ASME Section VIII Div I Materials

Tube Stainless steel Tubesheet Stainless steel Shell Carbon steel

Channel Carbon steel Rev. 0 WOLF CREEK TABLE 10.4-9 (Sheet 2)

Steam Generator Blowdown Surge Tank Type Vertical cylindrical Number 1 Capacity, gallons 2,065 Tank diameter, in. 78 Design pressure, psig 0.5 Design temperature, F 175 Material Carbon steel Code ASME Section VIII, Div. I Steam Generator Blowdown Mixed-Bed Demineralizer Type Flushable Number 4 Design temperature, F 200 Design pressure, psig 300 Design pressure drop (fouled condition), psi 20 @ 200 gpm Shell diameter, in. 60 Design flow, gpm 150 Decontamination factors Cation (a) 100 Anion 100 Cs, Rb 2 Resin volume, ft 3 75 Material Stainless steel Code ASME Section VIII, Div. I (a) Does not include Cs, Mo, Y, Rb, Te Steam Generator Blowdown Filter (FBM03A & 03B)

  • Type Disposable cartridge Number 2 Design pressure, psig 300 Design temperature, F 250 Design flow, gpm 250 Pressure drop (250 gpm, clean), psi 5 Pressure drop (fouled condition), psi 20 Particle retention 98% (min) of 30 micron size (max)*

Material (vessel) Stainless steel Code ASME Section VIII, Div. I

  • Standard filter cartridges are available with variable particle retention characteristics, and the selection of the filter cartridge is based on operating data.

Rev. 18 WOLF CREEK TABLE 10.4-9 (Sheet 3)

Steam Generator Drain Pump Type Inline centrifugal Number 2

Rated flow, gpm 100 Rated total dynamic head, ft 372 Design pressure, psig 150

Design temperature, F 150 Design code Manufacturer's standard Material Stainless steel Steam Generator Blowdown Nonregenerative Heat Exchanger Type BFU two pass shell 4 pass-tube Installation Horizontal

Number 1 Eff. heat transfer area, ft 2 682.5 Flow, continuous max., gpm 270 Fluid Shell side Service water Tube side Blowdown fluid

Design temperature, F Shell side 150 Tube side 600

Design pressure, psig Shell side 200 Tube side 300

Design code ASME Section VIII Div. I, TEMA-R Materials

Tube Stainless steel Shell Carbon steel Tubesheet Stainless Steel

Channel Carbon steel Steam Generator Blowdown Flash Tank

Type Vertical Number 1

Volume, gallons 2,350 Vessel diameter, in. 72 Design temperature, F 425

Design pressure, psig 300 Material Stainless steel Code ASME Section VIII, Div. I

  • If greater than 5% of the tubes have been plugged heat transfer value will be less than this value. . Rev. 18 WOLF CREEK TABLE 10.4-10 STEAM GENERATOR BLOWDOWN SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component Failure Comments Blowdown isolation Loss of power from Redundant power valves one power supply supply provided Valve fails to close Closure of three upon receipt of auto- out of four isolation matic signal (SLIS) valves adequate to

meet safety re-quirements (Refer to Section 10.4.8.2.2)

Sample isolation Loss of power from Valves fail closed valves one power supply upon loss of power Valve fails to close Closure of three out upon receipt of auto- of four isolation matic signal valves adequate to meet safety re-

quirements Rev. 0 WOLF CREEK TABLE 10.4-11 STEAM GENERATOR BLOWDOWN SYSTEM CONTROL, INDICATING AND ALARM DEVICES

Radwaste Building Control Main Control Main Room Room Control Room

Device Control/Indication Indication Alarm___

Blowdown flash

tank level X X (1)

Blowdown flash

tank pressure X Surge tank level X X (1)

Blowdown flow X X

Blowdown liquid high temperature X X (1)

Blowdown liquid radiation monitor X (alarm) X X

Surge tank discharge radiation monitor X (alarm) X X

Blowdown conductivity monitor X X (1)

(1) Common alarm window on main control board.

X denotes that indicating device is provided.

