ML15084A504

Wolf Creek Generating Station Updated Safety Analysis Report (Usar), Revision 28, Chapter 5.0, Reactor Coolant System and Connected Systems

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Text

WOLF CREEK TABLE OF CONTENTS CHAPTER 5.0 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

Section Page 5.1 SUMMARY DESCRIPTION 5.1-1 5.1.1 DESIGN BASES 5.1-1 5.1.2 DESIGN DESCRIPTION 5.1-2 5.1.3 SYSTEM COMPONENTS 5.1-4 5.1.4 SYSTEM PERFORMANCE CHARACTERISTICS 5.1-5

5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY 5.2-1 5.2.1 COMPLIANCE WITH CODES AND CODE CASES 5.2-1

5.2.1.1 Compliance with 10 CFR 50.55a 5.2-1 5.2.1.2 Applicable Code Cases 5.2-1

5.2.2 OVERPRESSURE PROTECTION 5.2-2

5.2.2.1 Design Bases 5.2-2 5.2.2.2 Design Evaluation 5.2-3 5.2.2.3 Piping and Instrumentation Diagrams 5.2-4 5.2.2.4 Equipment and Component Description 5.2-4 5.2.2.5 Mounting of Pressure-Relief Devices 5.2-4 5.2.2.6 Applicable Codes and Classification 5.2-7 5.2.2.7 Material Specifications 5.2-8 5.2.2.8 Process Instrumentation 5.2-8 5.2.2.9 System Reliability 5.2-8 5.2.2.10 RCS Pressure Control During Low Temperature Operation 5.2-8 5.2.2.11 Testing and Inspection 5.2-13

5.2.3 MATERIALS SELECTION, FABRICATION, AND PROCESSING 5.2-13

5.2.3.1 Material Specifications 5.2-13 5.2.3.2 Compatibility with Reactor Coolant 5.2-14 5.2.3.3 Fabrication and Processing of Ferritic Materials 5.2-17 5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel 5.2-18

5.0-i Rev. 23 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 5.2.4 INSERVICE INSPECTION AND TESTING OF REACTOR COOLANT PRESSURE BOUNDARY 5.2-25

5.2.4.1 Inspection of Class I Components 5.2-25 5.2.4.2 Arrangement and Accessibility 5.2-26 5.2.4.3 Examination Techniques and Procedures 5.2-29 5.2.4.4 Inspection Intervals 5.2-31 5.2.4.5 Examination Categories and Requirements 5.2-31 5.2.4.6 Evaluation of Examination Results 5.2-32 5.2.4.7 System Leakage and Hydrostatic Tests 5.2-32

5.2.5 REACTOR COOLANT PRESSURE BOUNDARY LEAKAGE DETECTION SYSTEMS 5.2-32 5.2.5.1 Design Bases 5.2-32 5.2.5.2 System Description 5.2-33 5.2.5.3 Safety Evaluation 5.2-43 5.2.5.4 Tests and Inspections 5.2-43 5.2.5.5 Instrumentation Applications 5.2-43

5.

2.6 REFERENCES

5.2-44 5.3 REACTOR VESSEL 5.3-1 5.3.1 REACTOR VESSEL MATERIALS 5.3-1

5.3.1.1 Material Specifications 5.3-1 5.3.1.2 Special Processes Used for Manufacturing and Fabrication 5.3-1 5.3.1.3 Special Methods for Nondestructive Examination 5.3-2 5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels 5.3-4 5.3.1.5 Fracture Toughness 5.3-4 5.3.1.6 Material Surveillance 5.3-5 5.3.1.7 Reactor Vessel Fasteners 5.3-16

5.3.2 PRESSURE - TEMPERATURE LIMITS 5.3-17 5.3.2.1 Limit Curves 5.3-17 5.3.2.2 Operating Procedures 5.3-17

5.0-ii Rev. 23 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page

5.3.3 REACTOR VESSEL INTEGRITY 5.3-18

5.3.3.1 Design 5.3-18 5.3.3.2 Materials of Construction 5.3-19 5.3.3.3 Fabrication Methods 5.3-19 5.3.3.4 Inspection Requirements 5.3-19 5.3.3.5 Shipment and Installation 5.3-19 5.3.3.6 Operating Conditions 5.3-20 5.3.3.7 Inservice Surveillance 5.3-21

5.

3.4 REFERENCES

5.3-24

5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4-1

5.4.1 REACTOR COOLANT PUMPS 5.4-1

5.4.1.1 Design Bases 5.4-1 5.4.1.2 Pump Description 5.4-1 5.4.1.3 Design Evaluation 5.4-4 5.4.1.4 Tests and Inspections 5.4-9 5.4.1.5 Pump Flywheels 5.4-9 5.4.2 STEAM GENERATORS 5.4-11 5.4.2.1 Design Bases 5.4-11 5.4.2.2 Design Description 5.4-12 5.4.2.3 Steam Generator Materials 5.4-14 5.4.2.4 Steam Generator Inservice Inspection 5.4-18 5.4.2.5 esign Evaluation 5.4-20 5.4.2.6 Quality Assurance 5.4-24 5.4.3 REACTOR COOLANT PIPING 5.4-25 5.4.3.1 Design Bases 5.4-25 5.4.3.2 Design Description 5.4-26 5.4.3.3 Design Evaluation 5.4-29 5.4.3.4 Tests and Inspections 5.4-30 5.4.4 MAIN STEAM LINE FLOW RESTRICTOR 5.4-31 5.4.4.1 Design Basis 5.4-31 5.4.4.2 Design Description 5.4-31 5.4.4.3 Design Evaluation 5.4-31 5.4.4.4 Tests and Inspections 5.4-31

5.0-iii Rev. 27 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 5.4.5 MAIN STEAM LINE ISOLATION SYSTEM 5.4-32 5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM 5.4-32 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM 5.4-32

5.4.7.1 Design Bases 5.4-32 5.4.7.2 Design Description 5.4-32 5.4.7.3 Performance Evaluation 5.4-43 5.4.7.4 Preoperational Testing 5.4-44

5.4.8 REACTOR WATER CLEANUP SYSTEM 5.4-44 5.4.9 MAIN STEAM LINE AND FEED WATER PIPING 5.4-44 5.4.10 PRESSURIZER 5.4-45

5.4.10.1 Design Bases 5.4-45 5.4.10.2 Design Description 5.4-46 5.4.10.3 Design Evaluation 5.4-47 5.4.10.4 Tests and Inspections 5.4-49

5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM 5.4-50

5.4.11.1 Design Bases 5.4-50 5.4.11.2 System Description 5.4-50 5.4.11.3 Design Evaluation 5.4-52 5.4.11.4 Instrumentation Requirements 5.4-53 5.4.11.5 Tests and Inspections 5.4-53

5.4.12 VALVES 5.4-53

5.4.12.1 Design Bases 5.4-53 5.4.12.2 Design Description 5.4-54 5.4.12.3 Design Evaluation 5.4-54 5.4.12.4 Tests and Inspections 5.4-54

5.4.13 SAFETY AND RELIEF VALVES 5.4-55

5.4.13.1 Design Bases 5.4-55 5.4.13.2 Design Description 5.4-55 5.4.13.3 Design Evaluation 5.4-56 5.4.13.4 Tests and Inspections 5.4-56

5.4.14 COMPONENT SUPPORTS 5.4-56

5.4.14.1 Design Bases 5.4-56 5.4.14.2 Description 5.4-57 5.4.14.3 Design Evaluation 5.4-59 5.4.14.4 Tests and Inspections 5.4-60

5.0-iv Rev. 26 WOLF CREEK TABLE OF CONTENTS (Continued)

Section Page 5.4.15 REFERENCES 5.4-60

5.0-v Rev. 21 WOLF CREEK TABLE OF CONTENTS (Continued)

LIST OF TABLES Table No.

Title 5.1-1 System Design and Operating Parameters

5.2-1 Applicable Code Addenda for Reactor Coolant System Components

5.2-2 Class 1 Primary Components Material Specifications

5.2-3 Class 1 and 2 Auxiliary Components Material Specifications 5.2-4 Reactor Vessel Internals for Emergency Core Cooling

Systems

5.2-5 Recommended Reactor Coolant Water Chemistry Limits

5.2-6 Design Comparison With Regulatory Guide 1.45, Dated May 1973, Titled Reactor Coolant Pressure Boundary Leakage Detection Systems

5.2-7 Bounding Lithium-Boron-Cycle Time for Coordinated pH 7.1-7.2 Primary Coolant Chemistry

5.3-1 Reactor Vessel Quality Assurance Program

5.3-2 Reactor Vessel Design Parameters

5.3-3 Reactor Vessel Material Properties

5.3-4 Deleted

5.3-5 Deleted

5.3-6 Reactor Vessel Closure Head Bolting Material Properties

5.3-7 Vessel Beltline Region Weld Metal Identification

Information

5.3-8 Beltline Region Intermediate Shell Plate Toughness

5.3-9 Beltline Region Lower Shell Plate Toughness

5.3-10 Beltline Region Weld Metal Toughness

5.3-11 Reactor Vessel Material Surveillance Program - Withdrawl

Schedule

5.4-1 Reactor Coolant Pump Design Parameters

5.4-2 Reactor Coolant Pump Quality Assurance Program

5.4-3 Steam Generator Design Data

5.0-vi Rev. 23 WOLF CREEK TABLE OF CONTENTS (Continued)

LIST OF TABLES Table No.

Title 5.4-4 Steam Generator Quality Assurance Program

5.4-5 Reactor Coolant Piping Design Parameters

5.4-6 Reactor Coolant Piping Quality Assurance Program

5.4-7 Design Parameters Bases for Residual Heat Removal System Operation 5.4-8 Residual Heat Removal System Component Data

5.4-9 Failure Modes and Effects Analysis - Residual Heat Removal System Active Components - Plant Cooldown Operation

5.4-10 Pressurizer Design Data

5.4-11 Reactor Coolant System Design Pressure Settings

5.4-12 Pressurizer Quality Assurance Program

5.4-13 Pressurizer Relief Tank Design Data

5.4-14 Relief Valve Discharge to the Pressurizer Relief Tank

5.4-15 Reactor Coolant System Valve Design Parameters

5.4-16 Reactor Coolant System Valves Nondestructive Examination Program

5.4-17 Pressurizer Valves Design Parameters

5.0-vii Rev. 14

WOLF CREEK CHAPTER 5 - 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 #*5.1-1 1 Reactor Coolant System M-12BB01 5.1-1 2 Reactor Coolant System M-12BB02 5.1-1 3 Reactor Coolant System M-12BB03 5.1-1 4 Reactor Coolant System M-12BB04 5.1-2 0 Reactor Coolant System Process Flow Diagram 5.2-1 0 Installation Detail for the Main Steam Pressure Relief Devices 5.2-2 0 Primary Coolant Leak Detection Response Time 5.3-1 0 Reactor Vessel 5.3-2 0 Wolf Creek Unit 1 Reactor Vessel Beltline Region Material Identification and Location 5.4-1 0 Reactor Coolant Controlled Leakage Pump 5.4-2 0 Reactor Coolant Pump Estimated Performance Characteristic 5.4-3 0 Westinghouse Model F Steam Generator 5.4-4 0 Westinghouse Model F Steam Generator Mechanical Modification Improvements 5.4-5 0 Westinghouse Model F Steam Generator Design Improvements 5.4-6 0 Quatrefoil Broached Holes 5.4-7 0 Residual Heat Removal System M-12EJ01 5.4-8 0 Residual Heat Removal System Process Flow Diagram 5.4-9 0 Normal Residual Heat Removal Cooldown 5.4-10 0 Single Residual Heat Removal Train Cooldown 5.4-11 0 Pressurizer 5.4-12 0 Pressurizer Relief Tank 5.4-13 0 Reactor Vessel Supports 5.4-14 0 Steam Generator Supports 5.4-15 0 Reactor Coolant Pump Supports 5.4-16 0 Reactor Building Internals Pressurizer Supports 5.4-17 0 Pressurizer Supports 5.4-18 0 Crossover Leg Supports 5.4-19 0 Crossover Leg Vertical Run Restraint (deleted in 5th refueling outage) 5.4-20 0 Hot Leg Restraint 5.4-21 0 Hot and Cold Leg Lateral Restraints C-03BB53

5.0-viii Rev. 27 WOLF CREEK CHAPTER 5.0 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.1 SUMMARY DESCRIPTION 5.1.1 DESIGN BASES

The performance and safety design bases of the reactor coolant system (RCS) and its major components are interrelated. These design bases are listed below:

a. The RCS has the capability to transfer to the steam and power conversion system the heat produced during power operation and when the reactor is subcritical, including the initial phase of plant cooldown.

b. The RCS has the capability to transfer to the residual heat removal system the heat produced during the subsequent phase

of plant cooldown and cold shutdown.

c. The RCS heat removal capability under power operation and normal operational transients, including the transition from

forced to natural circulation, assures no fuel damage within

the operating bounds permitted by the reactor control and

protection systems.

d. The RCS provides the water used as the core neutron moderator and reflector and as a solvent for chemical shim

control.

e. The RCS maintains the homogeneity of the soluble neutron poison concentration and the rate of change of the coolant temperature, so that uncontrolled reactivity changes do not occur.

f. The RCS pressure boundary is capable of accommodating the temperatures and pressures associated with operational

transients.

g. The reactor vessel supports the reactor core and control rod drive mechanisms.

h. The pressurizer maintains the system pressure during operation and limits pressure transients. During the

reduction or increase of plant load, the pressurizer

accommodates volume changes in the reactor coolant. 5.1-1 Rev. 0 WOLF CREEK

i. The reactor coolant pumps supply the coolant flow necessary to remove heat from the reactor core and transfer it to the

steam generators.

j. The steam generators provide high quality steam to the turbine. The tube and tubesheet boundary are designed to prevent the transfer of radioactivity generated within the core to the secondary system.

k. The RCS piping contains the coolant under operating temperature and pressure conditions and limits leakage (and

activity release) to the containment atmosphere. The RCS piping contains demineralized borated water which is circulated at the flow rate and temperature consistent with achieving the reactor core thermal and hydraulic

performance.

l. The RCS is monitored for loose parts, as described in Section 4.4.6.

5.1.2 DESIGN DESCRIPTION

The RCS, shown in Figure 5.1-1, consists of four similar heat transfer loops connected in parallel to the reactor pressure vessel. Each loop contains a reactor coolant pump, steam generator, and associated piping and valves. In addition, the system includes a pressurizer, pressurizer relief and safety valves, interconnecting piping, and instrumentation necessary for operational

control. All the above components are located in the containment building.

During operation, the RCS transfers the heat generated in the core to the steam generators where steam is produced to drive the turbine generator. Borated demineralized water is circulated in the RCS at a flow rate and temperature consistent with achieving the reactor core thermal-hydraulic performance. The

water also acts as a neutron moderator and reflector and as a solvent for the

neutron absorber used in chemical shim control.

The RCS pressure boundary is a barrier against the release of radioactivity generated within the reactor, and is designed to ensure a high degree of

integrity throughout the life of the plant.

RCS pressure is controlled by the use of the pressurizer where water and steam are maintained in equilibrium by electrical heaters and water sprays. Steam

can be formed (by the heaters) or condensed (by the pressurizer spray) to

minimize pressure variations due to contraction and expansion of the reactor

coolant. 5.1-2 Rev. 0 WOLF CREEK Spring-loaded safety valves and power-operated relief valves from the pressurizer provide for steam discharge from the RCS. Discharged steam is

piped to the pressurizer relief tank, where the steam is condensed and cooled by mixing with water.

The extent of the RCS is defined as:

a. The reactor vessel, including control rod drive mechanism housings

b. The portion of the steam generators containing reactor coolant

c. Reactor coolant pumps

d. The pressurizer

e. Safety and relief valves

f. The interconnecting piping, valves, and fittings between the principal components listed above

g. The piping, fittings, and valves leading to connecting auxiliary or support systems up to and including the second isolation valve (from the high pressure side) on each line The RCS is shown schematically in Figure 5.1-2. Included on this figure is a tabulation of principal pressures and temperatures and the flow rate of the

system under normal steady state full power operating conditions. These

parameters are based on the best estimate flow at the pump discharge. RCS volume under the above conditions is presented in Table 5.1-1.

A piping and instrumentation diagram of the RCS is shown in Figure 5.1-1. The diagrams show the extent of the systems located within the containment and the points of separation between the RCS and the secondary (heat utilization) system. Figure 1.2-9 and Figures 1.2-11 through 1.2-18 provide plan and elevation views of the reactor building. These figures show principal dimensions of reactor coolant system components in relationship with supporting

and surrounding steel and concrete structures and demonstrate the protection provided to the reactor coolant system by its physical layout. 5.1-3 Rev. 13 WOLF CREEK 5.1.3 SYSTEM COMPONENTS The major components of the RCS are as follows:

a. Reactor vessel

The reactor vessel is cylindrical and has a welded, hemispherical bottom head and a removable, flanged,

hemispherical upper head. The vessel contains the core, core-supporting structures, control rods, and other parts

directly associated with the core.

The vessel has inlet and outlet nozzles located in a horizontal plane just below the reactor vessel flange but above the top of the core. Coolant enters the vessel

through the inlet nozzles and flows down the core barrel-

vessel wall annulus, turns at the bottom, and flows up

through the core to the outlet nozzles.

b. Steam generators The steam generators are vertical shell and U-tube evaporators with integral moisture separating equipment.

The reactor coolant flows through the inverted U-tubes,

entering and leaving through the nozzles located in the hemispherical bottom head of the steam generator. Steam is generated on the shell side and flows upward through the

moisture separators to the outlet nozzle at the top of the

vessel. The steam generator design is designated by

Westinghouse as Model F.

c. Reactor coolant pumps The reactor coolant pumps are single speed centrifugal units driven by air-cooled, three-phase induction motors. Heat

from the air-cooling system is rejected to the component

cooling water. The shaft is vertical with the motor mounted

above the pump. A flywheel on the shaft above the motor

provides additional inertia to extend pump coastdown. The flow inlet is at the bottom of the pump, and the discharge is on the side.

d. Piping

The reactor coolant piping is seamless stainless steel piping. The hot leg is defined as the piping between the reactor vessel outlet nozzle and the steam generator. The cold leg is defined as the piping between the reactor

coolant pump outlet and the reactor vessel. The crossover

leg is defined as the piping between the steam generator and

the reactor coolant pump inlet. 5.1-4 Rev. 0 WOLF CREEK

e. Pressurizer The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. Electrical heaters are installed through the bottom head of the vessel while the spray nozzle and relief and safety valve connections are located in the top head of the vessel.

f. Safety and relief valves

The pressurizer safety valves are of the totally enclosed pop-type. The valves are spring loaded and self activated with back pressure compensation. The power-operated relief valves have electric solenoid actuators. They are operated

automatically based on RCS pressure or by remote manual

control. Remotely operated valves are provided to isolate

the inlet to the power-operated relief valves if excessive

leakage occurs. These valves will automatically isolate if

the RCS pressure drops below a predetermined value,

indicative of a stuck-open, power-operated relief valve.