Rev. 19 WOLF CREEK TABLE 10.4-12 AUXILIARY FEEDWATER SYSTEM COMPONENT DATA Motor-Driven Auxiliary Feedwater Pump (per pump)

Quantity 2

Type Horizontal centrifugal, multistage, split case with packing Capacity, gpm (each) 575

TDH, ft 3,200 NPSH required, ft 17 NPSH available, ft (min) 28

Material

Case Alloy steel Impellers Stainless steel Shaft Stainless steel

Design code ASME Section III, Class 3 Seismic design Category I

Driver Type Electric motor

Horsepower, hp 800 Rpm 3,600 Power supply 4, 160 V, 60 Hz, 3-phase

Class 1E Design code NEMA Seismic design Category I Turbine-Driven Auxiliary Feedwater Pump

Quantity 1 Type Horizontal centrifugal, multistage, split case with packing

Capacity, gpm 1,145 TDH, ft 3,450 NPSH required, ft 17

NPSH available ft (min) 27

Material

Case Alloy steel Impellers Stainless steel

Shaft Stainless steel

Rev. 13 WOLF CREEK TABLE 10.4-12 (Sheet 2)

Design code ASME Section III, Class 3 Driver

Type Noncondensing, single stage, mechanical-drive steam turbine Rpm 3,850

Horsepower, hp 1,590 Design code NEMA Seismic design Category I

Motor-Driven Pump Control Valves

Quantity 4 (2 per pump)

Type Motor-operated globe valve Size, in. 4

CV 50 Design pressure, psig 1,800 Design temperature, F 150

Material Carbon steel Design Code ASME Section III Seismic Design Category I

Turbine-Driven Pump Control Valves

Quantity 4 Type Air-operated globe valve Size, in. 4

CV 50 Design pressure, psig 2,000 Design temperature, F 150

Material Carbon steel Design Code ASME Section III Seismic Design Category I

Turbine Driven Auxiliary Feedwater Pump Standby Water Accumulator Tanks

Quantity 3 Type Cylindrical with dished heads Capacity 300 gallons Manufacturer Joseph Oat Corporation Seismic Category 1 Weight 2500 lbs. Design Code ASME Section III, Class 3

Rev. 26 WOLF CREEK

TABLE 10.4-13 AUXILIARY FEEDWATER SYSTEM SINGLE ACTIVE FAILURE ANALYSIS Component Failure Comments Suction isolation In the event that the CST is un- Redundant nonreturn check valves from CST available, valve fails to close valve is provided, and suffi-

upon receipt of automatic isola- cient ESW flow is provided to

tion signal or loss of power the auxiliary feedwater pumps.

Suction isola- In the event that the CST is un- Two 100-percent redundant

tion valves from available, valve fails to open upon backup ESW trains are pro-

ESW receipt of automatic signal or loss vided. Operation of one train

of power of the suction valves meet

the requirements.

Suction header Loss of one transmitter. No pro- 2-out-of-3 logic reverts to

pressure trans- tection logic generated 1-out-of-2 logic, and protec-mitters tion logic is generated by other devices.

Motor-driven auxi- Fails to start on automatic signal Two motor-driven pumps are

liary feedwater provided. One pump is suf-

pump ficient to meet decay heat

removal requirements. If

due to a main steam or feed-

water line break, the oper-

ating motor-driven pump can-

not supply two intact steam

generators, the turbine-driven

pump will supply feedwater to meet decay heat removal requirements.

Turbine-driven Fails to open on automatic signal Parallel connections are pro-

pump steam supply vided on two main steam lines.

valve from main One of the two valves will

steam header supply 100 percent of the

turbine steam requirements.

Rev. 25 WOLF CREEK

TABLE 10.4-13 (Sheet 2)

Component Failure Comments

Turbine-driven Failure resulting in loss of func- Two motor-driven pumps are pump tion provided. Either will pro-vide 100 percent of the feed-water requirements for decay heat removal during plant normal cooldown.

Motor-driven pump Failure resulting in loss of flow The second motor-driven pump

control valve or loss of flow control will provide 100 percent of

the required flow through

separate control valves.

If due to a main steam or

feedwater line break, the

operational motor-driven pump

train cannot supply two intact steam generators, the turbine-

driven pump will supply feedwater to meet decay heat removal requirements.

Failure to close valve in line feed- Second motor-driven

ing broken loop pump will provide 100 percent

required flow through separate

control valves.

Turbine-driven Failure resulting in loss of flow Either of the two motor-driven

pump control valve or loss of flow control pumps will supply 100 percent

of the required feedwater flow through separate control valves.

Failure to close valve inline feed- Either of the two motor-

ing broken loop driven pumps will supply 100

percent required flow through

separate control valves.

Rev. 11 WOLF CREEK

TABLE 10.4-13 (Sheet 3)

Non-return check Fails to close Redundant non-return check valve (ALV0161) and air valve ALV0001 release vacuum breaker check valve (ALV0167) are provided. ALV0161 is considered passive for a "loss of offsite power with a concurrent loss of the CST" event because the valve is normally closed by gravity and is not required to have discernable mechanical motion. AV0167 is considered active for this event and passive for all other events.

The design of the valve requires water flow to raise the float to stop the flow. The float is normally in the neutral position so air can flow in response to system conditions. The valve is mounted above the overflow of the CST. Water will be below the valve inlet. The float is considered passive for all other events.

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&..&-(+1&0(&-34.&%&-5%&&*+0%'+&,5+,5&%',6)+&%34)+%&-5%*6*-%35.1)08%

+)+-6*144)6

&26-5%*-%(3

,%*4+-%4.*-1)(-%14-1'%.75+,5&%',66*-%3 13+&,.&2&,)%%<

WOLF CREEK TABLE 10.4-13B DESIGN COMPARISONS TO NRC RECOMMENDATIONS ON AUXILIARY FEEDWATER SYSTEMS CONTAINED IN THE MARCH 10, 1980 NRC LETTER A. SHORT-TERM RECOMMENDATIONS WCGS POSITION

1. Recommendation GS The licensee should The limiting conditions for operation re-propose modifications to the Technical lated to the auxiliary feedwater system are Specifications to limit the time that one addressed in the Technical Specifications.

auxiliary feedwater system pump and its associated flow train and essential instrumentation can be inoperable. The outage time limit and subsequent action time should be as required in current Technical Specifications; i.e., 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, respectively.

2. Recommendation GS The licensee should This item is not applicable to WCGS because lock open single valves or multiple valves the design does not include single valves or in series in the auxiliary feedwater system multiple valves in series that could interrupt pump suction piping and lock open other auxiliary feedwater pump suction or all single valves or multiple valves in series auxiliary feedwater flow.

that could interrupt all auxiliary feedwater

system flow. Monthly inspections should be performed to verify that these valves are locked and in the open position. These

inspections should be proposed for incorporation into the surveillance requirements of the plant Technical

Specifications. See Recommendation GL-2 for the longer-term resolution of this concern.

3. Recommendation GS The licensee has Throttling auxiliary feedwater flow to avoid stated that it throttles auxiliary feed- water hammer is not utilized. The system water flow to avoid water hammer. The design precludes the occurrence of water hammer licensee should reexamine the practice in the steam generator inlet, as described in of throttling auxiliary feedwater Section 10.4.7.2.1.

Rev. 10 WOLF CREEK TABLE 10.4-13B (Sheet 2)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

3. system flow to avoid water hammer.

The licensee should verify that the auxiliary feedwater system will

supply on demand sufficient initial flow to the necessary steam genera-tors to assure adequate decay heat

removal following loss of main feedwater flow and a reactor trip from 100 percent power. In cases

where this reevaluation results in an increase in initial auxiliary feedwater system flow, the licensee

should provide sufficient informa-tion to demonstrate that the required initial auxiliary feed-

water system flow will not result in plant damage due to water hammer.

4. Recommendation GS Emergency The WCGS design includes an automatic procedures for transferring to transfer to the alternate sources of alternate sources of auxiliary supply. Procedures provide guidance feedwater system supply should be to the operator concerning alternate available to the plant operators. water sources.

These procedures should include

criteria to inform the operator The normal supply from the condensate when, and in what order, the storage tank (CST) is through a locked-transfer to alternate water sources open, butterfly valve. Periodic sur-

should take place. The following veillance verifies valve position.

cases should be covered by the procedures:

Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 3)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

(1) The case in which the primary water Opening of valves from the backup ESWS supply is not initially available. and starting of auxiliary feedwater pumps The procedures for this case should are timed such that an AFWS start with

include any operator actions required no suction from the CST is not a mode for to protect the auxiliary feedwater common failure of all auxiliary feedwater system pumps against self-damage pumps.

before water flow is initiated.