Steam from the pressurizer safety and relief valves is discharged into the pressurizer relief tank through a

sparger pipe under the water level. This condenses and

cools the steam by mixing it with water that is near ambient temperature.

5.1.4 SYSTEM PERFORMANCE CHARACTERISTICS Design and performance characteristics of the RCS are provided in Table 5.1-1.

a. Reactor coolant flow The reactor coolant flow, a major parameter in the design of the system and its components, is established with a

detailed design procedure supported by operating plant

performance data, by pump model tests and analysis, and by

pressure drop tests and analyses of the reactor vessel and

fuel assemblies. Data from all operating plants have indicated that the actual flow has been well above the flow specified for the thermal design of the plant. By applying the design procedure described below, it is possible to

specify the expected operating flow with reasonable

accuracy. 5.1-5 Rev. 0 WOLF CREEK Three reactor coolant flow rates are identified for the various plant design considerations. The definitions of

these flows are presented in the following paragraphs.

b. Best estimate flow The best estimate flow is the most likely value for the actual plant operating condition. This flow is based on the

best estimate of the flow resistances in the reactor vessel, steam generator, and piping and on the best estimate of the

reactor coolant pump head-flow capacity, with no uncertainties assigned to either the system flow resistance or the pump head. System pressure drops, based on best estimate flow, are presented in Table 5.1-1.

Although the best estimate flow is the most likely value to be expected in operation, more conservative flow rates are

applied in the thermal and mechanical designs.

c. Thermal design flow

Thermal design flow is the flow rate used as a basis for the reactor core thermal performance, the steam generator

thermal performance, and the nominal plant parameters used

throughout the design. The thermal design flow accounts for the uncertainties in flow resistances (reactor vessel, steam generator, and piping), reactor coolant pump head, and the

methods used to measure flow rate. The thermal design flow

is approximately 8.9 percent less than the best estimate flow. The thermal design flow is confirmed when the plant is placed in operation. Tabulations of important design and

performance characteristics of the RCS, as provided in

Table 5.1-1, are based on the thermal design flow.

d. Mechanical design flow

Mechanical design flow is a conservatively high flow used in the mechanical design of the reactor vessel internals and fuel assemblies. The mechanical design flow is based on a

reduced system resistance and on increased pump head

capability. The mechanical design flow is approximately 2.6 percent greater than the best estimate flow. 5.1-6 Rev. 13 WOLF CREEK Pump overspeed due to a turbine generator overspeed of 20 percent results in a peak reactor coolant flow of 120

percent of the mechanical design flow. The overspeed condition is applicable only to operating conditions when the reactor and turbine generator are at power.

e. Flows with one pump shut down The design procedure for calculation of flows with one pump shut down is similar to the procedure described above for

calculating flows with all pumps operating.

• For the case where reverse flow exists in the idle loop, the system resistance incorporates the idle loop reverse flow resistance with a stationary pump impeller as a flow path in parallel with the reactor vessel internals.

The thermal design flow uncertainty includes a conservative application of parallel flow uncertainties (reactor

internals high, idle loop low) as well as the usual

component, pump, and flow measurement uncertainties, thereby

resulting in a conservatively low reactor flow rate for the

thermal design. The mechanical design flow uncertainty is

increased slightly to account for the slightly higher

uncertainties at the higher pump flows.

________________

• In reality, WCGS Technical Specifications require a shutdown to hot standby (Mode 3) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a shutdown of a reactor coolant pump when in Mode 1 or 2. Continuous 3 pump operation is not permitted. 5.1-7 Rev. 13 WOLF CREEK TABL E 5.1-1 SYST EM DESIGN AND OP ERATING PARAM ETERSPlant design life, years 40 Nominal operating pressure, psig 2,235 Total system volume, including 12,135

+/-100* pressurizer and surge line, ft 3System liquid volume, including 11,393 pressurizer water at maximum guaranteed power, ft 3Pressurizer spray rate, maximum, gpm 900 Pressurizer heater capacity, kW 1,800 System Thermal and Hydraulic Data 4 Pumps Running NSSS power, MWt 3,579 Reactor power, MWt 3,565

Thermal design flows, gpm Active loop 90,324 (10% SGTP)

Idle loop --

Reactor (core flow only) 336,366 (10% SGTP)

Total reactor flow, 10 6 lb/hr 134.7 Temperatures, °F

Reactor vessel outlet 621.1 Reactor vessel inlet 555.8 Steam generator outlet 555.5

Steam generator steam 537.6

Feedwater 446.0

• at a nominal T avg of 557°FRev. 13 WOLF CREEK TABL E 5.1-1 (Sheet 2)

System Thermal and Hydraulic Data 4 Pumps Running Steam pressure, psia 944 Total steam flow, lO 6 lb/hr 15.92 Best estimate flows, gpm Active loop 101,600 (0% SGTP) 99,200 (10% SGTP)

Idle loop --

Reactor (core flow only) 378,350 (0% SGTP) 369,420 (10% SGTP)

Mechanical design flows, gpm

Active loop 104,200 (0% SGTP)

Idle loop --

Reactor (core flow only) 388,040 (0% SGTP)

System Pressure Drops

+(Tavg = 570.7°F)(Tavg = 588.4°F)Reactor vessel P, psi48.647.4 Steam generator P, psi46.645.5 Hot leg piping P, psi1.21.2 Crossover leg piping P, psi3.23.1 Cold leg piping P, psi3.4*3.3*Pump head, ft312312

+Original Design Date

• Includes pump weir P of 2.0 psi.

Rev. 13 WOLF CREEK STEAM GENERATOR NOTES: THIS DIAGRAM IS A SIMPLIFICATION OF THE SYSTEM INTENDED TO FACIUATE THE UNDERSTANDING OF THE PROCESS.

FOR DETAILS OF THE PIPING, VALVES, INSTRUMENTATION, ETC. REFER TO TH£ ENGINEERING FLOW DIAGRAM.

REFER TO PROCESS FLOW DIAGRAM TABLES FOR THE CONDITIONS AT EACH NUMBERED POINT. STEAM GENERATOR LOOP3 LOOP4 tSEE NOTES ON THE FOLLOWING PAGESt WOLF CREEK UPDATED SAFETY ANALYSIS REPORT Figure 5.1-2, REV. 20 REACTOR COOLANT SYSTEM PROCESS FLOW DIAGRAM WOLFCREEKNOTESTOFIGURE5.1-2ModeASteadyStateFullPowerOperationKey:BasisnumbersNSSS3579MWtforT hotMaintained@10%SGTubePlugging()numbersNSSS3579MWtfor15°FT hotReduction@10%SGTubePluggingLocationFluid Pressure(2)(psig)Temperature

(°F)Flowgpm(1)Volume(cu.ft.)1ReactorCoolant2,236.2(2,236.2) 618.3(601.4)110,871(109,522)

-2ReactorCoolant2,235.0(2,235.0) 618.3(601.4)110,875(109,526)

-3ReactorCoolant2,189.5(2,188.4) 558.2(539.7)99,310(99,294)-4ReactorCoolant2,186.4(2,185.2) 558.2(539.7)99,315(99,298)-5ReactorCoolant2,286.9(2,288.2) 558.5(540.0)99,200(99,200)-6ReactorCoolant2,283.6(2,284.8) 558.5(540.0)99,205(99,204)-10-15Reactor CoolantSeeLoop#1Specifications19-24Reactor CoolantSeeLoop#1Specifications28-33Reactor CoolantSeeLoop#1Specifications37Reactor Coolant2,286.9(2,288.2) 558.5(540.0)1.0(1.0)-38Reactor Coolant2,286.9(2,288.2) 558.5(540.0)1.0(1.0)-39Reactor Coolant2,286.9(2,288.2) 558.5(540.0)2.0(2.0)-Rev.13 WOLFCREEKNOTESTOFIGURE5.1-2(Sheet2)ModeASteadyStateFullPowerOperationLocationFluidPressure (2)(psig)Temperature (F)Flowgpm(1)Volume (cu.ft.)40Steam2,235.0652.772041Reactor2,235.0652.71,080 coolant42Reactor2,235.0652.72.5-coolant43Reactor2,235.0652.72.5-coolant44Steam2,235.0652.70-45Reactor2,235.0<652.70-coolant46N23.01200-47Reactor2,235.0<652.70-coolant48N23.01200-49N23.01200-50N23.0120-45051Pres-3.0120-1,350 surizer relieftank

water52Steam/H 22,235.05590-53Reactor3.01200-coolant54Reactor501700-coolant(1)Attheconditionsspecified.(2)Pressuresreflectnonrecoverablelossesonly(

ElevationPsarenotincluded)Rev.13 WOLF CREEK 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY This section discusses the measures employed to provide and maintain the

integrity of the reactor coolant pressure boundary (RCPB) for the plant design

lifetime. Section 50.2 of 10 CFR 50 defines the RCPB as extending to the outermost containment isolation valve in system piping which penetrates the

containment and is connected to the RCS. This section is limited to a

description of the components of the RCS as defined in Section 5.1, unless

otherwise noted. Components

• which are part of the RCPB (as defined in 10 CFR

50) but are not described in this section are described in the following

sections:

a. Section 6.3 - RCPB components which are part of the

emergency core cooling system.

b. Section 9.3.4 - RCPB components which are part of the chemical and volume control system.

c. Section 3.9(N).1 - Design loadings, stress limits, and

analyses applied to the RCS and ASME Code Class 1

components.

d. Section 3.9(N).3 - Design loadings, stress limits, and

analyses applied to ASME Code Class 2 and 3 components.

The phrase RCS, as used in this section, is as defined in Section 5.1. When

the term RCPB is used in this section, its definition is that of Section 50.2

of 10 CFR 50.

5.2.1 COMPLIANCE WITH CODES AND CODE CASES 5.2.1.1 Compliance with 10 CFR 50.55a RCS components are designed and fabricated in accordance with 10 CFR 50,

Section 50.55a, "Codes and Standards" except as described below. The addenda of the ASME Code applied in the design of each component are listed in Table

5.2-1.

All components located within the reactor coolant pressure boundary (as defined by 10CFR50.2) are classified as required by 10CFR50.55a with the exception of the pressurizer upper level instrument lines, the pressurizer safety valve loop seal drain lines, 3/4" and smaller branch lines connected to the pressurizer relief lines, and the associated components. These lines are Safety Class 2 although a rupture of one of these lines may result in a rapid depressurization of the reactor coolant system and ECCS actuation on low pressurizer pressure.

Relief from the requirements of 10CFR50.55a was authorized by the NRC in accordance with 10CFR50.55a(a)(3)(ii) to allow these lines to remain Safety Class 2 (Reference 11).

5.2.1.2 Applicable Code Cases

Regulatory Guides 1.84 and 1.85 are discussed in Appendix 3A.

Code Case 1528 (SA-508, Class 2a) material was used in the manufacture of the WCGS steam generators and pressurizer. At the time of initial application,

Regulatory Guide 1.85 reflected a conditional NRC approval of Code Case 1528.

Westinghouse conducted a test program which demonstrated the adequacy of Code

Case 1528 material. The results of the test program are documented in

Reference 1.

• A component is considered to be any piece or portion of equipment below the system level but above the part level.

5.2-1 Rev. 19 WOLF CREEK Reference 1 was submitted to the NRC by Reference 2.

The specific code cases used for Wolf Creek are:

Steam Generator: 1484 and 1528

Pressurizer: 1528-3

Piping: 1423-2, N-411, N-391, N-392 & N-318-3*, 1606-1 (N-53)

Valves: 1649, 1769, 1567 and N-3-10

5.2.2 OVERPRESSURE PROTECTION

RCS overpressure protection is accomplished by the utilization of pressurizer safety valves along with the reactor protection system and associated

equipment. Combinations of these systems provide compliance with the

overpressure requirements of the ASME Boiler and Pressure Vessel Code, Section

III, Paragraphs NB-7300 and NC-7300, for pressurized water reactor systems.

Auxiliary or emergency systems connected to the RCS are not utilized for the

prevention of RCS overpressurization protection.

Selected overpressure protection measures for the secondary side are also

described in these sections.

5.2.2.1 Design Bases Overpressure protection is provided for the RCS by the pressurizer safety

valves which discharge to the pressurizer relief tank by means of a common

header. The transient which established the design requirements for the primary system overpressure protection is a complete loss of steam flow to the

turbine with operation of the steam generator safety valves and maintenance of

main feedwater flow. However, for the sizing of the pressurizer safety valves,

no credit is taken for reactor trip nor the operation of the following:

a. Pressurizer power-operated relief valves

b. Steam line atmospheric relief valve

c. Steam dump system

d. Reactor control system

e. Pressurizer level control system

f. Pressurizer spray valve

For this transient, the peak RCS and peak steam system pressure are limited to

110 percent of their respective design values.

• Code Case N-318 provides several conditions for lug attachment evaluation snubber reduction program (Ref. 13) has listed all stress calculation numbers that used N-318 in class 2 and 3 pipe lines. Lug locations are available in pipe support drawings.

5.2-2 Rev. 21 WOLF CREEK Assumptions for the overpressure analysis include: 1) the plant is operating

at the power level corresponding to the engineered safeguards design rating and

2) the RCS average temperature and pressure are at their maximum values. These

assumptions are the most limiting with respect to system overpressure.

Overpressure protection for the steam system is provided by steam generator

safety valves. The steam system safety valve capacity is based on providing

enough relief to remove 105 percent of the engineered safeguards design steam

flow. This relief capacity may be provided while limiting the maximum steam

system pressure to less than 110 percent of the steam generator shell side

design pressure.

Blowdown and heat dissipation systems of the NSSS connected to the discharge of

pressure relieving devices are discussed in Section 5.4.11, pressurizer relief discharge system.

Steam generator blowdown systems for the balance-of-plant are discussed in

Section 10.4.8.

Postulated events and transients on which the design requirements of the

overpressure protection system are based are discussed in Reference 3.

5.2.2.2 Design Evaluation The relief capacities of the pressurizer and steam generator safety valves are

determined from the postulated overpressure transient conditions in conjunction

with the action of the reactor protection system. An evaluation of the functional design of the system to perform its function is presented in

Reference 3. The results of the analysis performed at the uprated power

condition also confirm that the design of the overpressure protection system

will continue to perform its function under uprated power condition. The

analysis showed that when the first reactor protection system trip signal

(following a direct reactor trip signal on turbine trip) was ignored, the

primary and secondary coolant overpressure protection systems provided

sufficient pressure relief to ensure that the peak pressure of both coolant

systems remained below the Technical Specification limit of 110% of their

respective design pressures. The analysis further demonstrated that, when the second and third trip signals were ignored, the overpressure protection systems maintained the primary and secondary coolant pressures below 110% of their

design pressures and thus confirmed adequate safety valve sizing exists under

uprated power conditions.

5.2-3 Rev. 8 WOLF CREEK Reference 3 describes in detail the types and number of pressure relief devices employed, relief device description, locations in the systems, reliability

history, and the details of the methods used for relief device sizing based on

typical worst-case transient conditions and analysis data for each transient

condition. The description of the analytical model used in the analysis of the overpressure protection system and the basis for its validity are discussed in

Reference 8. An evaluation of the overpressure protection system's design was

performed to ensure that the conclusions presented in Reference 3 remain valid

under the uprated power conditions. The evaluation followed the methodology

presented in Reference 3 utilizing the analytical model described in Reference

8.

A description of the pressurizer safety valves performance characteristics

along with the design description of the incidents, assumptions made, method of

analysis, and conclusions are discussed in Chapter 15.0.

5.2.2.3 Piping and Instrumentation Diagrams Overpressure protection for the RCS is provided by pressurizer safety valves

shown in Figure 5.1-1, Sheet 2.

These discharge to the pressurizer relief tank by means of a common header.

The steam system safety valves are discussed in Section 10.3 and are shown on

Figure 10.3-1, Sheet 2.

5.2.2.4 Equipment and Component Description The operation, significant design parameters, number and types of operating

cycles, and environmental conditions of the pressurizer safety valves are

discussed in Sections 5.4.13, 3.9(N).1, and 3.11(N).

Section 10.3 contains a discussion of the equipment and components of the steam

system overpressure system.

5.2.2.5 Mounting of Pressure-Relief Devices The design bases for the assumed loads for the primary and secondary side

pressure relief devices of the steam generator are described in Paragraph

3.9(B).3.3.

5.2.2.5.1 Location of Pressure Relief Devices

Figure 5.2-1 provides typical design and installation details for pressure

relief devices mounted on the secondary side of the steam generator. Pressure

relief devices for the reactor coolant system are three pressurizer safety

relief valves and two power-operated relief valves. These valves discharge to

the pressurizer relief tank via a common header.

5.2-4 Rev. 13 WOLF CREEK 5.2.2.5.2 Pressurizer Safety Relief Valves

The pressurizer safely valve discharge piping system is a closed system in

which no sustained reaction force from a free discharging jet of fluid can exist. However, transient hydraulic forces are imposed at various points in

the piping system from the time a safety valve begins to open until a steady

flow is completely developed. Since a water loop seal is applied, transient

hydraulic forces caused by the liquid being forced through the safety valve and

then accelerated down the piping system does occur.

The pressurizer relief devices are mounted and installed as follows:

a. Each straight leg of the discharge pipe is supported to

take the valve discharge transient force along that leg.

b. The supports at the valve discharge piping are connected

to the adjacent structure.

c. Snubbers are used to restrain the valve discharge

transient forces when thermal movements are of a high

magnitude.

Subprogram RVDFT (relief valve discharge flow transients) was used to predict

the transient flows resulting from actuation of a safety relief valve under

normal operating conditions. It also predicted the resulting piping loads as a

function of time to be used as dynamic forcing functions for structural design

of discharge piping and its supporting components. The computation was based

on finite difference solutions by the method of effluent characteristics. The

computed transient forces were then used to calculate loads on pipe bends and on pipe runs.