(2) The case in which the primary water supply is being depleted. The pro-cedure for this case should provide for transfer to the alternate water

sources prior to draining of the pri-mary water supply.

5. Recommendation GS The as-built plant The turbine-driven pump in the WCGS should be capable of providing the design is capable of being auto-required auxiliary feedwater system flow matically initiated and operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from any one independent of any alternating auxiliary feedwater pump train, indepen- current power source for at dent of any alternating current power least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Essential con-

source. If manual auxiliary feedwater trols, valve operators, other system initiation or flow control is supporting systems, and turbine required following a complete loss of lube oil cooling for the turbine-

alternating current power, emergency driven pump are all independent procedures should be established for of alternating current power.

manually initiating and controlling the

system under these conditions. Since the water for cooling of the lube oil for the turbine-driven pump bearings may be

dependent on alternating current power, Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 4)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

5. design or procedural changes shall be made to eliminate this dependency as soon as practicable.

Until this is done, the emergency procedures should provide for an individual to be stationed at the

turbine-driven pump in the event of loss of all alternating cur-rent power to monitor pump bearing

and/or lube oil temperatures. If necessary, this operator would operate the turbine-driven pump

in a manual on-off mode until alternating current power is re-stored. Adequate lighting powered

by direct current power sources and communications at local sta-tions should also be provided if

manual initiation and control of the auxiliary feedwater system is needed. See Recommendation GL-3

for the longer-term resolution of this concern.

6. Recommendation GS The licensee Valve lineups and independent second should confirm flow path operator verification of valve lineups availabiity of an auxiliary is required on the auxiliary feedwater feedwater system flow train that system after maintenance. Verification has been out of service to perform of operability is included as part of periodic testing or maintenance as functional testing on return from ex-

follows: tended cold shutdown.

- Procedures should be implemented to require an operator to determine Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 5)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

6. that the auxiliary feedwater system valves are properly aligned and a second operator to

independently verify that the valves are properly aligned.

The licensee should propose Technical Specifications to assure that prior to plant

startup following an extended cold shutdown, a flow test would be performed to verify the

normal flow path from the primary auxiliary feedwater system water source to the steam

generators. The flow test should be conducted with auxiliary feedwater system

valves in their normal alignment.

7. Recommendation GS The licensee The WCGS auxiliary feedwater system should verify that the automatic is designed so that automatic start auxiliary feedwater system initiation signals and circuits signals and associated circuitry are redundant and meet safety-are safety grade. If this cannot grade requirements. Refer to be verified, the auxiliary system Section 7.3.6.

automatic initiation system should be modified in the short-term to meet the functional requirements

listed below. For the longer term, the automatic initiation signals Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 6)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

7. and circuits should be upgraded to meet safety-grade requirements as indicated in Recommendation GL-
5.

(1) The design should provide for the automatic initiation of the auxiliary feedwater system flow.

(2) The automatic initiation signals and circuits should be

designed so that a single failure will not result in the loss of auxiliary feedwater

system function.

(3) Testability of the initiation signal and circuits shall be a feature of the design.

(4) The initiation signals and circuits should be powered from the emergency buses.

(5) Manual capability to initiate the auxiliary feedwater system

from the control room should be implemented so that a single failure in the manual circuits will not result in the loss of system function.

Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 7)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

7. (6) The alternating current motor-driven pumps and valves in the auxiliary feedwater system should be included

in the automatic actuation (simul-taneous and/or sequential) of the loads to the emergency buses.

(7) The automatic initiation signals and circuits shall be designed so that

their failure will not result in the loss of manual capability to initiate the auxiliary feedwater system from

the control room.

8. Recommendation GS The licensee should See response to GS-7 above.

install a system to automatically initiate auxiliary feedwater system flow. This system need not be safety grade; however, in the short term, it should meet the criteria listed below, which are similar to Item 2.1.7.a of NUREG-0578. For the longer

term, the automatic initiation signals and circuits should be upgraded to meet safety-grade requirements; as indicated in

Recommendation GL-2.

(1) The design should provide for the automatic initiation of the auxiliary feedwater system flow.

(2) The automatic initiation signal and circuits should be designed so that a single failure will not result in

the loss of auxiliary feedwater system function. Rev. 1 WOLF CREEK TABLE 10.4-13B (Sheet 8)

A. SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

8. (3) Testability of the initiating signals and circuits should be a feature of the design.

(4) The initiating signals and circuits should be powered from the emergency

buses.

(5) Manual capability to initiate the auxiliary feedwater system from the control room should be retained and should be implemented

so that a single failure in the manual circuits will not result in the loss of system function.

(6) The alternating current powered motor-driven pumps and valves in

the auxiliary feedwater system should be included in the automatic actua-tion (simultaneous and/or sequen-

tial) of the loads to the emergency buses.

(7) The automatic initiation signals and circuits should be designed so that their failure will not result in

the loss of manual capability to initiate the auxiliary feedwater sys-tem from the control room.

B. ADDITIONAL SHORT-TERM RECOMMENDATIONS

1. Recommendation - The licensee should provide The existing WCGS design provides the redundant level indication and low-level following redundant control room indica-alarms in the control room for the auxiliary tion for condensate storage tank level.

Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 9)

B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

feedwater system primary water supply to a) LI-4A shown on Figure 9.2-12.

allow the operator to anticipate the need b) P1-24A, P1-25A, or P1-26A- Class 1E to make up water or transfer to an alternate auxiliary feedwater pump suction water supply and prevent a low pump suction pressure indication shown on

pressure condition from occurring. The Figure 10.4-9.

low-level alarm setpoint should allow at least 20 minutes for operator action, Direct correlation between pump suction

assuming that the largest capacity auxiliary pressure and tank level is achieved by feedwater system pump is operating. simple conversion. Exclusion of dynamic piping losses from the conversion results

in a conservative determination of tank level.

Redundant control room tank level alarms are as follows:

a) LALL-9 shown on Figure 9.2-12.

b) LAL Class 1E auxiliary feedwater pump low suction pressure alarm shown

on Figure 10.4-9.

Setpoints for both alarms allow at least 20 minutes for operator action, assuming that the largest capacity auxiliary feedwater pump is operating.

2. Recommendation (This recommendation has been WCGS performed a 48-hour, in situ endur-revised from the original recommendation in ance test on all auxiliary feedwater NUREG-0611 - The licensee should perform a pumps as part of the preoperational test 48-hour endurance test on all auxiliary feed- program.

water system pumps, if such a test or contin-uous period of operation has not been accom-plished to date. Following the 48-hour pump run, the pumps should be shut down and cooled

down and then restarted and run for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Test acceptance criteria should include Rev. 1 WOLF CREEK TABLE 10.4-13B (Sheet 10)

B. ADDITIONAL SHORT-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

demonstrating that the pumps remain within design limits with respect to bearing/

bearing oil temperatures and vibration and that pump room ambient conditions

(temperature, humidity) do not exceed environmental qualification limits for safety-related equipment in the room.

3. Recommendation - The licensee should The WCGS auxiliary feedwater design implement the following requirements as provides safety-grade (Class 1E) indica-specified by Item 2.1.7.b on page A-32 of tion in the control room of auxiliary NUREG-0578: feedwater flow to each steam generator.

The design utilizes four independent

Safety-grade indication of auxiliary feed- Class 1E power supplies. The safety-water flow to each steam generator shall grade steam generator level indication be provided in the control room. The provides a backup method for determining

auxiliary feedwater flow instrument channels the auxiliary feedwater flow to each shall be powered from the emergency buses steam generator.

consistent with satisfying the emergency

power diversity requirements for the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the

Standard Review Plan, Section 10.4.9

4. Recommendation - Licensees with plants which This recommendation is not applicable to require local manual realignment of valves to the WCGS design.

conduct periodic tests on auxiliary feedwater system trains, and where there is only one re-maining auxiliary feedwater system train available for operation, should propose Technical Specifications to provide that a

dedicated individual who is in communication with the control room be stationed at the manual valves. Upon instruction from the con-

trol room, this operator would realign the valves in the auxiliary feedwater system train from the test mode to their operational alignment. Rev. 0 WOLF CREEK TABLE 10.4-13B (Sheet 11)

C. LONG-TERM RECOMMENDATIONS WCGS POSITION (Cont.)

1. Recommendation GL For plants with a The WCGS design includes automatic manual starting system, the licensee should initiation of the auxiliary feedwater install a system to automatically initiate system. Refer to the response to GS-7.

the auxiliary feedwater system flow. This system and associated automatic initation

signals should be designed and installed to meet safety-grade requirements. Manual auxiliary feedwater system start and control

capability should be retained with manual start serving as backup to automatic auxil-iary system initiation.