A static analysis was performed for thermal, weight, and seismic anchor

movement loadings on the discharge piping. A dynamic analysis for seismic and

valve discharge loadings was also performed to verify the design of the support

configuration. The results of these analyses are described below:

a. For loading combinations see Table 3.9(B)-2.

b. Material Type

Class I Piping 3" Sch. 160, SA-312, TP-304

6" Sch. 160, SA-312, TP-304

B31.1 Piping 3" Sch. 80S, SA-312, TP-304

6" Sch. 80S, SA-312, TP-304

12" Sch. 80S, SA-312, TP-304

5.2-5 Rev. 13 WOLF CREEK

c. Maximum stress points within piping system

Class I Piping Node point - 405

Type - reducer Max. primary stress 18,092 psi

Allowable primary stress 24,282 psi

B31.1 Piping Node point - 310

Max. primary stress 14,811 psi

Allowable primary stress 22,560 psi

Node point - 555

Max. primary + secondary

stress 33,995 psi

Allowable primary +

secondary stress 43,375 psi 5.2.2.5.3 Main Steam Safety Relief Valves

Figure 5.2-1 provides design and installation details.

The steady-state flow condition reached after the valve has opened and is

exhausting into the stack was considered in the stress analysis of the safety

valve installation. With these conditions, the valve moments are balanced due

to the split valve discharge design, and the vertical discharge thrust force is

reacted by the header supports via the header. The discharge force from the

vent stack is reacted by an in-line anchor and the supports near the top of the

stack. The effects of thermal expansion, pipe weight, seismic anchor

movements, seismic occurrence, and relief valve discharge thrust forces were

considered in the stress analysis of the vent stack piping. These effects were

also considered in the stress analysis of the main steam header piping in addition to the water hammer effects caused by fast valve closure of the main steam isolation valves.

A 10 percent unbalanced discharge from the two split discharge ports of each

safety valve was assumed for the stress analysis of the header piping.

Therefore, one discharge port had an assumed vertical thrust load of 13,574

pounds and the other an assumed thrust load of 12,227 pounds. These values are

based on a relief valve discharge from a line pressure of 1,185 psi and a

dynamic load factor of 1.2. It was conservatively assumed that each valve

opened simultaneously, resulting in the following header stresses and support

loads:

a. For loading combinations see Table 3.9(B)-2 and Table

3.9(B)-10.

5.2-6 Rev. 0 WOLF CREEK

b. Material type

28-inch OD wall thickness of 1.5 inch, SA 106, Gr C.

c. Maximum stress points within system Node point - 83

Maximum primary stress 9,287 psi

Allowable primary stress 21,000 psi

Node point - 5

Maximum secondary stress 4,112 psi

Allowable secondary stress 26,250 psi

d. Support loads

Header Support Loads

(vertical supports and Node Point loads only)

5 21,942 lbs

33 187,800 lbs

83 112,700 lbs

85 166,300 lbs

300 33,347 lbs

294 187,800 lbs

282 112,700 lbs

281 166,300 lbs

347 33,362 lbs

341 187,800 lbs

329 112,700 lbs

328 166,300 lbs

397 10,100 lbs 391 184,400 lbs 380 112,800 lbs

379 166,300 lbs

5.2.2.6 Applicable Codes and Classification The requirements of ASME Boiler and Pressure Vessel Code,Section III,

Paragraphs NB-7300 (Overpressure Protection Report) and NC-7300 (Overpressure

Protection Analysis), are followed and complied with for pressurized water reactor systems.

Piping, valves, and associated equipment used for overpressure protection are

classified in accordance with ANS-N18.2, "Nuclear Safety Criteria for the

Design of Stationary Pressurized Water Reactor Plants." These safety class

designations are delineated on Table 3.2-1 and shown on Figure 5.1-1.

For further information, refer to Section 3.9(N).

5.2-7 Rev. 0 WOLF CREEK 5.2.2.7 Material Specifications

Refer to Section 5.2.3 for a description of material specifications.

5.2.2.8 Process Instrumentation

Each pressurizer safety valve discharge line incorporates a control board

temperature indicator and alarm to notify the operator of steam discharge due

to either leakage or actual valve operation. Safety-related control room positive position indication is provided for the PORVs and safety valves. For

a further discussion on process instrumentation associated with the system,

refer to Chapter 7.0.

5.2.2.9 System Reliability The reliability of the pressure relieving devices is discussed in Section 4 of

Reference 3.

5.2.2.10 RCS Pressure Control During Low Temperature Operation Administrative procedures were developed to aid the operator in controlling RCS

pressure during low temperature operation. However, to provide a back-up to

the operator and to minimize the frequency of RCS overpressurization, an automatic system is provided to maintain pressures within allowable limits.

Analyses have shown that one pressurizer power-operated relief valve is

sufficient to prevent violation of these limits due to anticipated mass and

heat input transients. However, redundant protection against an

overpressurization event is provided through the use of two pressurizer power-

operated relief valves to mitigate any potential pressure transients. The

mitigation system is required only during low temperature water solid operation

when it is manually armed and automatically actuated.

5.2.2.10.1 System Operation

Two pressurizer power-operated relief valves are supplied with actuation logic

to ensure that a redundant and independent RCS pressure control back-up feature

is provided for the operator during low temperature operations. This system

provides the capability for RCS inventory letdown, thereby maintaining RCS

pressure within allowable limits. Refer to Sections 5.4.7, 5.4.10, 5.4.13,

7.6.6, and 9.3.4 for additional information on RCS pressure and inventory

control during other modes of operation.

5.2-8 Rev. 13 WOLF CREEK The basic function of the system logic is to continuously monitor RCS

temperature and pressure conditions whenever plant operation is at low

temperatures. An auctioneered system temperature is continuously converted to

an allowable pressure and then compared to the actual RCS pressure. The system logic first annunciates a main control board alarm whenever the measured

pressure approaches within a predetermined amount of the allowable pressure

thereby indicating that a pressure transient is occurring. On a further

increase in measured pressure, an actuation signal is transmitted to the

pressurizer power-operated relief valves when required to mitigate the pressure

transient.

5.2.2.10.2 Evaluation of Low Temperature Overpressure Transients

The ASME Code (Section III, Appendix G) establishes guidelines and upper limits for RCS pressure primarily for low temperature conditions less than approximately 350 F. The mitigation system discussed in Section 5.2.2.10.1

addresses these conditions as discussed in the following paragraphs.

Two specific transients: mass input and heat input, with the RCS in a water-

solid condition; have been considered as the design basis for the Low Temperature Overpressure Protection (LTOP) system. Each of these scenarios assumes as an initial condition that the RHRS is isolated from the RCS, and thus the relief capability of the RHRS relief valves is not available.

Transient analyses have been performed to determine the maximum pressure for

the postulated mass input and heat input events.

The LTOP PORV setpoint limit curve (PTLR Figure 2.2-1) is determined based on the updated heatup and cooldown limit curves, and the analysis results of limiting Low Temperature Over-Pressure (LTOP) transients. The methodology for

this determination is given in Reference 10. The limiting LTOP mechanisms

analyzed for WCGS under water solid conditions were:

a. FOR LIMITING MASS ADDITION LTOP MECHANISM Operation of one Centrifugal Charging Pump (CCP) and the Normal

Charging Pump (NCP) with instrument air failure resulting in the

flow control valve in the letdown line failing closed (letdown

isolation) and the flow control valve in the charging line failing

open (maximum charging flow), and

b. FOR LIMITING HEAT ADDITION LTOP MECHANISM Inadvertent start-up of a reactor coolant pump with a maximum 50F temperature mismatch between the RCS and the hotter steam generators.

These analyses, using the LOFTRAN computer code, take into consideration

pressure overshoot and undershoot beyond the PORV open and close setpoints,

which can occur as a result of time delays in signal processing and valve

stroke times. The maximum expected pressure overshoot and undershoot

calculated from the limiting mass input and heat input transients, in

conjunction with the 10 CFR 50, Appendix G, pressure limits and reactor coolant

pump No. 1 seal pressure limit, are utilized in the selection of the pressure

setpoints for the PORV. The mass injection rate assumed in the design basis

mass input transient is based on 100% flow capacity of the NCP and one CCP.

The maximum combined pump flow has been assumed in order to envelop the maximum

flow possible by the operational configuration that uses the NCP for charging with one CCP remaining operable, or the use of one CCP for charging with the NCP remaining operable, during shutdown modes.

5.2-9 Rev. 23 WOLF CREEK Both the heat input and mass input analyses take into account the single failure criteria and therefore, only one pressurizer power-operated relief

valve was assumed to be available for pressure relief. The above events have

been evaluated considering the allowable pressure/temperature limits

established by the Appendix G guidelines. The evaluation of the transient results concluded that reactor vessel integrity is not impaired.

5.2.2.10.3 Operating Basis Earthquake Evaluation

A fluid systems evaluation has been performed considering the potential for

overpressure transients following an operating basis earthquake.

The pressurizer power-operated relief valves have been designed in accordance

with the ASME Code and seismically qualified under the Westinghouse valve

operability program which is discussed in Section 3.9(N).3.2.

Therefore, the overpressurizer mitigation system is available to provide

pressure relief following an operating basis earthquake.

5.2.2.10.4 Administrative Procedures

Although the system described in Section 5.2.2.10.1 was installed to maintain

RCS pressure within allowable limits, administrative procedures minimize the

potential for and the consequences of any transient that could actuate the

over-pressure relief system. The following discussion highlights these

procedural controls, listed in hierarchy of their function in mitigating RCS

cold overpressurization transients.

5.2.2.10.4.1 Normal and Transitional Operation

Of primary importance is the basic method of operation of the plant. Normal plant operating procedures maximize the use of a pressurizer cushion (steam

bubble) during periods of low pressure, low temperature operation. This

cushion dampens the plants' response to potential transient generating inputs,

providing easier pressure control with the slower response rates.

An adequate cushion substantially reduces the severity of potential pressure

transients, such as reactor coolant pump induced heat input, and slows the rate

of pressure rise for others. In conjunction with the alarms discussed in

Section 7.6, this provides reasonable assurance that most potential transients

can be terminated by operator action before the overpressure relief system

actuates.

However, for those modes of operation when water solid operation may still be

possible, procedures further highlight precautions that minimize the severity

of, or the potential for, developing an overpressurization transient. The

following precautions or measures were considered in developing the operating

procedures:

a. The residual heat removal inlet lines from the reactor

coolant loop are normally open when the RCS pressure is

less than 425 psig. This precaution assures that there

5.2-10 Rev. 14 WOLF CREEK is a relief path from the reactor coolant loop to the

residual heat removal suction line relief valves when

the RCS is at low pressure and is water solid.

b. Whenever the plant is water solid and the reactor

coolant pressure is being maintained by the low pressure

letdown control valve, letdown flow normally bypasses

the normal letdown orifices. In addition, all three

letdown orifices may be open.

c. If all reactor coolant pumps have stopped for more than

5 minutes during plant heatup and the reactor coolant

temperature is greater than the charging and seal

injection water temperature, a steam bubble is formed in the pressurizer prior to restarting a reactor coolant pump. This precaution minimizes the pressure transient

when the pump is started and the cold water previously

injected by the charging pumps is circulated through the

warmer reactor coolant components. The steam bubble

accommodates the resultant expansion as the cold water

is rapidly warmed.

d. If all reactor coolant pumps are stopped and the RCS is

being cooled down by the residual heat exchangers, a

nonuniform temperature distribution may occur in the

reactor coolant loops. Prior to restarting a reactor

coolant pump, a steam bubble is formed in the

pressurizer or an acceptable temperature profile is

demonstrated.

e. During plant cooldown, all steam generators are normally

connected to the steam header to assure a uniform

cooldown of the reactor coolant loops.

f. At least one reactor coolant pump normally remains in

service until the reactor coolant temperature is reduced

to 160 F.

These special precautions back-up the normal operational mode of maximizing

periods of steam bubble operation so that cold overpressure transient

prevention is continued during periods of transitional operations. These

precautions do not apply to reactor coolant system hydrostatic testing.

The specific plant configurations of emergency core cooling system testing and

alignment also highlight procedural recommendations to prevent developing cold

overpressurization transients.

5.2-11 Rev. 13 WOLF CREEK During these limited periods of plant operation, the following

precautions/measures were considered in developing the operating procedures:

a. To preclude inadvertent emergency core cooling system actuation during heatup and cooldown, procedures require

blocking the low pressurizer pressure, and low steam line

pressure signal actuation logic at 1,900 psig.

b. During further cooldown, closure and power lockout of the accumulator isolation valves with one centrifugal charging pump and both safety injection pumps rendered incapable of injecting into the RCS in accordance with WCGS Technical Specifications, provide additional back-up to item a above.

c. The recommended procedure for periodic emergency core

cooling system pump performance testing is to test the

pumps during normal power operation or at hot shutdown

conditions. This precludes any potential for developing

a cold overpressurization transient.

Should CSD testing of the pumps be desired, the test is

done when the vessel is open to atmosphere, again

precluding overpressurization potential.

If CSD testing with the vessel closed is necessary, the

procedures require emergency core cooling system pumps

discharge valve closure and RHRS alignment to isolate

potential emergency core cooling system pump input and to provide back-up benefit of the RHRS relief valves.

d. SIS circuitry testing, if done during CSD, requires RHRS alignment and one centrifugal charging pump and both safety injection pumps rendered incapable of injecting into the RCS to preclude developing cold overpressurization transients.

The above procedural precautions covering normal operations with a steam

bubble, transitional operations where potentially water solid, and specific

testing operations provide in-depth cold overpressure preventions or

reductions, augmenting the installed overpressure relief system.

5.2.2.10.4.2 Failure of Both PORVs

Should both of the PORVs fail closed at a time when the RHR letdown isolation

valves for either or both RHR loops are open, the RCS is protected from

overpressurization by the RHR inlet relief

5.2-12 Rev. 13 WOLF CREEK valves. Although the valves are only required to relieve the flow of a single

centrifugal charging pump delivering at its maximum rate, the valves are each

conservatively sized to relieve the combined flow of both centrifugal charging

pumps at a setpoint of 450 psig.

During normal startup and shutdown, a pressurizer bubble is maintained whenever

the RHR system is isolated. The normal steam bubble volume in this condition

would be approximately 1350 ft

3. Should normal letdown be isolated, the maximum makeup rate imbalance would be determined by the head/flow curve of the

centrifugal charging pump, which could be in operation. This rate would

actually be much less as the transient progressed, since the charging flow

control system would throttle the flow to try to maintain pressurizer level.

However, even if no credit is taken for the charging control system, and

assuming that the pressurizer level is initially at the high level alarm setpoint (i.e., approximately 567 ft 3 steam bubble), the plant operator would have greater than 10 minutes to terminate the event to prevent overfill of the pressurizer.

5.2.2.11 Testing and Inspection Testing and inspection of the overpressure protection components are discussed

in Section 5.4.13.4 and Chapter 14.0.

5.2.3 MATERIALS SELECTION, FABRICATION, AND PROCESSING

5.2.3.1 Material Specifications Material specifications used for the principal pressure retaining applications

in components of the RCPB are listed in Table 5.2-2 for ASME Class 1 primary

components and Table 5.2-3 for ASME Class 1 and 2 auxiliary components. Tables 5.2-2 and 5.2-3 also include the material specifications of unstabilized

austenitic stainless steel used for components in systems required for reactor

shutdown and for emergency core cooling.

The material specifications of unstabilized austenitic stainless steel used for

reactor vessel internals which are essential for emergency core cooling and for

core structural support are listed in Table 5.2-4.

Table 5.2-3 is not totally inclusive of the material specifications used in the

listed applications. However, the listed specifications are representative.

The materials utilized conform to the applicable ASME Code rules.

The welding materials used for joining the ferritic base materials of the RCPB

conform to or are equivalent to ASME Material Specifications SFA 5.1, 5.2, 5.5,

5.17, 5.18, and 5.20. They are qualified to the requirements of the ASME Code,

Section III.

5.2-13 Rev. 13 WOLF CREEK The welding materials used for joining the austenitic stainless steel base

materials of the RCPB conform to ASME Material Specifications SFA 5.4 and 5.9.

They are qualified to the requirements of the ASME Code,Section III.

The welding materials used for joining nickel-chromium-iron alloy in similar

base material combination and in dissimilar ferritic or austenitic base

material combination conform to ASME Material Specifications SFA 5.11 and 5.14.

They are qualified to the requirements of the ASME Code,Section III.

5.2.3.2 Compatibility With Reactor Coolant 5.2.3.2.1 Chemistry of Reactor Coolant

The RCS chemistry specifications are given in Table 5.2-5.

The RCS water chemistry is selected to minimize corrosion. Routinely scheduled

analyses of the coolant chemical composition are performed to verify that the

reactor coolant chemistry meets the specifications.

The chemical and volume control system provides a means for adding chemicals to

the RCS which perform the following functions: 1) control the pH of the

coolant during pre-startup testing and subsequent operation, 2) scavenge oxygen

from the coolant during heatup, and 3) control radiolysis reactions involving

hydrogen, oxygen, and nitrogen during all power operations subsequent to startup. The normal limits for chemical additives and reactor coolant impurities for power operation are shown in Table 5.2-5.

The pH control chemical utilized is lithium hydroxide monohydrate, enriched in

the lithium-7 isotope to 99.9 percent. This chemical is chosen for its

compatibility with the materials and water chemistry of borated water/stainless

steel/zirconium/inconel systems. In addition, lithium-7 is produced in

solution from the neutron irradiation of the dissolved boron in the coolant.

The lithium-7 hydroxide is introduced into the RCS via the charging flow. The

solution is prepared in the laboratory and transferred to the chemical additive

tank. Reactor makeup water is then used to flush the solution to the suction

header of the charging pumps. The concentration of lithium-7 hydroxide in the

RCS is maintained in the range specified for pH control. If the concentration

exceeds this range, the cation bed demineralizer is employed in the letdown

line in series operation with the mixed bed demineralizer.

5.2-14 Rev. 0 WOLF CREEK During reactor startup from the cold condition, hydrazine is employed as an

oxygen scavenging agent. The hydrazine solution is introduced in accordance

with plant operating procedures.

The reactor coolant is treated with dissolved hydrogen to control the net

decomposition of water by radiolysis in the core region. The hydrogen also

reacts with oxygen and nitrogen introduced into the RCS as impurities under the

impetus of core radiation. Sufficient partial pressure of hydrogen is

maintained in the volume control tank so that the specified equilibrium

concentration of hydrogen is maintained in the reactor coolant. A self-

contained pressure control valve maintains a minimum pressure in the vapor

space of the volume control tank. This can be adjusted to provide the correct

equilibrium hydrogen concentration.

Boron, in the chemical form of boric acid, is added to the RCS for long-term reactivity control of the core.

Suspended solids (corrosion product particulates) and other impurity

concentrations are maintained below specified limits by controlling the

chemical quality of makeup water and chemical additives and by purification of

the reactor coolant through the chemical and volume control system mixed bed

demineralizer.

5.2.3.2.2 Compatibility of Construction Materials with

Reactor Coolant

All of the ferritic low alloy and carbon steels which are used in principal

pressure retaining applications have corrosion resistant cladding on all

surfaces that are exposed to the reactor coolant. The corrosion resistance of the cladding material is at least equivalent to the corrosion resistance of Types 304 and 316 austenitic stainless steel alloys or nickel-chromium-iron

alloy, martensitic stainless steel, and precipitation hardened stainless steel.

The cladding of ferritic type base materials receives a post-weld heat

treatment, as required by the ASME Code.

Ferritic low alloy and carbon steel nozzles have safe ends of either stainless

steel wrought materials, stainless steel weld metal analysis A-7 (designated A-

8 in the 1974 Edition of the ASME Code), or nickel-chromium-iron alloy weld

metal F-Number 43. The latter buttering material requires further safe ending

with austenitic stainless steel base material after completion of the post-weld

heat treatment when the nozzle is larger than a 4-inch nominal inside diameter

and/or the wall thickness is greater than 0.531 inches.

5.2-15 Rev. 16 WOLF CREEK All of the austenitic stainless steel and nickel-chromium-iron alloy base materials with primary pressure retaining applications are used in the solution

anneal heat treat condition. These heat treatments are as required by the

material specifications.

During subsequent fabrication, these materials are not heated above 800 F other

than locally by welding operations. The solution annealed surge line material

is subsequently formed by hot bending followed by a resolution annealing heat

treatment.

Components with stainless steel sensitized in the manner expected during

component fabrication and installation will operate satisfactorily under normal

plant chemistry conditions in pressurized water reactor systems because

chlorides, fluorides, and oxygen are controlled to very low levels.

5.2.3.2.3 Compatibility with External Insulation and

Environmental Atmosphere

In general, all of the materials listed in Tables 5.2-2 and 5.2-3 which are

used in principal pressure-retaining applications and which are subject to

elevated temperature during system operation are in contact with thermal

insulation that covers their outer surfaces.

The thermal insulation used on the RCPB is either the reflective stainless

steel type or made of compounded materials which yield low leachable chloride

and/or fluoride concentrations. The compounded materials in the form of

blocks, boards, cloths, tapes, adhesives, cements, etc., are silicated to

provide protection of austenitic stainless steels against stress corrosion

which may result from accidental wetting of the insulation by spillage, minor leakage, or other contamination from the environmental atmosphere. Appendix 3A includes a discussion which indicates the degree of conformance with Regulatory

Guide 1.36, "Nonmetallic Thermal Insulation for Austenitic Stainless Steel."

In the event of coolant leakage, the ferritic materials will show increased

general corrosion rates. Where minor leakage is anticipated from service

experience, such as valve packing, pump seals, etc., only materials which are

compatible with the coolant are used. These are as shown in Tables 5.2-2 and

5.2-3. Ferritic materials exposed to coolant leakage can be readily observed

as part of the inservice visual and/or nondestructive inspection program to

assure the integrity of the component for subsequent service.

5.2-16 Rev. 0 WOLF CREEK 5.2.3.3 Fabrication and Processing of Ferritic Materials

5.2.3.3.1 Fracture Toughness

The fracture toughness properties of the RCPB components meet the requirements of the ASME Code,Section III, Paragraphs NB, NC, and ND-2300 as appropriate.

The fracture toughness properties of the reactor vessel materials are discussed

in Section 5.3.

Limiting steam generator and pressurizer RTNDT temperatures are guaranteed at

60 F for the base materials and the weldments. These materials meet the 50 ft-

lb absorbed energy and 35 mils lateral expansion requirements of the ASME Code,

Section III at 120 F. The actual results of these tests are provided in the

ASME material data reports which are supplied for each component and submitted to the owner at the time of shipment of the component.

Calibration of temperature instruments and Charpy impact test machines are

performed to meet the requirements of the ASME Code,Section III, Paragraph NB-

2360.

Westinghouse has conducted a test program to determine the fracture toughness

of low alloy ferritic materials with specified minimum yield strengths greater

than 50,000 psi to demonstrate compliance with Appendix G of the ASME Code,

Section III. In this program, fracture toughness properties were determined

and shown to be adequate for base metal plates and forgings, weld metal, and

heat affected zone metal for higher strength ferritic materials used for

components of the RCPB. The results of the program are documented in Reference

1, which was submitted to the NRC.

The fracture toughness tests for WCGS reactor coolant pressure boundary components were performed by qualified operators in accordance with written

procedures.

5.2.3.3.2 Control of Welding

All welding is conducted utilizing procedures qualified according to the rules

of Sections III and IX of the ASME Code. Control of welding variables, as well

as examination and testing during procedure qualification and production

welding, is performed in accordance with ASME Code requirements.

Appendix 3A includes discussions which indicate the degree of conformance of

the ferritic materials components of the RCPB with Regulatory Guides 1.34,

"Control of Electroslag Weld Properties,"

5.2-17 Rev. 0 WOLF CREEK 1.43, "Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components,"

1.50, "Control of Preheat Temperature for Welding of Low-Alloy Steel," and

1.71, "Welder Qualification for Areas of Limited Accessibility."

5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel Sections 5.2.3.4.1 through 5.2.3.4.5 address Regulatory Guide 1.44, "Control of

the Use of Sensitized Stainless Steel," and present the methods and controls

utilized by Westinghouse to avoid sensitization and prevent intergranular attack of austenitic stainless steel components. Also, Appendix 3A includes a

discussion which indicates the degree of conformance with Regulatory Guide

1.44.

5.2.3.4.1 Cleaning and Contamination Protection Procedures

Austenitic stainless steel materials used in the fabrication, installation, and

testing of nuclear steam supply components and systems is handled, protected,

stored, and cleaned according to recognized and accepted methods which are

designed to minimize contamination which could lead to stress corrosion cracking. The rules covering these controls are stipulated in Westinghouse process specifications. As applicable, these process specifications

supplemented the equipment specifications and purchase order requirements of

every individual austenitic stainless steel component or system which

Westinghouse procures for the WCGS nuclear steam supply system, regardless of

the ASME Code classification.

The process specifications which define these requirements and which follow the

guidance of the American National Standards Institute N-45 Committee

specifications are as follows:

Process Specification

Number

82560HM Requirements for Pressure Sensitive Tapes for Use on Austenitic Stainless Steels

83336KA Requirements for Thermal Insulation Used on Austenitic

Stainless Steel Piping and Equipment

83860LA Requirements for Marking of Reactor Plant Components and

Piping

84350HA Site Receiving Inspection and Storage Requirements for

Systems, Material, and Equipment

5.2-18 Rev. 1 WOLF CREEK 84351NL Determination of Surface Chloride and°Fluoride on

Austenitic Stainless Steel Materials

85310QA Packaging and Preparing Nuclear Components for Shipment and Storage

292722 Cleaning and Packaging Requirements of Equipment for Use

in the NSSS

597756 Pressurized Water Reactor Auxiliary Tanks Cleaning

Procedures

597760 Cleanliness Requirements During Storage Construction,

Erection and Start-Up Activities of Nuclear Power System Appendix 3A includes a discussion which indicates the degree of conformance of

the austenitic stainless steel components of the RCPB with Regulatory Guide

1.37, "Quality Assurance Requirements for Cleaning of°Fluid Systems and

Associated Components of Water-Cooled Nuclear Power Plants."

5.2.3.4.2 Solution Heat Treatment Requirements

The austenitic stainless steels listed in Tables 5.2-2, 5.2-3, and 5.2-4 are

utilized in the final heat treated condition required by the respective ASME

Code,Section II materials specification for the particular type of grade of

alloy.

5.2.3.4.3 Material Testing Program

Westinghouse practice is that austenitic stainless steel materials of product forms with simple shapes need not be corrosion tested provided that the

solution heat treatment is followed by water quenching. Simple shapes are

defined as all plates, sheets, bars, pipe, and tubes, as well as forgings,

fittings, and other shaped products which do not have inaccessible cavities or

chambers that would preclude rapid cooling when water quenched. When testing

is required, the tests are performed in accordance with ASTM A 262, Practice A

or E, as amended by Westinghouse Process Specification 84201MW.

5.2.3.4.4 Prevention of Intergranular Attack of Unstabilized

Austenitic Stainless Steels

Unstabilized austenitic stainless steels are subject to intergranular attack

(IGA) provided that three conditions are present simultaneously. These are:

a. An aggressive environment, e.g., an acidic aqueous

medium containing chlorides or oxygen

5.2-19 Rev. 0 WOLF CREEK

b. A sensitized steel

c. A high temperature

If any one of the three conditions described above is not present,

intergranular attack will not occur. Since high temperatures cannot be avoided

in all components in the NSSS, reliance is placed on the elimination of

conditions a and b to prevent intergranular attack on wrought stainless steel

components.

This is accomplished by:

a. Control of primary water chemistry to ensure a benign

environment.

b. Utilization of materials in the final heat treated

condition and the prohibition of subsequent heat

treatments in the 800 and 1,500°F temperature range.

c. Control of welding processes and procedures to avoid

heat affected zone sensitization.

d. Confirmation that the welding procedures used for the

manufacture of components in the primary pressure

boundary and of reactor internals do not result in the

sensitization of heat affected zones.

Further information on each of these steps is provided in the following

paragraphs:

The water chemistry in the RCS is controlled by the Technical Requirements

Manual and plant procedures to prevent the intrusion of aggressive species.

Reference 5 describes the precautions taken to prevent the intrusion of

chlorides into the system during fabrication, shipping, and storage. The use

of hydrogen overpressure precludes the presence of oxygen during operation.

The effectiveness of these controls has been demonstrated by laboratory tests

and operating experience. The long-time exposure of severely sensitized

stainless in early Westinghouse pressurized water reactors to reactor coolant

environments has not resulted in any sign of intergranular attack. Reference 5

describes the laboratory experimental findings and reactor operating

experience. The additional years of operations since the issuance of Reference

5 have provided further confirmation of the earlier conclusions that severely

sensitized stainless steels do not undergo any intergranular attack in

Westinghouse pressurized water reactor coolant environments.

5.2-20 Rev. 13 WOLF CREEK In spite of the fact that there never has been any evidence that pressurized

reactor coolant water attacks sensitized stainless steels, Westinghouse

considers it good metallurgical practice to avoid the use of sensitized

stainless steels in the nuclear steam supply system components. Accordingly, measures are taken to prohibit the purchase of sensitized stainless steels and

to prevent sensitization during component fabrication. Wrought austenitic

stainless steel stock used for components that are part of: 1) the RCPB, 2)

systems required for reactor shutdown, 3) systems required for emergency core

cooling, and 4) reactor vessel internals (relied upon to permit adequate core

cooling for normal operation or under postulated accident conditions) is

utilized in one of the following conditions:

a. Solution annealed and water quenched, or

b. Solution annealed and cooled through the sensitization temperature range within less than approximately 5

minutes

It is generally accepted that these practices prevent sensitization.

Westinghouse has verified this by performing corrosion tests on as-received

wrought material.

The heat-affected zones of welded components must, of necessity, be heated into

the sensitization temperature range, 800 to 1,500°F. However, severe

sensitization, i.e., continuous grain boundary precipitates of chromium

carbide, with adjacent chromium depletion, can be avoided by controlling

welding parameters and welding processes. The heat input

• and associated cooling rate through the carbide precipitation range are of primary importance.

Westinghouse has demonstrated this by corrosion testing a number of weldments.

___________

• Heat input is calculated according to the formula:

H =

(E) (I) (60)

S Where:

H = joules/in.

E = volts I = amperes

S = travel speed, in./min.

5.2-21 Rev. 0 WOLF CREEK Of 25 production and qualification weldments tested, representing all major

welding processes, and a variety of components, and incorporating base metal

thicknesses from 0.10 to 4.0 inches, only portions of two were severely

sensitized. Of these, one involved a heat input of 120,000 joules, and the other involved a heavy socket weld in relatively thin walled material. In both

cases, sensitization was caused primarily by high heat inputs relative to the

section thickness. In only the socket weld did the sensitized condition exist

at the surface, where the material is exposed to the environment. The

component has been redesigned, and a material change has been made to eliminate

this condition.

The heat input in all austenitic pressure boundary weldments has been

controlled by:

a. Prohibiting the use of block welding

b. Limiting the maximum interpass temperature to 350°F

c. Westinghouse exercising approval rights on all welding

procedures

5.2.3.4.5 Retesting Unstabilized Austenitic Stainless

Steels Exposed to Sensitization Temperatures

As described in the previous section, it is not normal Westinghouse practice to

expose unstabilized austenitic stainless steels to the sensitization range of

800 to 1,500°F during fabrication into components. If, during the course of fabrication, the steel was inadvertently exposed to the sensitization

temperature range, 800 to 1,500°F, the material could be tested in accordance with ASTM A 262, as amended by Westinghouse Process Specification 84201MW, to verify that it is not susceptible to intergranular attack, except that testing

is not required for:

a. Cast metal or weld metal with a ferrite content of 5

percent or more,

b. Material with a carbon content of 0.03 percent or less

that is subjected to temperatures in the range of 800 to

1,500°F for less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />,

c. Material exposed to special processing provided the

processing is properly controlled to develop a uniform

product and provided that adequate documentation exists

of service experience and/or test data to demonstrate

that the processing will not result in increased

susceptibility to intergranular stress corrosion.

5.2-22 Rev. 0 WOLF CREEK If it was not verified that such material is not susceptible to intergranular

attack, the material would have been resolution annealed and water quenched or

rejected.

5.2.3.4.6 Control of Welding

The following paragraphs address Regulatory Guide 1.31, "Control of Ferrite

Content in Stainless Steel Weld Metal," and present the methods used, and the

verification of these methods, for austenitic stainless steel welding.

The welding of austenitic stainless steel is controlled to mitigate the

occurrence of microfissuring or hot cracking in the weld. Although published

data and experience have not confirmed that fissuring is detrimental to the

quality of the weld, it is recognized that such fissuring is undesirable in a general sense. Also, it has been well documented in the technical literature that the presence of delta ferrite is one of the mechanisms for reducing the

susceptibility of stainless steel welds to hot cracking. However, there is

insufficient data to specify a minimum delta ferrite level below which the

material will be prone to hot cracking. It is assumed that such a minimum lies

somewhere between 0- and 3-percent delta ferrite.

The scope of these controls discussed herein encompasses welding processes used

to join stainless steel parts in components designed, fabricated, or stamped in

accordance with the ASME Code,Section III, Class 1, 2, and core support

components. Delta ferrite control is appropriate for the above welding

requirements, except where no filler metal is used or for other reasons such

control is not applicable. These exceptions include electron beam welding,

autogenous gas shielded tungsten arc welding, explosive welding, and welding

using fully austenitic welding materials.

The fabrication and installation specifications require welding procedure and

welder qualification in accordance with Section III, and include the delta

ferrite determinations for the austenitic stainless steel welding materials

that are used for welding qualification testing and for production processing.

Specifically, the undiluted weld deposits of the "starting" welding materials

are required to contain a minimum of 5-percent delta ferrite

• as determined by chemical analysis and calculation, using the appropriate weld metal

constitution diagrams in Section III. When new

___________________

• The equivalent ferrite number may be substituted for percent delta ferrite.

5.2-23 Rev. 0 WOLF CREEK welding procedure qualification tests are evaluated for these applications,

including repair welding of raw materials, they are performed in accordance

with the requirements of Section III and Section IX.

The results of all the destructive and nondestructive tests are reported in the

procedure qualification record in addition to the information required by

Section III.

The "starting" welding materials used for fabrication and installation welds of

austenitic stainless steel materials and components meet the requirements of

Section III. The austenitic stainless steel welding material conforms to ASME

weld metal analysis A-7 (designated A-8 in the 1974 Edition of the ASME Code),

Type 308 or 308L for all applications. Bare weld filler metal, including

consumable inserts, used in inert gas welding processes conform to ASME SFA 5.9, and are procured to contain not less than 5-percent delta ferrite according to Section III. Weld filler metal materials used in flux shielded

welding processes conform to ASME SFA 5.4 or 5.9 and are procured in a wire-

flux combination to be capable of providing not less than 5-percent delta

ferrite in the deposit according to Section III. Welding materials are tested,

using the welding energy inputs to be employed in production welding.

Combinations of approved heat and lots of "starting" welding materials are used

for all welding processes. The welding quality assurance program includes

identification and control of welding material by lots and heats as

appropriate. All of the weld processing is monitored according to approved

inspection programs which include review of "starting" materials, qualification

records and welding parameters.

Welding systems are also subject to quality assurance audit including calibration of gages and instruments; identification of "starting" and completed materials; welder and procedure qualifications; availability and use

of approved welding and heat treating procedures; and documentary evidence of

compliance with materials, welding parameters, and inspection requirements.

Fabrication and installation welds are inspected using nondestructive

examination methods according to Section III rules.

To assure the reliability of these controls, Westinghouse has completed a delta

ferrite verification program, described in Reference 6, which has been approved

as a valid approach to verify the Westinghouse hypothesis and is considered an

acceptable alternative for conformance with the NRC Interim Position on

Regulatory Guide 1.31. The Regulatory Staff's acceptance letter and topical

report evaluation were received on December 30, 1974. The program

5.2-24 Rev. 0 WOLF CREEK results, which do support the hypothesis presented in Reference 6, are

summarized in Reference 7.

Appendix 3A includes discussions which indicate the degree of conformance of the austenitic stainless steel components of the RCPB with Regulatory Guides

1.34, "Control of Electroslag Properties," and 1.71, "Welder Qualification for

Areas of Limited Accessibility."

5.2.4 INSERVICE INSPECTION AND TESTING OF THE REACTOR

COOLANT PRESSURE BOUNDARY

Inservice inspection, inservice testing, repair and replacement of pressure-

retaining components, such as vessels, piping, pumps, valves, and bolting and

supports within the reactor coolant pressure boundary, comply with Section XI of the ASME Code, including addenda, per 10 CFR 50.55a(f) for testing and 10 CFR 50.55a(g) for inspection, repair and replacement, with certain exceptions

and alternatives whenever specific written relief is granted by the NRC per 10

CFR 50.55a, or when Section XI or OM Code Cases are used which either have been

reviewed by the NRC and found acceptable as documented in 10CFR50.55a(b)(5) or

(6) and Regulatory Guide 1.147 or 1.192 or approved for use by the granting of

relief requests. The conditions for use of Regulatory Guide 1.147 or 1.192

approved Code Cases are discussed in Appendix 3A. The inservice testing of

pumps and valves are discussed in Section 3.9(B).6. The limitations and modifications that the NRC places on the ASME Code in paragraph (b) of 10 CFR 50.55a are adhered to.