2. Recommendation GL Licensees with plant The alternate water supply (essential designs in which all (primary and alternate) service water) connects to the auxiliary water supplies to the auxiliary feedwater feedwater pump suction piping downstream systems pass through valves in a single flow of the single, normally locked-open valve path should install redundant parallel flow in a single flow path from the primary paths (piping and valves). water source (condensate storage tank).

Valves from the alternate supply auto-Licensees with plant designs in which the primary matically open on low pump suction auxiliary feedwater system water supply passes pressure. Refer to the response to GS-2

through valves in a single flowpath, but the and GS-4.

alternate auxiliary feedwater system water supplies connect to the auxiliary feedwater system pump

suction piping downstream of the above valve(s) should install redundant valves parallel to the

above valve(s) or provide automatic opening of

the valve(s) from the alternate water supply upon low pump suction pressure.

The licensee should propose Technical Specifications to incorporate appropriate periodic inspections to verify the valve positions into the surveillance requirements.

Rev. 10 WOLF CREEK TABLE 10.4-13B (Sheet 12)

C. LONG-TERM RECOMMENDATIONS (Cont.) WCGS POSITION (Cont.)

3. Recommendation GL At least one auxiliary The WCGS design meets this recommendation.

feedwater system pump and its associated flow path Refer to the response to GS-5.

and essential instrumentation should automatically initiate auxiliary feedwater system flow and be capable of being operated independently of any alternating current power source for at least

2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Conversion of direct current power to alternating current power is acceptable.

4. Recommendation GL Licensees having plants As discussed in the response to GS-4 with unprotected normal auxiliary feedwater and GL-2 above, the WCGS design includes system supplies should evaluate the design of automatic transfer to the alternate water their auxiliary feedwater systems to determine source. The alternate source (essential if automatic protection of the pumps is neces- service water) is protected from tornados sary following a seismic event or a tornado. and is seismic Category I.

The time available to the control room operator, and the time necessary for assessing the problem

and taking action should be considered in deter-mining whether operator action can be relied on to prevent pump damage. Consideration should be

given to providing pump protection by means such as automatic switchover of the pump suctions to the alternate safety-grade source of water, automatic pump trips on low suction pressure, or upgrading the normal source of water to meet seismic Category I and tornado protection

requirements.

5. Recommendation GL The licensee should upgrade As stated in the response to GS-7 the auxiliary feedwater system automatic initia- the auxiliary feedwater system automatic tion signals and circuits to meet safety-grade initiation signals and circuits are safety requirements. grade.

Rev. 0 WOLF CREEK TABLE 10.4-14 AUXILIARY FEEDWATER SYSTEM INDICATING, ALARM, AND CONTROL DEVICES Control Room Indication/Control Control Room Local (1) Alarm Condensate storage tank suction valve position X X

ESW suction valve position X X

Condensate storage tank X X X level Condensate storage tank suction header pressure X

Low pump suction pressure X X X Low pump discharge pressure X X X

Pump flow control valve operation X X

Pump flow control valve position X X

Auxiliary feedwater flow X X

Auxiliary feedwater pump turbine trip & throttle valve position X X X

Auxiliary feedwater pump turbine speed X X X (2) Auxiliary feedwater pump

turbine low lube oil pressure X Auxiliary feedwater pump

turbine high lube oil temperature X (1) Local control here means the auxiliary shutdown panel.

(2) High/Low Speed and Control system fault alarms.