In addition, WCGS initially prepared separate preservice and inservice

inspection program documents, which complied with "NRC Staff Guidance for

Complying with Certain Provisions of 10CFR50.55a(g)--Inservice Inspection

Requirements." A description of the preservice inspection program was submitted to the NRC by SNUPPS letter dated May 26, 1981. The initial

inservice inspection program document was submitted to the NRC by letter dated

December 11, 1985. Subsequent inservice inspection program documents are

prepared in accordance with the 10 year update requirements in 10 CFR 50.55a

and submitted to the NRC for initial approval. The inspection program

documents identify the applicable Section XI edition and addenda and provide

the details to the areas subject to examination, method of examination, extent

and frequency of examination, and applicable Code Cases. 'Relief Requests'

seeking relief from applicable code requirements are submitted to the NRC and

become part of the inservice inspection program upon approval by the NRC. The repair and replacement program identifies the applicable Section XI edition and addenda, applicable Code Cases and relief requests, and provides the

administrative controls for performing repairs and replacements.

Since the plant is required to meet the requirements of future editions of

Section XI, insofar as practicable, an attempt was made during design to allow

access for inspections and coverage's anticipated to be required by later

editions of the Code. The result of this effort increased the areas on RPV

available to mechanized inservice inspection. WCGS has attempted to create an

inservice inspection program and plant design which concur with the 10 CFR 50

philosophy of upgrading inspections.

5.2.4.1 Inspection of Class 1 Components The system boundary subject to inspection includes all piping and components in

quality Group A (ASME Boiler and Pressure Vessel Code,Section III, Class 1).

The reactor pressure vessel (RPV), pressurizer, Class 1 portion of the steam generators, and all Class 1 piping, pumps, and valves are examined except for

items exempt from examination in accordance with ASME Section XI IWB-1200 and

for those areas where relief has been requested and granted.

5.2-25 Rev. 20 WOLF CREEK The scope of examinations, inspections, and acceptance criteria for initial

preservice inspections met the requirements outlined in Section XI of the ASME

Boiler and Pressure Vessel Code, "Rules for Inservice Inspection of Nuclear

Power Plant Components," 1977 Edition up to and including the Summer 1978 Addenda. The scope of examinations, inspections, and acceptance criteria for

inservice inspections and preservice inspections following repair and

replacement meet the applicable Edition and Addenda of Section XI, as described

at the beginning of section 5.2.4 and documented in the inservice inspection

program. In addition, the RPV is examined in accordance with the

recommendations of Regulatory Guide 1.150, Rev. 1 (Alternative Method), except for the components required to be examined to Appendix VIII. The ultrasonic examination of ferritic, austenitic, and dissimilar metal piping welds are performed in accordance with IWA-2232. The ultrasonic examination of cast

austenitic stainless steel (centrifugal and static cast) piping and component

welds may be performed in accordance with IWA-2240.

The extent of selection of piping welds for PSI examination were determined by

the requirements of the 1974 Edition of Section XI with Addenda through Summer

1975. The extent of selection of piping welds for ISI examination is

determined by the requirements of the applicable Edition and Addenda of ASME Section XI as described at the beginning of section 5.2.4 and documented in the

inservice inspection program. Beginning in ISI interval 2, the selection of piping welds for examination is determined under a risk-informed ISI program as an NRC approved alternative to the Section XI requirements. This program is implemented under the 'Relief Request' process as described at the beginning of 5.2.4. The Inservice Inspection Program requirements are specified in the Technical

Requirements Manual.

5.2.4.2 Arrangement and Accessibility

5.2.4.2.1 General

Access for the purpose of inservice inspection is defined as the design of the plant with the proper clearances for examination personnel and/or equipment to

perform inservice examinations during a nuclear unit shutdown. During system

and component arrangement design, careful attention was given to physical

clearances to allow personnel and equipment to perform required inservice

examinations. Access requirements of the Code were considered in the design of

components, weld joint configuration, and system arrangement. An inservice

inspection program design review was undertaken to identify any exceptions to

the access requirements of the code with subsequent design modifications and/or

inspection technique development to ensure Code compliance, as required.

Additional exceptions may be identified and reported to the NRC after plant operations, as specified in 10 CFR 50.55a(g)(5)(iv). Space has been provided to handle and store insulation, structural members, shielding, calibration

blocks, and similar material related to the inspection. Suitable hoists and

other handling equipment are also provided. Lighting, sources of power, and

services for the inspection equipment are provided at appropriate locations.

5.2-26 Rev. 20 WOLF CREEK Access is provided for volumetric examination of the pressure-containing welds

from the external surfaces of components and piping by means of removable

insulation, removable shielding, and permanent tracks for remote inspection

devices in areas where personnel access is restricted. Provisions for suitable access for inservice inspection examinations minimize the time required for

these inspections to be performed. Therefore, they reduce the amount of

radiation exposure to both plant and examination personnel. Working platforms

have been provided at strategic locations in the plant to permit ready access

to those areas of the reactor coolant pressure boundary which are designated as

inspection points in the inservice inspection program. Areas without permanent

platforms are provided with temporary platforms and/or scaffolding, as

required.

5.2.4.2.2 Access to Reactor Pressure Vessel Access for inspection of the RPV was provided as follows:

a. Access to the exterior surface of the RPV below the

2,011-foot-6-inch cavity shelf elevation for inservice

inspection is available since an annular space has been

provided between the vessel exterior surface and the

insulation interior surface. This was designed to permit the insertion of remotely operated inspection devices, if used, between the insulation and the reactor vessel.

Examination personnel could enter the area below the RPV through one approximately 3-foot-square access port in the

insulation to install the pole track remote examination

device. The bottom head insulation is designed to allow

an examiner to walk on the insulation while installing the examination device. Access to the window is provided through the in-core instrumentation tunnel. Use of the remotely operated external inspection devices was

abandoned in favor of the standard industry approach of

remotely operated internal inspection devices.

b. A 3-foot annular space between the exterior surface of

the RPV and the interior surface of the insulation has

been provided from the vessel closure flange elevation

to the cavity shelf elevation. The clearance area

provides sufficient access for examination personnel and

equipment to perform preservice and, if used, inservice

examinations on the exterior surfaces of the nozzle-to-

shell, safe end, pipe-to-elbow, flange-to-shell, and

vertical welds in the upper shell course of the vessel.

These welds may also be examined from the inside surface of the

vessel using remotely operated inspection devices.

c. The vessel flange seal surface is accessible during

refueling outages when the closure head is removed. The

vessel-to-flange weld can be examined manually or

mechanically from the flange seal surface, using

ultrasonic techniques. The inside surface of the RPV is

5.2-27 Rev. 12 WOLF CREEK available for a mechanized examination of the vessel-to-

flange weld from the vessel side during refueling

outages when the core barrel is removed. If examination

of the vessel-to-flange weld from the vessel side is required when the core barrel has not been removed, the

weld can be examined from the exterior surface of the

vessel.

d. Access to the inner surface of the RPV is available

during refueling outages when the portions of vessel

core structure are removed. A remotely operated

examination device designed to perform ultrasonic

examinations from the inner surface of the vessel is

used to examine the vessel-to-flange weld, nozzle-to-shell welds, and the vertical, circumferential, and meridional welds of the vessel.

Selected areas of reactor cladding and the internal

support attachments welded to the vessel wall are

accessible for remote visual examination when the core

barrel is removed at the end of the 10-year inspection

interval. A camera capable of remote positioning can be

inserted into the RPV.

e. The closure head is dry stored during refueling, which

facilitates direct manual examination. Removable

insulation allows examination of the head welds from the

outside surface. All reactor vessel studs which can be removed, nuts, and washers are removed to dry storage during refueling and are examined as required at that time. Studs which can not be removed are covered with a protective cover. Any stud that cannot be

removed is cleaned and visually inspected, in-situ, to the extent

possible, prior to placement in service for the next power operation

cycle.

5.2.4.2.3 Pressurizer

The external surface is accessible for visual and volumetric inspection by

removing the external insulation. Manways are provided to allow access for

internal visual inspection. The permanent insulation around the pressurizer

heaters is provided with a means to identify component leakages during system

pressure testing as described in section 5.2.4.7.

5.2.4.2.4 Heat Exchangers and Steam Generators

The external surface is accessible for volumetric and visual inspection by

removing portions of the vessel insulation. Manways in the steam generator

channel head provide access for internal visual examinations and eddy current

tests of steam generator tubes.

5.2-28 Rev. 16 WOLF CREEK 5.2.4.2.5 Piping Pressure Boundary

The physical arrangement of piping, pumps, and valves has been designed to

allow personnel access to welds requiring inservice inspection. Modifications to the initial plant design have been incorporated where practical to provide

proper inspection access. Removable insulation has been provided where

required by the Code on those piping systems requiring ultrasonic and/or

surface examinations. In addition, the placement of pipe hangers and supports

with respect to these welds has been reviewed and modified where necessary to

reduce the amount of plant support required in these areas during inspection.

Working platforms are provided in areas required to facilitate the servicing of

pumps and valves.

Temporary or permanent platforms and ladders are provided, as necessary, to gain access to piping welds. A conscientious effort has been made to minimize the number of fitting-to-fitting welds within the inspection boundary. Welds

requiring inspection have been located to permit ultrasonic examinations from

at least one side, but, where component geometries permit, access from both

sides of the weld is provided. The surfaces of the welds requiring ultrasonic

examination by the Code have been prepared to permit effective examination.

Vertical runs of piping are provided with removable insulation or catch basins

at the low point for leakage surveillance during system pressure testing as

described in section 5.2.4.7.

5.2.4.2.6 Pump Pressure Boundaries

The internal pressure-retaining surfaces of the pumps are accessible for visual

inspection by removing the pump internals. External surfaces of the pump

casing are accessible for visual and volumetric examination by removing component insulation. Internal examinations, when required by ASME Section XI, are performed when the pumps are disassembled for maintenance purposes.

5.2.4.2.7 Valve Pressure Boundaries

Class 1 valves over 4-inch nominal size are accessible for disassembly for

visual examination of internal pressure boundary surfaces.

5.2.4.3 Examination Techniques and Procedures Techniques and procedures, including any special technique and procedure for

visual, surface, and volumetric examinations were written in accordance with

the requirements of Subarticle IWA-2200 and Table IWB-2500-1 of Section XI of the ASME Code, applicable year and addenda. The liquid penetrant or magnetic

particle

5.2-29 Rev. 12 WOLF CREEK methods are utilized for surface examinations, radiographic (RT), and/or

ultrasonic (UT) methods (either automated or manual) for volumetric

examinations.

5.2.4.3.1 Equipment for Inservice Inspection

Procedures governing the use of the following examination devices are qualified

prior to examinations in the plant.

5.2.4.3.1.1 Ultrasonic Equipment

Although the SNUPPS design provided for remotely operated external inspection

equipment for examination of the reactor pressure vessel, such external

equipment was abandoned in favor of the standard industry approach of remotely operated internal inspection equipment. The remotely operated device for examination of the vessel and connected piping from their inner surfaces is

attached to the RPV at the flange surface. The device is capable of moving the

transducers over the surface of the components in any direction.

An electronic system with a receiver or data channel for each ultrasonic

transducer is used for acquiring and storing data when using remote automated

examination equipment. Reflected signals may be transmitted through an

ultrasonic instrument, gated, and multiplexed to initiate a digital recording.

Scanning position is indicated by encoders and subsequently logged by the data

acquisition system. The key parameters of each reflector recorded include

location, maximum signal amplitude, depth below the scanning surface, and

length of reflector. However, similar or compatible systems of data

acquisition may be utilized.

5.2.4.3.1.2 Surface Examination Equipment

Mechanized surface examination techniques provide results which are at least

equivalent to those obtainable by manual surface techniques.

5.2-30 Rev. 12 WOLF CREEK 5.2.4.3.1.3 Visual Examination Equipment

Remote visual examination techniques will be in accordance with ASME Section XI

requirements.

5.2.4.3.2 Coordination of Inspection Equipment with

Access Provisions

Access to areas of the plant requiring inservice inspection is provided to

allow the use of existing equipment, wherever practicable.

5.2.4.3.3 Manual Examination

In areas where manual ultrasonic examination is performed, reportable indications are mapped and records made of maximum signal amplitude, depth below the scanning surface, and length of the reflector. The data compilation

format is such as to provide for comparison of data from subsequent

examinations. Radiographic techniques may be used where ultrasonic techniques

are not applicable. In areas where manual surface or direct visual

examinations are performed, reportable indications are mapped with respect to

size and location in a manner to allow comparison of data from subsequent

examinations.

5.2.4.4 Inspection Intervals The inspection interval, as defined in Subarticle IWA-2400 of Section XI, is a

10 year interval of service. These inspection intervals represent calendar

years after the reactor facility has been placed into commercial service. The interval may be extended by as much as one year to permit inspections to be

concurrent with plant outages. The inspection schedule is in accordance with

IWB-2400. Inservice examinations are performed during normal plant outages,

such as refueling shutdowns or maintenance shutdowns occurring during the

inspection interval. However, inservice examinations may be performed while

the unit is on-line, if radiological and operational conditions permit access

to the components. No examinations are performed which require draining of the

reactor vessel further than just below the nozzles or removal of the core

solely for the purpose of accomplishing the examinations.

5.2.4.5 Examination Categories and Requirements The extent of the examinations performed and the examination methods utilized

shall be in accordance with the applicable Edition and Addenda of Section XI,

as described at the beginning of section 5.2.4 and documented in the inservice inspection program.

5.2-31 Rev. 14 WOLF CREEK In addition, preservice inspections comply with IWB-2200.

5.2.4.6 Evaluation of Examination Results

Evaluation of examination results for Class 1 components preservice inspections

were conducted in accordance with the requirements of Article IWB-3000 of the

ASME Code,Section XI, 1977 Edition with Addenda through the Summer of 1978.

Evaluation of examination results for Class 1 inservice inspections are

conducted in accordance with IWB-3000 in the applicable Edition and Addenda of

Section XI, as described at the beginning of section 5.2.4 and documented in

the inservice inspection program. In addition, the recording and evaluation of

examinations results for the reactor pressure vessel (RPV) are done as per

Regulatory Guide 1.150.

5.2.4.7 System Leakage and Hydrostatic Tests System pressure tests of the reactor pressure vessel and reactor coolant

pressure boundary are conducted in accordance with the requirements of Articles

IWA-5000 and IWB-5000. System leakage tests are conducted prior to startup following each reactor refueling outage, in accordance with Paragraph IWB-5221,

as required by Article IWB-5000. The system leakage test performed during Inspection Period 3 at or near the end of each 10-year interval is in accordance with the provisions of ASME Code,Section XI, or approved ASME Code Cases, as documented in the ISI program plan.

5.2.5 REACTOR COOLANT PRESSURE BOUNDARY LEAKAGE

DETECTION SYSTEMS

5.2.5.1 Design Bases

5.2.5.1.1 Safety Design Bases

There is no safety design basis for the reactor coolant pressure boundary leakage detection system.

5.2.5.1.2 Power Generation Design Bases

POWER GENERATION DESIGN BASIS ONE - For leaks of 1 gpm or greater, other than

identified leakage sources, the reactor coolant boundary leakage detection

systems are designed to detect leaks and determine the leakage rate (in

accordance with Regulatory Guide 1.45 and 10 CFR 50, Appendix A, General Design

Criterion 30). A comparison with the Regulatory Guide requirements is provided

in Table 5.2-6.

POWER GENERATION DESIGN BASIS TWO - The leakage detection equipment is designed

to continuously monitor the environmental conditions within the containment so

that a background level is identified which is indicative of the normal level

of leakage from

5.2-32 Rev. 20 WOLF CREEK primary systems and components. Significant upward deviation from normal

containment environmental conditions provides positive indication in the

control room of increases in leakage rates.

5.2.5.2 System Description 5.2.5.2.1 General Description

IDENTIFIED LEAKAGE DETECTION - Certain components of the reactor coolant pressure boundary may have small amounts of leakage and cannot, from a

practical standpoint, be made leaktight. These identified sources of leakage

are piped to the reactor coolant drain tank whose level is indicated and

alarmed in the control room. The annular gap between the O-rings in the

reactor vessel head flange is tapped and piped to a temperature indicator and

then to the reactor coolant drain tank. Reactor coolant leakage gives a high

temperature indication and alarm. Additionally, the controlled leakage shaft

seal system for the reactor coolant pumps is monitored by reactor coolant drain

tank level indication and alarm.

UNIDENTIFIED LEAKAGE DETECTION - The reactor coolant pressure boundary leakage detection system consists of the sump level and flow monitoring system, the

containment air particulate monitoring system, the containment cooler condensate measuring system, and the containment humidity monitoring system.

The sump level and flow monitoring system indicates leakage by monitoring

increases in sump level. The containment cooler condensate measuring system

and the containment humidity measuring system detect leakage from the release

of steam or water to the containment atmosphere. The air particulate gas monitoring system detects leakage from the release of radioactive materials to the containment atmosphere. The containment gaseous radioactivity monitor could provide additional indication of leakage if significant reactor coolant gaseous activity is present from fuel cladding defects.

Primary-to-secondary reactor coolant leakage, if it occurs, is detected by the

following radioactivity monitors: the main condenser evacuation, the steam

generator liquid, the steam generator blowdown processing, and the steam

generator blowdown discharge (Section 11.5.2).

Reactor coolant pressure boundary leakage is also indicated by increasing

charging pump flow rate compared with reactor coolant system inventory changes

and by unscheduled increases in reactor makeup water usage.

INTERSYSTEM LEAKAGE - Leakage to any significant degree into the auxiliary

systems connected to the RCPB is not expected to occur. Design and

administrative provisions which serve to limit leakage

5.2-33 Rev. 20 WOLF CREEK include isolation valves designed for low seat leakage, periodic testing of

RCPB check valves (see Section 6.3.4.2), and inservice inspection (see Section

6.6). Leakage is detected by increasing the auxiliary system level,

temperature, and pressure indications or lifting of the relief valves accompanied by increasing values of monitored parameters in the relief valve

discharge path. These systems are isolated from the RCS by normally closed

valves and/or check valves.

a. Residual Heat Removal System (Suction Side) - The RHR

system is isolated from the RCS on the suction side by

motor-operated valves 8701A/B and 8702A/B. Leakage past

these valves is detected by lifting of relief valves

8708A or 8708B, accompanied by increasing pressurizer

relief tank level, pressure, and temperature indications and alarms on the main control board.

b. Safety Injection System/Accumulators - The accumulators

are isolated from the RCS by check valves 8948A/B/C/D

and 8956A/B/C/D. Leakage, past these valves and into

the accumulator subsystem, is detected by redundant

control room accumulator pressure and level indications

and alarms.

c. Safety Injection System/RHR Discharge Subsystem - The

RHR pump portion of the safety injection system is

isolated from the RCS by check valves 8948A/B/C/D,

8818A/B/C/D, 8949B/C, 8841A/B, and normally closed

motor-operated valve 8840. Leakage past these valves

eventually pressurizes the RHR discharge header and result in lifting of the relief valves 8856A and 8856B or 8842. Relief valve lifting is detected by increasing levels of boron recycle holdup tanks which indicate and alarm in the radwaste control room and provide a general system alarm in the main control room.

d. Safety Injection System/SI Pump Subsystem - The safety

injection pump portion of the safety injection system is

isolated from the RCS by check valves 8948A/B/C/D; EP-

V010, V020, V030, V040; 8949A/B/C/D; EM-V001, V002,

V003, V004; and normally closed motor-operated valves

8802A/B. Leakage past these valves pressurizes the

safety injection pump discharge header, resulting in

control room indication of increasing pressure and

eventually lifting of relief valve 8851 or 8853A/B.

Relief valve lifting is detected by increasing levels of boron recycle holdup tanks which indicate and alarm in the radwaste control room and provide a general system alarm in the main control room.

5.2-34 Rev. 13 WOLF CREEK

e. Safety Injection System/Charging Pump Subsystem - The charging pump subsystem is isolated from the RCS by

check valves BB-V001, V022, V040, V059; and EM-8815; and

motor-operated valves EM-8801A/B. Leakage past these

valves eventually pressurizes the boron injection tank, resulting in a control room indication of increasing

tank pressure. The BIT and associated piping form a

closed volume which is designed for charging flow

pressure. Lower pressure portions of the SIS are

protected by double valve isolation, while single valves

isolate the higher pressure charging flow piping.

Leakage past valves EM-V151, V246, and V247 is not

possible, since the inlet of each of these valves is

pressurized by the operating charging pump.

f. Waste Processing System - The waste processing system is isolated from the RCS by manual valves BB-V008, V028,

V047, V066 and BB-V009, V029, V048, V067. Leakage past

these valves results in increasing the control room

indication of reactor coolant drain tank level and

reactor coolant drain tank pump flow.

g. Head Gasket Monitoring Connections - Leakage past the

reactor vessel head gasket(s) result in temperature

indication and alarm in the control room.

h. Component Cooling Water - Leakage from the reactor

coolant system to the component cooling water system,

which services all components of the reactor coolant

pressure boundary that require cooling, is detected by the component cooling water radioactivity monitoring system and/or increasing surge tank level. (Section

11.5.2).

Leakage to the containment atmosphere from the reactor coolant pressure

boundary would cause a change in the containment airborne radioactivity which

would be detected by the air particulate monitors. If the reactor is operating with a known rate of leakage, at a constant power level, with a constant reactor coolant activity and a constant purge rate, both the gross particulate

and gross noble gas activities reach an equilibrium level. Under these

conditions, an abnormal increase in monitored activity are the results of

increased leakage. Such leakage is classified as unidentified until its source is determined.

During the expected modes of operation, the reactor coolant activity level

fluctuates due to power variations and variations in letdown flow rate.

However, significant increases in leakage can be detected.

5.2-35 Rev. 20 WOLF CREEK Leakage detection systems have been designed to aid operating personnel, to the

extent possible, in differentiating between possible sources of detected

leakage within the containment and identifying the physical location of the

leak.

The containment atmosphere particulate monitoring system provides the primary means of remotely determining the presence of reactor coolant leakage within the containment. Increases in containment airborne activity levels detected by

either of the monitors indicate the reactor coolant pressure boundary as the source of leakage. Conversely, if the humidity detector or condensate

measuring system detects increased containment moisture without a corresponding

increase in airborne activity level, the indicated source of leakage would be

judged to be a non-radioactive system, except during times when reactor coolant

activity may be low.

Less sensitive methods of leakage detection, such as unexplained increases in

reactor plant makeup requirements to maintain pressurizer level, also provide

indication of the reactor coolant pressure boundary as a potential leakage

source. Increases in the frequency of a particular containment sump pump

operation or increases in the level in a particular sump facilitate

localization of the source to components whose leakage would drain to that

sump. Leakage rates of the magnitude necessary to be detectable by these

latter methods are expected to be noted first by the more sensitive radiation

and moisture detection equipment.

Normally, unidentified leakage from the reactor coolant pressure boundary is

essentially zero. The reactor coolant system is an all welded system, with the

exception of the connections on the pressurizer safety valves, reactor vessel

head, and the pressurizer and steam generator manways, which are flanged, and

encapsulation clamps at the capped flange on CRDM penetrations 13, 24, 25, 27,

28 and 29. In addition, encapsulation clamps are authorized to be installed on

any of the remaining spare or active CRDM penetrations or any of the Core Exit

Thermocouple (CET) penetrations. Connections to the reactor coolant system are

welded. Isolation or check valves between the reactor coolant system and other

systems have been designed for low seat leakage, and reactor coolant pressure

boundary check valve backleakage is checked periodically. In general, valves

in the reactor coolant system 2 inches and under are of the packless type.

Valves larger than 2 inches have graphite packing.

The plant containment has the capability for a continuous purge of 4,000 cfm.

The time to recirculate one containment free air volume through the containment

air coolers is 4.57 minutes. The component operation for various leak

detection systems, as discussed in Section 5.2.5.2.3, is based on this

containment purge and recirculation time.

5.2-36 Rev. 20 WOLF CREEK MAXIMUM ALLOWABLE TOTAL LEAKAGE - The limits for the reactor coolant pressure

boundary leakage are: identified, 10 gpm and unidentified, 1 gpm. When

leakage is identified, it is evaluated by the operating staff to determine if

operation can safely continue. Under these conditions, an allowable total leakage from known sources of 10 gpm has been established. Continued operation

of the reactor with identified or unidentified leakage shall be in accordance

with the Technical Specifications.

Normal chemical and volume control system operation can consist of either 75

gpm or 120 gpm letdown. This is determined by either operator preference or

plant conditions. For example, 120 gpm letdown would normally be employed

during periods of increased RCS activity. An additional 12 gpm reactor coolant

pump seal return during normal plant operation results in a total flow leaving

the reactor of either 87 gpm (75 gpm letdown) or 132 gpm (120 gpm letdown).

Based on the above conditions, the charging pump flow rates of 87 gpm or 132 gpm would be required to makeup for flow leaving the reactor. Considering a

normal seal injection flow of 32 gpm; 55 gpm (75 gpm letdown) or 100 gpm (120

gpm letdown) would be supplied through the normal charging line. A single

centrifugal charging pump with a 150 gpm rated capacity at 5800 ft of head or

the Normal Charging Pump which has a capability of 150 gpm as shown in the

preoperational test provides an adequate reserve capacity at normal RCS pressures to easily accommodate a 10 gpm maximum limit on reactor coolant pressure boundary leakage.

The reactor coolant pressure boundary leakage detection system provides ample

protection to assure that, in the unlikely event of a failure of the reactor coolant pressure boundary, small cracks are detected prior to becoming large

leaks. In particular:

a. The sensitivity of the detection equipment is such that

leaks can be identified when small, and the plant can be

shut down. The limit on continued operation for

unidentified leakage is l gpm. This is well within the

detection capability of the reactor coolant pressure

boundary leakage detection system.

b. The time span for a crack to go from detectable size to critical size varies from 5 to more than 40 years. This

assures adequate safety from a major loss-of-coolant

accident. Actual conditions are addressed in Reference 9.

5.2-37 Rev. 13 WOLF CREEK The above methods are supplemented by visual and ultrasonic inspections of the

reactor coolant pressure boundary during plant shutdown periods, in accordance

with the inservice inspection program (Section 5.2.4).

5.2.5.2.2 Component Description

CONTAINMENT AIR PARTICULATE MONITOR - An air sample is drawn outside the

containment into a closed system by a sample pump and is then consecutively

passed through a particulate filter with detectors, an iodine filter with

detector, and a gaseous monitor chamber with detector. The sample transport

system includes:

a. A pump to obtain the air sample

b. A flow control valve to provide flow adjustment

c. A flow meter to indicate the flow rate

d. A flow alarm assembly to provide high and low flow alarm

signals

The particulate filter is continuously monitored by a scintillation crystal

with a photo multiplier tube which provides an output signal proportional to

the activity collected on the filter. The particulate monitor has a range of 10-12 to 10-7 Ci/cc and a minimum detectable concentration of 10

-11 Ci/cc. The containment and particulate monitoring system is capable of performing its radioactive monitoring functions following an SSE. More details concerning the

particulate monitors can be found in Section 11.5.2.3.2.2.

CONTAINMENT GASEOUS RADIOACTIVITY MONITOR - The containment gaseous

radioactivity monitor determines gaseous radioactivity in the containment by

monitoring continuous air samples from the containment atmosphere. After

passing through the gas monitor, the sample is returned via the closed system

to the containment atmosphere.

Each sample is continuously mixed in a fixed, shielded volume where its activity is monitored. The monitor has a range of 10

-7 to 10-2 Ci/cc and a minimum detectable concentration of 2 x 10

-7 Ci/cc. The containment gaseous radioactivity monitors are fully described in Section

11.5.2.3.2.2.

5.2-38 Rev. 0 WOLF CREEK The containment gaseous radioactivity monitoring system is capable of

performing its radioactivity monitoring functions following an SSE.

CONTAINMENT PURGE MONITORS - The containment purge system radioactivity monitors (Section 11.5.2.3.2.3) serve as a backup to the containment air

particulate and gaseous airborne radioactivity monitoring system while the

purge is in operation.

CONTAINMENT COOLER CONDENSATE MONITORING SYSTEM - The condensate monitoring

system permits measurements of the liquid runoff from the containment cooler

units. It consists of a containment cooler drain collection header, a vertical

standpipe, valving, and standpipe level instrumentation for each cooler.

The condensation from the containment coolers flows via the collection header to the vertical standpipe. A differential pressure transmitter provides standpipe level signals. The system provides measurements of low leakages by

monitoring standpipe level increase versus time.

CONTAINMENT HUMIDITY MONITORING SYSTEM - The containment humidity monitoring

system, utilizing temperature compensated humidity detectors, is provided to

determine the water vapor content of the containment atmosphere.

An increase in the humidity of the containment atmosphere indicates release of

water within the containment. The range of the containment humidity measuring

system is 10 to 98-percent relative humidity at 80°F with a temperature range

of 40 to 120°F.

CONTAINMENT SUMP LEVEL AND FLOW MONITORING SYSTEM - Since a leak in the primary

system would result in reactor coolant flowing into the containment normal or instrument tunnel sumps, leakage would be indicated by a level increase in the sumps. Indication of increasing sump level is transmitted from the sump to the

control room level indicator by means of a sump level transmitter. The system

provides measurements of low leakages by monitoring level increase versus time.

CHARGING PUMP OPERATION - During normal operation, either the normal or other

centrifugal charging pump is in operation. If a gross loss of reactor coolant

occurs which is not detected by the methods previously described, the flow rate

of the operating charging pump indicates the leakage from the reactor coolant

system. This leakage must be sufficient to cause a decrease in pressurizer or

volume control

5.2-39 Rev. 13 WOLF CREEK tank level that is within the sensitivity range of the level indicators. The

charging pump flow would automatically increase to try to maintain pressurizer

level. Charging pump discharge flow indication is provided in the control

room.

SUMP PUMP OPERATION - Since a leak in the primary system may result in reactor

coolant flowing into the containment normal or instrument tunnel sumps, gross

leakage can be indicated by an increase in the frequency of operation of the

containment normal or the containment instrument tunnel sump pumps. Pump

operation can be monitored from the control room.

LIQUID INVENTORY - Larger leaks may also be detected by unscheduled increases

in the amount of reactor coolant makeup water which is required to maintain the

normal level in the pressurizer. Pressurizer level can be monitored in the control room. Total makeup water flow is also available from the plant computer.

5.2.5.2.3 Component Operation

CONTAINMENT AIR PARTICULATE MONITOR - Particulate activity is determined from

the containment free volume and the coolant fission and corrosion product

particulate activity concentrations. Any increase of more than two standard

deviations above the count rate for background would indicate a possible leak.

The total particulate activity concentration above background, due to an

abnormal leak and natural decay, increases almost linearly with time for the

first several hours after the beginning of a leak. As shown in Figure 5.2-2,

with 0.1-percent failed fuel, containment background airborne particulate

radioactivity equivalent to 10-4 percent/day, and a partition factor equal to

0.01 (NUREG-0017 assumptions), a 1-gpm leak would be detected in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Larger leaks would be detected in proportionately shorter times (exclusive of sample transport time, which remains constant). The detection capabilities and

response times are shown on Figure 5.2-2.

In the discussions with the NRC and in NUREG/CR-6582, the gaseous particulate monitors cannot readily determine the leakage rate because the activity is determined by unsteady conditions, background level, reactor coolant activity and partition factors for particulates. The background activity is dependent upon the power level, percent failed fuel, crud bursts, iodine spiking, and natural radioactivity brought in by the containment purge.

CONTAINMENT GASEOUS RADIOACTIVITY MONITOR - This monitor is less sensitive than the containment air particulate monitors but gives a positive indication of leakage in the event that reactor coolant gaseous activity exists as a result of fuel-cladding defects. Gaseous radioactivity is determined from the containment free volume and the gaseous activity concentration of the reactor

coolant. Any increase more than two standard deviations above the count rate

for background would indicate a possible leak. The total gaseous activity

level above background (after 1 year of normal operation) increases

5.2-40 Rev. 20 WOLF CREEK almost linearly for the first several hours after the beginning of the leak.

As specified in Figure 5.2-2, with 0.1-percent failed fuel, containment

background airborne gaseous radioactivity equivalent to 1 percent/day, and a

partition factor equal to l (NUREG-0017 assumptions), a 1-gpm leak would be detected within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Larger leaks would be detected in proportionately

shorter times (exclusive of the sample transport time which remains constant).

The detection capabilities and response times are shown on Figure 5.2-2.

Evaluations have shown that the pre-existing containment radioactive gaseous

background levels for which reliable detection is possible is dependent upon

the reactor power level, percent failed fuel and natural radioactivity brought

in by the containment purge. With primary coolant concentrations less than

equilibrium levels, such as during reactor startup and operation with no fuel

defects, the increase in detector count rate due to leakage will be partially masked by 1) the statistical variation of the minimum detector background count rate, and 2) the Ar-41 activation activity rendering reliable detection of a 1

gpm leak uncertain. The containment atmosphere gaseous radioactivity monitors

were designed in accordance with the sensitivities specified in Regulatory

Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems," with

the alarm setpoint set to indicate a 1 gpm RCS leak based on Regulatory Guide

1.45 assumptions. The monitors are fully functioning in accordance with its

design requirements, however they have been removed as part of the reactor

coolant pressure boundary leakage detection system due to the inability to

promptly detect a 1 gpm RCS leak within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with reduced radioactivity

levels in the reactor coolant system. (Reference 12)

CONTAINMENT PURGE MONITORS - The containment purge monitors function the same

as the containment air particulate and gaseous radioactivity monitors, except

that the purge monitors sample from the containment purge exhaust line.

CONTAINMENT COOLER CONDENSATE MONITORING SYSTEM - The condensate flow rate is a

function of containment humidity, essential service water temperature leaving

the coolers, and containment purge rate. The water vapor dispersed by a 1 gpm

leak is much greater than the water vapor brought in with the outside air. Air

brought in from the outside is heated to 50°F before it enters the containment.

After the air enters the containment, it is heated to 100-120°F so that the

relative humidity drops. The water vapor brought in with the outside air does

not build up in the containment since it is continually purged. The most

important factor in condensing the water vapor is the temperature of the

essential service water which is provided to the containment coolers. This

water can vary between 38 - 100°F on the outlet of the coolers, depending on

seasonal conditions.

Level changes of as little as 0.25 inches in the cooler condensate standpipes

can be detected. Increases in the condensation rates over normal background

are monitored by the plant computer based upon level checks in order to determine the unidentified leakage. Figure 5.2-2 shows the detection capabilities of the system for various seasonal conditions with no airborne

identified leakage. Normal background leakage will increase containment

humidity to the point where condensation will more readily occur and, thereby,

will improve the detection capabilities of this system.

5.2-41 Rev. 21 WOLF CREEK As shown on Figure 5.2-2, a sensitivity of 1 gpm in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> can be achieved with

cold essential service water temperature to the containment coolers or with

initial background leakage.

The rate of leakage can be determined when the precise essential service water,

outside air, and containment air temperatures and the outside relative humidity

are known by use of psychrometric charts.

CONTAINMENT HUMIDITY MONITORING SYSTEM - The maximum possible containment

humidity under various outside air conditions and no leakage will fall within

the extremes shown on Figure 5.2-2. Therefore, a 1-gpm leak can be detected

within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> by measuring the containment humidity.

The accuracy of the humidity detectors is +

3 percent. A rapid increase of humidity over the background level by more than 10 percent can be taken as a probable indication of a leak.

The leak rate can be determined when the outside air temperature and humidity and the containment temperature are known by use of psychrometric charts.

CONTAINMENT SUMP LEVEL AND FLOW MONITORING SYSTEM - The detection capabilities

of the containment normal sump and instrument tunnel sump are shown in Figure

5.2-2, assuming that the water from the leak is collected in the sump.

The minimum detectable change in the containment normal sump level is 3 gallons

and in the instrument tunnel sump level is 15 gallons. When the instrument

tunnel sump is completely dry, the minimum detectable level change is 25

gallons.

The actual reactor coolant leakage rate can be established from the increase

above the normal rate of change of sump level after consideration of 35 percent

of the high temperature leakage which initially evaporates but may be condensed

by the containment coolers and then is routed to the sump. A check of other instrumentation would be required to eliminate possible leakage from

nonradioactive systems as a cause of an increase in sump level.

CHARGING PUMP OPERATION - The normal charging pump normally delivers 87 or 132

gpm to the reactor coolant system depending on the amount of letdown flow

established. Any significant increase in the flow rate is a possible

indication of a leak.

The leakage rate can be determined by the amount that the charging pump rate

increases above 87 or 132 gpm to maintain constant pressurizer level.

5.2-42 Rev. 21 WOLF CREEK SUMP PUMP OPERATION - Under normal conditions, the containment normal and

instrument tunnel sump pumps will operate very infrequently. Gross leakage can

be surmised from unusual frequency of pump operation. Sump level and pump

running indication are provided in the control room to alert the operators.

The leakage rate can be determined from sump volumes and frequency of sump pump

operation.

LIQUID INVENTORY - The operators can surmise gross leakage from changes in the

reactor coolant inventory. Noticeable decreases in the pressurizer level not

associated with known changes in operation will be investigated. Likewise,

makeup water usage information which is available from the plant computer will

be checked frequently for unusual makeup rates not due to plant operations.

5.2.5.3 Safety Evaluation Inasmuch as this system has no safety design basis, no safety evaluation is

provided. Criteria for the selection of safety design bases are stated in

Section 1.1.7.