Rev. 27 WOLF CREEK TABLE 10.4-15 SECONDARY LIQUID WASTE SYSTEM COMPONENT DATA

Secondary Liquid Waste Evaporator (Note 1)

Quantity 1

Type Forced circulation Design process flow, gpm 30 Design pressure (vapor body), psig 30 Design temperature (vapor body), F 300 Cooling water requirements (condenser/subcooler)

Flow, lb/hr 685,000 Temperature, in/out, F 105/130 Pressure (max), psig 150

Steam requirements (heater)

Flow, lb/hr 18,000 (min)

Temperature in/out 250 (steam)/250 (liquid)

Pressure, psig 15 Principal design codes ASME VIII and TEMA R

Quality group D (augmented)

Materials of Construction

Vapor body Inconel 625 Entrainment separator 316L SS Distillate condenser 316L SS

Distillate subcooler 316L SS Heater vent gas cooler (shell/tubes) Carbon steel/316L SS

Condenser vent gas cooler (shell/tubes) Carbon steel/316L SS Heater Inconel 625

Recirculation pump Alloy 20 Concentrates pumps Alloy 20 Distillate pump 316L SS

Recirculation piping Inconel 625 Service (steam and cooling water) Carbon steel Piping

Valves Inconel 625, 316L SS, and carbon steel

SLW Charcoal Adsorber

Quantity 1 Type Activated carbon Fluid Secondary liquid waste

evaporator distillate or floor drain waste Design pressure, psig 150

Rev. 14

WOLF CREEK TABLE 10.4-15 (Sheet 2)

Design temperature, F 200 Design flow, gpm 35 Design pressure drop (fouled condition), psi 10 to 12 at 35 gpm

Volume, ft 3 (charcoal) 88 Design code ASME Section VIII

Material 304 SS

SLW Demineralizer

Quantity 1 Type Mixed bed Fluid Secondary liquid

waste evaporator distillate, floor drain waste, low

TDS waste Design pressure, psig 150 Design temperature, F 200

Design pressure drop (fouled condition), psi 12 to 15 at 100 gpm Flow rate, gpm 100

Resin volume, cu ft 55 Design code ASME Section VIII Material 304 SS

SLW Oil Interceptor Quantity 1

Type Gravity separation Design flow, gpm 150 Fluid Turbine building drains

Design pressure Atmospheric Design temperature, F 225 Design code Manufacturer's standard

Material 304 SS High TDS Collector Tanks

Quantity 2 Type Vertical, cylindrical, dished-bottom Fluid Regenerant waste (high TDS)

Capacity, gal 17,000 Design temperature, F 140 Design pressure, psig 15

Internals Mixer Design code ASME Section VIII Material 316L SS

Rev. 0

WOLF CREEK TABLE 10.4-15 (Sheet 3)

SLW Drain Collector Tanks Quantity 2 Type Vertical, cylindrical, dished bottom Fluid Turbine building floor drains

Capacity, gals 15,000 Design temperature, F 200 Design pressure Atmospheric

Design code ASME Section VIII Material 304 SS

Low TDS Collector Tanks Quantity 2

Type Vertical, cylindrical, conical bottom Fluid Regenerant waste

(low TDS)

Capacity, gals 45,000 Diameter, ft-in. 24-0

Height, ft-in. 20-3 Design temperature, F 150 Design pressure Atmospheric

Internals Baffles to promote settling of solids Material 304 SS

Design code ASME Section VIII SLW Monitor Tanks

Quantity 2 Type Vertical, cylindrical, dished bottom Fluid Processed turbine building floor

drains and con-densate demin-eralizer regen-

erant wastes, borated wastes, and primary water Capacity, gals 15,000 Design temperature, F 200 Design pressure Atmospheric

Design code ASME Section VIII Material 304 SS

Rev. 8

WOLF CREEK TABLE 10.4-15 (Sheet 4)

Low TDS Collector Tanks Pumps Quantity 2 Type In-line centrifugal

Fluid Regenerant waste (low TDS)

Design pressure, psig 250 Design temperature, F 100 Capacity, gpm 150 Rated head, ft 220 NPSH required, ft 6 Design code Manufacturer's standard Material (wetted surface) 316 SS