5.2.5.4 Tests and Inspections Periodic testing of leakage detection systems is conducted to verify the

operability and sensitivity of detector equipment. These tests include

installation calibrations and alignments, periodic channel calibrations, functional tests, and channel checks. A description of calibration and

maintenance procedures and frequencies for the containment radioactivity

monitoring system is presented in Section 11.5.2.

The humidity detector and condensate measuring system are also periodically

tested to ensure proper operation and verify sensitivity.

Inservice inspection criteria, the equipment used, procedures involved, the

frequency of testing, inspection, surveillance, and examination of the

structural and leaktight integrity of reactor coolant pressure boundary components are described in detail in Section 5.2.4.

5.2.5.5 Instrumentation Applications The following indications are provided in the control room to allow operating

personnel to monitor for leakage:

a. Containment air particulate monitor - air particulate

activity

5.2-43 Rev. 0 WOLF CREEK

b. Containment gaseous activity monitor - gaseous activity

c. Containment cooler condensate monitoring system -

standpipe level

d. Containment normal sump level and instrument tunnel sump

level e. Containment humidity measuring system - containment

humidity

f. Gross leakage detection methods - Charging pump flow rate, let-down flow rate, pressurizer level and reactor coolant temperatures are available for the charging pump flow method. Containment sump levels and pump operation are available for the sump pump operation method. Totalized makeup water flow is available from the plant computer for liquid inventory.

5.

2.6 REFERENCES

1. Logsdon, W. A., Begley, J. A., and Gottshall, C. L., "Dynamic Fracture Toughness of ASME SA508 Class 2a and ASME SA533 Grade A Class 2 Base and Heat Affected Zone Material and Applicable Weld Metals," WCAP-9292, March

1978. 2. Letter NS-CE-1730, dated March 17, 1978, C. Eicheldinger (Westinghouse) to J. F. Stolz (NRC).

3. Cooper, L., Miselis, V. and Starek, R. M., "Over-pressure Protection for Westinghouse Pressurized Water Reactors," WCAP-7769, Revision 1, June,

1972 (also letter NS-CE-622, dated April 16, 1975, C. Eicheldinger

(Westinghouse) to D. B. Vassallo (NRC), additional information on WCAP-

7769, Revision 1).

4. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP- 7907, October 1972.

5. Golik, M. A., "Sensitized Stainless Steel in Westinghouse PWR Nuclear Steam Supply Systems," WCAP-7477-L (Proprietary), March, 1970 and WCAP-

7735 (Non-Proprietary), August 1971.

6. Enrietto, J. F., "Control of Delta Ferrite in Austenitic Stainless Steel Weldments," WCAP-8324-A, June 1975.

7. Enrietto, J. F., "Delta Ferrite in Production Austenitic Stainless Steel Weldments," WCAP-8693, January 1976.

8. W. D. Wagner, et. Al., "Transient Analysis Methodology for the Wolf Creek Generating Station," NSAG-006 Rev. 0, March 11, 1991.

9. WCAP-7503, "Determination of Design Pipe Breaks for the Westinghouse Reactor Coolant System," Supplement 1, February 1972.

10. WCAP-14040-A, "Methodology Used to Develop Cold Overpressure Mitigation System Setpoints and RCS Heatup and Cooldown Limit Curves,"

Revision 4, J. Andrachek et. al., May 2004.

11. NRC Letter dated May 31, 2005, from Robert A. Gramm to Rick A. Muench "Wolf Creek Generating Station - Request for Relief Regarding

Classification of Pressurizer Upper level Instrument and Other Lines and

Associated components for Wolf Creek Generating Station, Unit 1 (TAC No.

MC5058)."

5.2-44 Rev. 23 WOLF CREEK 12. NRC Letter dated May 16, 2006, from J. Donohew to R. Muench, "Wolf Creek Generation Station - License Amendment Request to change the Reactor Coolant System Leakage Detection Instrumentation Methodology (TAC No.

MC8214).

13. Implementation of piping code cases in specification M-200.

14. Letter 07-00401, dated July 19, 2007, from USNRC to WCNOC, Authorization of Relief Request 13R-05, Alternatives to Structural Weld Overlay Requirements.

5.2-45 Rev. 21

WOLF CREEK TABL E 5.2-1APPLICABL E CODE ADDENDA FOR R EACTOR COOLANT SYST EM COMPONENTSReactor vessel ASM E III, 1971 Edition through Winter 1972 Steam generator ASM E III, 1971 Edition through Summer 1973 Pressurizer ASM E III, 1974 EditionCRDM housing ASM E III, 1974 Edition through Winter 1974 CRDM head adapter ASM E III, 1971 Edition through Winter 1972 Reactor coolant pump ASM E III, 1971 Edition through Summer 1973*Reactor coolant pipe ASM E III, 1974 Edition through Winter 1975**Surge lines ASM E III, 1986 EditionValves Pressurizer safety ASM E III, 1974 Edition through Summer 1975 Motor operated ASM E III, 1974 Edition through Summer 1975 Manual (3 inch and ASM E III, 1974 Edition through Summer 1975 larger)

Control ASM E III, 1974 Edition through Summer 1975

• The 1974 Edition and Addenda up to and including the Winter 1975 Addenda is the applicable version of the Code for Class 1 piping components designed /

supplied by Westinghouse. In addition, the fatigue stress analysis uses the

ASME Code Addend up to Summer 1979.

• • The Class 1 piping fatigue stress analysis uses ASM E Section III 1986 code.

Rev. 13 WOLF CREEK TABLE 5.2-2 CLASS 1 PRIMARY COMPONENTS MATERIAL SPECIFICATIONS Reactor Vessel Components

Shell and head plates (other SA-533, Grade A, B or C, Class 1

than core region) or 2 (vacuum treated)

Shell plates (core region) SA-533, Grade A or B, Class l

(vacuum treated)

Shell, flange and nozzle SA-508, Class 2 or 3; SA-182,

forgings, nozzle safe ends Grade F304 or F316

CRDM and/or ECCS appurtenances, SB-166 or SB-167 and SA-182, upper head Grade F304

Instrumentation tube SB-166 or SB-167 and SA-182,

appurtenances, lower head Grade F304, F304L or F316

Closure studs, nuts, washers, SA-540, Class 3, Grade B23 or B24

inserts, and adaptors (as modified by Code Case 1605)

Core support pads SB-166 with carbon less than

0.10 percent

Monitor tubes and vent pipe SA-312 or SA-376, Grade TP304 or

TP316 or SB-166 or SB-167 or

SA-182, Grade F316

Vessel supports, seal ledge, SA-516, Grade 70 (quenched and

and heat lifting lugs tempered) or SA-533, Grade A, B

or C, Class 1 or 2 (vessel

supports may be of weld metal

buildup of equivalent strength

of the nozzle material)

Cladding and buttering Stainless Steel Weld Metal

Analysis A-8 and Ni-Cr-Fe

Weld Metal F-Number 43

Steam Generator Components

Pressure Plates SA-533, Grade A, Class 2

Pressure forgings (including SA-508, Class 2a

nozzles and tube sheet)

Rev. 0 WOLF CREEK TABLE 5.2-2 (Sheet 2)

Nozzle safe ends Stainless Steel Weld Metal

Analysis A-8 Channel heads SA-533, Grade A, B or C, Class l

or 2 or SA-216, Grade WCC Tubes SB-163 (Ni-Cr-Fe annealed)

Cladding and buttering Stainless Steel Weld Metal

Analysis A-8 and Ni-Cr-Fe Weld

Metal F-Number 43 Closure bolting SA-193, Grade B7 Pressurizer Components Pressure plates SA-533, Grade A, Class 2 Pressure forgings

• SA-508, Class 2a Nozzle safe ends

• SA-182, Grade F316L Cladding and buttering

• Stainless Steel Weld Metal Analysis A-8 and Ni-Cr-Fe

Weld Metal F-Number 43 Closure bolting SA-193, Grade B7 Reactor Coolant Pump Pressure forgings SA-182, Grade F304, F316, F347

or F348 Pressure casting SA-351, Grade CF8, CF8A or CF8M Tube and pipe SA-213; SA-376 or SA-312, Seam-

less, Grade TP304 or TP316 Pressure plates SA-240, Type 304 or 316 Bar material SA-479, Type 304 or 316 Closure bolting SA-193; SA-320; SA-540 or

SA-453, Grade 660;

SB-637 Gr. N07718 Flywheel SA-533, Grade B, Class 1

• In order to mitigate primary water stress corrosion cracking concerns with the originally installed Alloy 600 (82/182) dissimilar metal welds, full structural weld overlays made of ERNiCrFe-7A (Alloy 52M/UNS N06054) have been installed to cover portions of the Pressurizer nozzles (Surge, Safety, Relief, and Spray),

nozzle weld butter layers, dissimilar metal welds between the butter and the safe end, safe ends, safe end to stainless steel pipe welds, and connecting stainless steel piping. Rev. 21 WOLF CREEK TABLE 5.2-2 (Sheet 3)

Reactor Coolant Piping

Reactor coolant pipe SA-351, Grade CF8A

Centrifugal Casting

Reactor coolant fittings, SA-351, Grade CF8A and SA-182,

branch nozzles (Code Case 1423-2) Grade 316N

Surge line SA-376, Grade TP304, TP316

or F304N

Auxiliary piping 1/2 through ANSI B36.19

12 inch and wall schedules

40S through 80S (ahead of

second isolation valve)

All other auxiliary piping ANSI B36.10

(ahead of second isolation

valve)

Socket weld fittings ANSI B16.11

Piping flanges ANSI B16.5

Full Length CRDM

Latch housing SA-182, Grade F304 or SA-351,

Grade CF8

Rod travel housing SA-182, Grade F304 or SA-336,

Class F8

Cap SA-479, Type 304

Welding materials Stainless Steel Weld Metal

Analysis A-8

Rev. 0

WOLF CREEK TABLE 5.2-3 CLASS 1 AND 2 AUXILIARY COMPONENTS MATERIAL SPECIFICATIONS

Valves

Bodies SA-182, Grade F316 or SA-351,

Grade CF8 or CF8M

Bonnets SA-182, Grade F316 or SA-351,

Grade CF8 or CF8M

Discs SA-182, Grade F316 or SA-564, Grade 630, or SA-351, Grade

CF8 or CF8M

Stems SA-182, Grade F316 or SA-564,

Grade 630

Pressure-retaining bolting SA-453, Grade 660

Pressure-retaining nuts SA-453, Grade 660 or SA-194

Grade 6

Auxiliary Heat Exchangers

Heads SA-240, Type 304 Nozzle necks SA-182, Grade F304

Tubes SA-213, Grade TP304

Tube Sheets SA-182, Grade F304

Shells SA-240 and SA-312, Grade TP304

Auxiliary Pressure Vessels, Tanks, Filters, etc.

Shells and heads SA-240, Type 304 or SA-264

(consisting of SA-537, Class 1

with Stainless Steel Weld Meta

Analysis A-8 Cladding)

Flanges and nozzles SA-182, Grade F304 and SA-105 or

SA-350, Grade LF2 or LF3 with

Stainless Steel Weld Metal

Analysis A-8 Cladding

Rev. 0 WOLF CREEK TABLE 5.2-3 (Sheet 2)

Piping SA-312 and SA-240, Grade TP304 or TP316 Seamless

Pipe fittings SA-403, Grade WP304 Seamless

Closure bolting and nuts SA-193, Grade B7 and SA-194,

Grade 2H/Grade 7 Auxiliary Pumps

Pump casing and heads SA-351, Grade CF8 or CF8M;

SA-182, Grade F304 or F316

Flanges and nozzles SA-182, Grade F304 or F316;

SA-403, Grade WP316L Seamless

Piping SA-312, Grade TP304 or TP316

Seamless

Stuffing or packing box cover SA-351, Grade CF8 or CF8M;

SA-240, Type 304 or 304L

or 316 Pipe fittings SA-403, Grade WP316L Seamless

Closure bolting and nuts SA-193, Grade B6, B7 or B8M;

SA-194, Grade 2H/Grade 7 or 8M; SA-453 Grade 660, and Nuts, SA-194, Grade 2H, 6 and 8 M

Rev. 23 WOLF CREEK TABL E 5.2-4 REACTOR VESSEL INTERNALS FOR EMERGENCY CORE COOLING SYST EMSForgings SA-182, Grade F304 Plates SA-240, Type 304

Pipes SA-312, Grade TP304 Seamless or SA-376, Grade TP304 Tubes SA-213, Grade TP304

Bars SA-479, Type 304 and 410

Castings SA-351, Grade CF8 and CF8A

Bolting SA-193, Grade B8M (65 MYS/90 MTS)

Code Case 1618 Inconel-750;

SA-461, Grade 688 Nuts SA-193, Grade B8

Locking devices SA-479, Type 304 Rev. 0 WOLF CREEK TABL E 5.2-5 RECOMMENDED REACTOR COOLANT WAT ER CHEMISTRY LIMITS (g)Electrical conductivity Determined by the concentration of boric acid and alkali present.

Expected range is 1 to 40 mhos/cm at 25°C.

Solution pH Determined by the concentration of boric acid and alkali present.

Expected values range between 4.2 (high boric acid concentration) to 10.5 (low boric acid concentration

at 25°C. Values will be 5.0 or

greater at normal operating

temperatures.

Oxygen(a) 0.005 ppm, maximum Chloride(b) 0.15 ppm, maximum Fluoride(b) 0.15 ppm, maximum Hydrogen(c) 25 to 50 cc (STP)/kg H2O Suspended solids (d) 1.0 ppm, maximum pH control agent (Li7OH)

(e) Lithium Control Program Boric acid Variable from 0 to ~4000 ppm as B Silica(f) 1.0 ppm, maximum Aluminum(f) 0.05 ppm, maximum Calcium(f) 0.05 ppm, maximum Magnesium (f) 0.05 ppm, maximum NOTES:(a) Oxygen concentration should normally be controlled by scavenging with hydrazine to less than 0.1 ppm in the reactor

coolant prior to exceeding a temperature of 250°F. During power operation with the specified hydrogen concentration maintained in the coolant, the residual oxygen concentration

does not exceed 0.005 ppm.

(b) Halogen concentrations are maintained below the specified values at all times regardless of system temperature. Rev. 16 WOLF CREEK TABL E 5.2-5 (Sheet 2)

(c) Hydrogen is maintained in the reactor coolant for all plant operations with nuclear power above 1 MWt. The normal

operating range should be 30 to 40 cc/kg H 2O.Twenty four hours prior to a scheduled shutdown, when the

reactor coolant system is intended to be cooled down, the

hydrogen concentration may be reduced below the normal

operating range to facilitate degassification, but hydrogen

levels of at least 15cc H 2/KgH2O should be maintained.

(d) Solids concentration determined by filtration through filter having 0.45 micron pore size. (e) Lithium control limits are established by administrative procedure based on the bounding parameters given in Table 5.2-7.(f) These limits are included in the table of reactor coolant specifications as recommended standards for monitoring coolant

purity.

Establishing coolant purity within the limits shown for these species is judged desirable with the current data base to minimize fuel clad crud deposition which affects the

corrosion resistance and heat transfer of the clad.

(g) Refer to the Technical Requirements Manual for required reactor coolant chemistry limits. Rev. 16 WOLF CR EEK TABL E 5.2-6 D ESIGN COMPARISON WITH R EGULATORY GUID E 1.45, DAT ED MAY 1973, TITL ED REACTOR COOLANT PR ESSURE BOUNDARY L EAKAGE DETECTION SYST EMS Regulatory Guide 1.45 Position WCGS C. R EGULATORY POSTION The source of reactor coolant leakage should be

identifiable to the extent practical. Reactor coolant pressure boundary leakage detection and collection systems should be selected and designed to include the following:

1. Leakage to the primary reactor containment from 1. Complies. Flow to the RCDT can be identified sources should be collected or otherwise established, is monitored, and is

isolated so that: separated from unidentified leakage.

a. the flow rates are monitored separately from unidentified leakage, and

b. the total flow rate can be established and

monitored.

2. Leakage to the primary reactor containment from 2. Complies. The instrumentation unidentified sources should be collected and the flow provided is such that over a period of rate monitored with an accuracy of one gallon per time (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or more), the collected flow minute (gpm) or better. rate can be determined with an accuracy of better than 1 gallon per minute.

3. At least three separate detection methods 3. Complies. The methods provided are should be employed and two of these methods should sump-level and flow (level versus time) be (1) sump level and flow monitoring and monitoring, airborne particulate Rev. 0 WOLF CREEK TABLE 5.2-6 (Sheet 2) Regulato ry Guide 1.45 Po sition WCG S(2) airborne particulate radioactivity monitoring. Rad ioactivity monitoring,The third method may be selected f rom the conta inment coole r condensate monitoring, following: and conta inment atmo sphere humidity mon itoring. a. mon itoring of conden sate flow rate from air coolers, b. monitoring of airborne gaseous radio- activity. Humidity, tempe rature, or pressure monitoring of the conta inment atmo sphere should be considered as alarms or indirect indication of leakage to the containment.4. Provisions should be made to mon itor systems 4. Compl ies. Refer to Sections connected to the RCPB fo r signs of intersystem 5.2.5.2.1, 9.3.3, and 11.5.

leakage. Method s should include radioactivity monitoring and indicators to show abnormal water levels or flow in the affected a rea. 5. The sensitivity and response time of each 5. Compl ies, as described in Section leakage detect ion system in regulatory position 5.2.5.2.3 and a s shown on F igure 5.2-2.