Motor 20 Hp/460 V/3 phase/60 Hz

Secondary Liquid Waste Oil Interceptor Transfer Pumps

Quantity 2 Type In-line centrifugal Fluid Turbine building floor drains

Design pressure, psig 300 Design temperature, F 150 Capacity, gpm 150

Rated head, ft 51 Design code Manufacturer's standard Material 316 SS

Motor 5 hp/460 V/3 phase/60 Hz High TDS Collector Tanks Pumps

Quantity 2 Type In-line centrifugal

Fluid Regenerant waste (high TDS)

Design pressure, psig 300

Design temperature, F 130 Capacity, gpm 35 Rated head, ft 255

NPSH required, ft 8 Design code Manufacturer's standard Material (wetted surface) Alloy 20

Motor 10 Hp/460 V/3 phase/60 Hz

Rev. 12

WOLF CREEK TABLE 10.4-15 (Sheet 5)

SLW Drain Collector Tank Pumps Quantity 2 Type In-line centrifugal

Fluid Turbine building floor drains Design pressure, psig 300

Design temperature, F 200 Capacity, gpm 35 Rated head, ft 207

NPSH required, ft 8 Design code Manufacturer's standard Material (wetted surface) 316 SS

Motor 10 Hp/460 V/3 phase/60 Hz

SLW Discharge Pumps Quantity 2 Type In-line centrifugal Fluid Processed secondary liquid wastes

Design pressure, psig 300 Design temperature, F 200 Capacity, gpm 100

Rated head, ft 250 NPSH required, ft 7 Design code Manufacturer's standard

Material (wetted surface) 316 SS Motor 15 Hp/460 V/3 phase/60 Hz

Low TDS Filters (FHF04A, 04B)

  • Quantity 2 Type Cartridge Design pressure, psig 150

Design temperature, F 250 Particle retention (See Note 2 of Table 9.3-13)

Pressure drop, psi @ 100 gpm

Clean 1 Dirty 25 Design code (vessel) ASME Section VIII

Material (vessel) 304 SS

  • See Table 9.3-13 Sheet 2 comment High TDS Transfer Tank

Quantity 1 Type Horizontal Fluid Regenerant waste

(high TDS)

Rev. 15

WOLF CREEK TABLE 10.4-15 (Sheet 6)

Capacity, gals 3,120 Design temperature, F 130 Design pressure Atmospheric Design code ASME Section VIII

Material 316L SS High TDS Transfer Tank Pumps

Quantity 2 Type In-line centrifugal

Fluid Regenerant waste (high TDS)

Design pressure, psig 300

Design temperature, F 130 Capacity, gpm 450 Rated head, ft 78

NPSH required, ft 8 Design code Manufacturer's standard Material (wetted surface) Alloy 20

Motor 20 Hp/460 V/3 phase/60 Hz Low TDS Transfer Tank

Quantity 1 Type Horizontal

Fluid Regenerant waste (low TDS)

Capacity, gals 3,120

Design temperature, F 130 Design pressure Atmospheric Design code ASME Section VIII

Material 304 SS Low TDS Transfer Tank Pumps

Quantity 2 Type In-line centrifugal

Fluid Regenerant waste (low TDS)

Design pressure, psig 300

Design temperature, F 130 Capacity, gpm 450 Rated head, ft 78

NPSH required, ft 8 Design code Manufacturer's standard Material (wetted surfaces) 316 SS

Motor 20 Hp/460 V/3 phase/60 Hz

Rev. 0

WOLF CREEK TABLE 10.4-15 (Sheet 7)

SLW Evaporator Feed Filter (FHF05)

  • Quantity 1 Type Cartridge

Design pressure, psig 150 Design temperature, F 250 Design flow, gpm 35

Particle retention 30 micron (max) 98% (min) 49 micron 100%

Pressure drop at 35 gpm Clean, psi 1 Dirty, psi 25

Material, vessel 316L SS Design code ASME Section VIII

Piping and Valves High TDS and Evaporator Feed

Material 316L SS Design code ANSI B31.1

Pressure rating, psig 150 Evaporator Concentrates Discharge

Material Incoloy 825 Design code ANSI B31.1

Pressure rating, psig 150 All Others

Material 304 or 316 SS Design code ANSI B31.1 Pressure rating, psig 150

  • See comments on Sheet 2 of Table 9.3-13.

Note 1: Equipment permanently out of service.

Rev. 19

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