3. above employed fo r unidentified leakage should be adequate to detect a leakage rate, or its equivalent, of one gpm in less than one hou

r. 6. The leakage detect ion systems should be

6. Complies. The airborne particulate capable of performing their functions following radioactivity system is designed to seismic events that do not require plant shutdown.

remain functional when subjected to the The airborne particulate radioactivity monitoring SSE. Refer to Sections 11.5.2.3.2.2 and system should remain functional when subjected to 11.5.2.3.2.3. The remaining leakage the SSE. detect ion systems can reasonably be Rev. 20 WOLF CREEK TABLE 5.2-6 (Sheet 3) Regulato ry Guide 1.45 Po sition WCG S e xpected to remain functional follow ing seismic events of lesser severity than the SSE. Howeve r, no special qualifica- t ion program is used to assure operabil-ity under such conditions. 7. Indicators and alarms for each leakage 7. Compl ies, as described in Sections detection system should be provided in the main 5.2.5.2.3 and 5.2.5.5.

control room. Procedures for converting various indications to a common leakage equ ivalent should be available to the ope rators. The cal ibration of the indicators should account fo r needed independent va riables. 8. The leakage detect ion systems should be

8. Complies. Refer to Section 5.2.5.4.

equipped with provisions to readily permit testing for operability and cal ibration during plant ope ration. 9. The techn ical specifications should include 9. Compl ies. Refer to Techn ical Specifications. the limiting conditions for identified and The Conta inment Atmo sphere Particulate unidentified leakage and add ress the availability Radioactivity Monitor, Containment Sump of various types of instruments to assure adequate Level and Flow Mon itoring System, and coverage at all t imes. the Conta inment Air Cooler Condensate Monitoring System are specified in the Limiting Conditions for operation to monitor and detect leakage f rom the reactorcoolant p ressure boundary. Rev. 20 WOLF CREEK Table 5.2-7 Bounding Lithium-Boron-Cycle Time for Coordinated pH 7.1-7.2 Primary Coolant Chemistry Burnup,GWd/MTUCycle Time, efpdBoron,PpmLithium,ppm0019243.500.92223.115513.502.58364.815973.504.244106.415723.505.906148.114843.507.567189.813583.509.228231.412163.5010.889273.110413.1112.551314.88792.6114.212356.46832.0515.873398.15131.5917.534439.83451.1719.196481.41810.7820.857523.1240.4321.400536.8100.40Rev. 16

---

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.,.... I " N I 21 tiB"' 2, ,, ... ..-tO I I") *18 VENT STACK 83/4" I" EXTRUDED OUTL.ET *28" .128.38 O.D.I REV. 3 r* *toOtt WOLF CREEK _______ -------------

UPHAT-BD- AFE-T¥

-A-N-AlrY.SIS

-R:SP0RT Figure 5.2-1 INSTALLATION DETAIL FOR THE MAIN STEAM PRESSURE RELIEF DEVICES I -------------------------------------------------------------------------------------------------------------

---

..J w f-4: 0::: 5 WOLF CREEK .----------------r--------------------------------------------------------,

100 ' ' ' ' ' ' ' ' ' ' ' ' w 1-z 0 ;::: < ...J ::> u a:: u w a:: a:: <t 1-z w ::::; z <t 1-z 0 u ' I NOTE -THESE CURVES ARE BASED UPON A CONTINUOUS CONTAINMENT PURGE RATE OF 4000 CFM. AIR 97"F 45XRH OUTSIDE AIR 97" F 45:1. RH COOLANT INVENTORY BACKGROUND FACTOR

• 1 75 60 40 25 10 8 4 w ::> z ....... (/) z 0 _J _J 4: <...? MINIMUM TIME TO DETECT LEAKAGE OF 1 GPM REV. 23 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.2-2 PRIMARY COOLANT LEAK DETECTION RESPONSE TIME WOLF CREEK 5.3 REACTOR VESSEL 5.3.1 REACTOR VESSEL MATERIALS

5.3.1.1 Material Specifications Material specifications are in accordance with the ASME Code requirements and are given in Section 5.2.3.

The ferritic materials of the reactor vessel beltline are restricted to the following maximum limits of copper, phosphorous, and vanadium to reduce

sensitivity to irradiation embrittlement in service:

Base Metal As Deposited Weld Element (percent)

Metal (percent)

Copper 0.10 (Ladle) 0.10

0.12 (Check)

Phosphorous 0.012 (Ladle) 0.015

0.017 (Check)

Vanadium 0.05 (Check) 0.05 (as residual)

Figure 5.3-2 identifies the location of the beltline materials and welds for the WCGS reactor vessel. Table 5.3-7 contains weld identification information for these welds. Information concerning the fabrication and post-weld heat

treatment of the surveillance test specimen weld is identified in WCAP-10015 for WCGS. The test weldment is fabricated as a separate weld, not as an extension of a longitudinal weld seam.

5.3.1.2 Special Processes Used for Manufacturing and Fabrication

a. The vessel is Safety Class 1. Design and fabrication of the reactor vessel is carried out in strict accordance

with ASME Code,Section III, Class l requirements. The

head flanges and nozzles are manufactured as forgings.

The cylindrical portion of the vessel is made up of

formed plates joined by full penetration longitudinal

and girth weld seams. The hemispherical heads are made

from dished plates. The reactor vessel parts are joined by welding, using the single or multiple wire submerged arc and the shielded metal arc processes.

5.3-1 Rev. 1 WOLF CREEK

b. The use of severely sensitized stainless steel as a pressure boundary material has been prohibited and has

been eliminated by either choice of material or programming the method of assembly.

c. The control rod drive mechanism head adapter threads and surfaces of the guide studs are chrome plated to prevent possible galling of the mated parts.

d. At all locations in the reactor vessel where stainless steel and Inconel are joined, the final joining weld

beads are Inconel weld metal in order to prevent cracking.

e. The location of full penetration weld seams in the upper closure head and vessel bottom head are restricted to

areas that permit accessibility during inservice

inspection.

f. The stainless steel clad surfaces are sampled to assure that material composition requirements are met.

g. Freedom from underclad cracking is assured by special evaluation of the procedure qualification for cladding applied on low alloy steel (SA-508, Class 2).

h. Minimum preheat requirements have been established for pressure boundary welds, using low alloy material. The

preheat is maintained until either an intermediate or

full post-weld heat treatment is completed or until the completion of welding.

5.3.1.3 Special Methods for Nondestructive Examination The nondestructive examination of the reactor vessel and its appurtenances is conducted in accordance with ASME Code,Section III requirements; also numerous examinations are performed in addition to ASME Code,Section III requirements.

Nondestructive examination of the vessel is discussed in the following

paragraphs and the reactor vessel quality assurance program is given in Table 5.3-1.5.3.1.3.1 Ultrasonic Examination

a. In addition to the required ASME Code straight beam ultrasonic examination, angle beam inspection over 100 percent of one major surface of plate material is performed during fabrication to detect discontinuities that may be undetected by the straight beam examination.

5.3-2 Rev. 0 WOLF CREEK

b. In addition to the ASME Code,Section III nondestructive examination, all full penetration ferritic pressure

boundary welds in the reactor vessel are ultrasonically examined during fabrication. This test was performed upon completion of the welding and intermediate heat

treatment but prior to the final post-weld heat treatment.

c. After hydrotesting, all full penetration ferritic pressure boundary welds in the reactor vessel, as well

as the nozzle to safe end welds, are ultrasonically

examined. These inspections are also performed in

addition to the ASME Code,Section III nondestructive

examinations.

5.3.1.3.2 Penetrant Examinations The partial penetration welds for the control rod drive mechanism head adapters and the bottom instrumentation tubes were inspected by dye penetrant after the

root pass, in addition to code requirements. Core support block attachment

welds were inspected by dye penetrant after the first layer of weld metal and

after each 1/2 inch of weld metal. All clad surfaces and other vessel and head

internal surfaces were inspected by dye penetrant after the hydrostatic test.

5.3.1.3.3 Magnetic Particle Examination

The magnetic particle examination requirements below are in addition to the magnetic particle examination requirements of Section III of the ASME Code.

All magnetic particle examinations of materials and welds were performed in accordance with the following:

a. Prior to the final post-weld heat treatment - Only by the prod, coil, or direct contact method.

b. After the final post-weld heat treatment - Only by the yoke method.

The following surfaces and welds were examined by magnetic particle methods.

The acceptance standards are in accordance with Section III of the ASME Code.

Surface Examinations

a. Magnetic particle examine all exterior vessel and head surfaces after the hydrostatic test.

5.3-3 Rev. 0 WOLF CREEK

b. Magnetic particle examine all exterior closure stud surfaces and all nut surfaces after final machining or

rolling. Continuous circular and longitudinal magnetization is used.

c. Magnetic particle examine all inside diameter surfaces of carbon and low alloy steel products that have their properties enhanced by accelerated cooling. This

inspection is performed after forming and machining (if performed) and prior to cladding.

Weld Examination Magnetic particle examination of the weld metal build-up for vessel support welds, the closure head lifting lugs, and the refueling seal ledge to the

reactor vessel after the first layer and each 1/2 inch of weld metal is

deposited. All pressure boundary welds are examined after back chipping or back grinding operations.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels Welding of ferrite steels and austenitic stainless steels is discussed in Section 5.2.3. Section 5.2.3 includes discussions which indicate the degree of

conformance with Regulatory Guide 1.44. Appendix 3A discusses the degree of

conformance with Regulatory Guides 1.43, 1.50, 1.71, and 1.99.

5.3.1.5 Fracture Toughness Assurance of adequate fracture toughness of ferritic materials in the reactor coolant pressure boundary (ASME Code,Section III, Class 1 components) is

provided by compliance with the requirements for fracture toughness testing

included in NB-2300 to Section III of the ASME Code and Appendix G of 10 CFR

50.The initial Charpy V-notch minimum upper shelf fracture energy levels for the reactor vessel beltline (including welds) are 75 foot-pounds, as required per

Appendix G of 10 CFR 50. Materials having a section thickness greater than 10 inches with an upper shelf of less than 75 foot-pounds are evaluated with

regard to effects of chemistry (especially copper content), initial upper shelf

energy, and fluence to assure that a 50-foot-pound shelf energy, as required by

Appendix G of 10 CFR 50 is maintained throughout the life of the vessel. The

specimens are oriented as required by NB-2300 of Section III of the ASME Code.

The vessel fracture toughness data is provided in Table 5.3-3.

5.3-4 Rev. 0 WOLF CREEK Charpy V-notch test data for the heat-affected zone of the limiting beltline region plate is presented in WCAP 10015 for WCGS. Complete Charpy test results

for each weld and plate are provided in Tables 5.3-8 through 10. There are no other heat-affected zones which require impact testing per paragraph NB-4335.2 of the 1977 ASME Code. There are no ferritic base metals other than in the

vessel in the reactor coolant pressure boundary.

5.3.1.6 Material Surveillance In the surveillance program, the evaluation of radiation damage is based on preirradiation testing of Charpy V-notch and tensile specimens and

postirradiation testing of Charpy V-notch, tensile, and 1/2 T (thickness)

compact tension (CT) fracture mechanics test specimens. The program is

directed toward evaluation of the effect of radiation on the fracture toughness

of reactor vessel steels based on the transition temperature approach and the

fracture mechanics approach. The program conforms with ASTM E-185 "Recommended

Practice for Surveillance Tests for Nuclear Reactor Vessels," and 10 CFR 50, Appendix H.

The reactor vessel surveillance program prior to Refuel 14 used six specimen capsules. The capsules are located in guide baskets welded to the outside of the neutron shield pads and positioned directly opposite the center portion of

the core. The capsules can be removed when the vessel head is removed and can

be replaced when the internals are removed. The six capsules contain reactor

vessel steel specimens, oriented both parallel and normal (longitudinal and

transverse) to the principal rolling direction of the limiting base material

located in the core region of the reactor vessel and associated weld metal and

weld heat-affected zone metal. The six capsules contain 54 tensile specimens,

360 Charpy V-notch specimens (which include weld metal and weld heat-affected zone material), and 72 CT specimens. Archive material sufficient for two

additional capsules is retained.

Dosimeters, as described below, are placed in filler blocks drilled to contain them. The dosimeters permit evaluation of the flux seen by the specimens and the vessel wall. In addition, thermal monitors made of low melting point

alloys are included to monitor the maximum temperature of the specimens. The

specimens are enclosed in a tight-fitting stainless steel sheath to prevent corrosion and ensure good thermal conductivity. The complete capsule is helium leak tested. As part of the surveillance program, a report of the residual elements in weight percent to the nearest 0.01 percent is made for surveillance material and as-deposited weld metal.

5.3-5 Rev. 19 WOLF CREEK Each of the six capsules contains the following specimens:

Number of Number of Number of Material Charpys Tensiles CTs Limiting base material

• 15 3 4 Limiting base material

• • 15 3 4 Weld metal

• • • 15 3 4 Heat-affected zone 15 - -

• Specimens oriented in the major rolling or working direction.

• • Specimens oriented normal to the major rolling or working direction.

• • • Weld metal to be selected per ASTM E-185.

The following dosimeters and thermal monitors are included in each of the six capsules:

Dosimeters IronCopper Nickel Cobalt-aluminum (0.15 percent Co)

Cobalt-aluminum (cadmium shielded)

U-238 (cadmium shielded)

Np-237 (cadmium shielded)

Thermal Monitors 97.5 percent Pb, 2.5 percent Ag (579°F melting point)

97.5 percent Pb, 1.75 percent Ag, 0.75 percent Sn (590°F melting point) 5.3-6 Rev. 0 WOLF CREEK The fast neutron exposure of the specimens occurs at a faster rate than that experienced by the vessel wall, with the specimens being located between the

core and the vessel. Since these specimens experience accelerated exposure and are actual samples from the materials used in the vessel, the transition temperature shift measurements are representative of the vessel at a later time

in life. Data from CT fracture toughness specimens are expected to provide additional information for use in determining allowable stresses for irradiated material.

Correlations between the calculations and measurements of the irradiated samples in the capsules, assuming the same neutron spectrum at the samples and

the vessel inner wall, are described in Section 5.3.1.6.1. The anticipated degree to which the specimens perturb the fast neutron flux and energy distribution is considered in the evaluation of the surveillance specimen data.

Verification and possible readjustment of the calculated wall exposure is made

by the use of data on all capsules withdrawn. The schedule for removal of the

capsules for postirradiation testing is shown in Table 5.3-11 and conforms with

ASTM E-185 and Appendix H of 10 CFR 50. Changes to the schedule for removal of the capsules is required to be approved by the NRC in accordance with appendix H of 10 CFR 50. The results of the reactor vessel material irradiation surveillance specimens are used to update the RCS pressure/temperature limits for heatup, cooldown, inservice hydrostatic and leak testing, criticality and

PORV lift setting figures in the PTLR.

WCAP 10015 provides the location withdrawal schedule and lead factors for each capsule and the estimated reactor vessel end of life fluence at the 1/4 wall

thickness as measured from the ID.

5.3.1.6.1 Measurement of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples In order to effect a correlation between fast neutron (E > 1.0 MeV) exposure and the radiation-induced properties changes observed in the test specimens, a number of fast neutron flux monitors are included as an integral part of the reactor vessel surveillance program. In particular, the surveillance capsules contain detectors employing the following reactions.

Fe 54 (n,P) Mn 54 Ni 58 (n,P) Co 58 Cu 63 (n, ) Co 60 Np 237(n,f) Cs137 U 238(n,f) Cs137In addition, thermal neutron flux monitors, in the form of bare and cadmium shielded Co-Al wire, are included within the capsules to enable an assessment

of the effects of isotopic burnup on the response of the fast neutron

detectors. 5.3-7 Rev. 18 WOLF CREEK The use of activation detectors such as those listed above does not yield a direct measure of the energy dependent neutron flux level at the point of

interest. Rather, the activation process is a measure of the integrated effect that the time and energy dependent neutron flux has on the target material. An accurate estimate of the average neutron flux level incident on the various

detectors may be derived from the activation measurements only if the parameters of the irradiation are well known. In particular, the following variables are of interest:

a. The operating history of the reactor

b. The energy response of the given detector

c. The neutron energy spectrum at the detector location The procedure for the derivation of the fast neutron flux from the results of the Fe54(n,P) Mn54reaction is described below. The measurement technique for the other dosimeters, which are sensitive to different portions of the neutron

energy spectrum, is similar.

The Mn54product of the Fe 54(n,P) Mn54reaction has a half-life of 314 days and emits gamma rays of 0.84 MeV energy, which are easily detected using a NaI scintillator. In irradiated steel samples, chemical separation of the Mn 54maybe performed to ensure freedom from interfering activities. This separation is

simple and very effective, yielding sources of very pure Mn 54activity. In some samples, all of the interferences may be corrected for by the gamma

spectrometric methods without any chemical separation.

The analysis of the sample requires that two procedures be completed. First, the Mn54disintegration rate per unit mass of sample and the iron content of the sample must be measured as described above. Second, the neutron energy

spectrum at the detector location must be calculated.

For this analysis, the DOT (Ref. 1), two-dimensional multigroup discrete ordinates transport code is employed to calculate the spectral data at the

location of interest. Briefly, the DOT calculations utilize a 21 group energy

scheme, an S 8 order of angular quadrature, and a P 1 expansion of the scattering matrix to compute neutron radiation levels within the geometry of interest.

The reactor geometry employed here includes a description of the radial regions

internal to the primary concrete (core barrel, neutron pad, pressure vessel, and water annuli) as well as the surveillance capsule and an appropriate reactor core fuel loading 5.3-8 Rev. 0 WOLF CREEK pattern and power distribution. Thus, distortions in the fission spectrum due to the attenuation of the reactor internals are accounted for in the analytical

approach.

Having the measured activity, sample weight, and neutron energy spectrum at the location of interest, the calculation of the threshold flux is as follows:

The induced Mn 54activity in the iron flux monitors may be expressed as: D = NA f E F(1-eJ)ed oi(E)(E)j-t-tj=1nwhere:

D = induced Mn 54activity (dps/gm F e) N o = Avogadro's number (atoms/gm-atom)

A = atomic weight of iron (gm/gm-atom) f i = weight fraction of Fe 54 in the detector (E) = energy dependent activation cross-section for the Fe 54 (n,p)Mn54reaction (barns) (E) = energy dependent neutron flux at the detector at full reactor power (n/cm 2 sec) = decay constant of Mn 54(1/sec) F J = fraction of full reactor power during the Jth time interval, Jj = length of the Jth irradiation period (sec) d = decay time following the Jth irradiation period (sec)

The parameters F J,J, and d depend on the operating history of the reactor and the delay between capsule removal and sample counting.

The integral term in the above equation may be replaced by the following relation:

5.3-9 Rev. 1 WOLF CREEK (E)(E) = =

--ETH-ETHSSSETHEEE0where:- = effective spectrum average reaction cross-section for neutrons above energy, E TH-ETH = average neutron flux above energy, E THS(E) = multigroup Fe 54(n,P)Mn54reaction cross-sections compatible with the DOT energy group structure S(E) = multigroup energy spectra at the detector location obtained from the DOT analysis ETH = threshold energy for damage correlation Thus,D = NA F (1-e) e oi--ETHJ-J-dj=1nor, solving for the threshold flux:

-ETHoi-J-tJj=1n-td = DNA f F(1 - e eThe total fluence above energy ETH is given by: ETH-ETHJ Jj=1n = Fwhere FJ Jj=1n represents the total effective full power seconds of reactor operation up to the time of capsule removal. 5.3-10 Rev. 1 WOLF CREEK Because of the relatively long half-life of Mn 54the fluence may be accurately calculated in this manner for irradiation periods up to about 2 years. Beyond this time, the calculated average flux begins to be weighted toward the later stages of irradiation, and some inaccuracies may be introduced. At these longer irradiation times, therefore, more reliance must be placed on Np 237 and U238 fission detectors with their 30 year half-life product (Cs 137).No burnup correction was made to the measured activities, since burnout of the Mn54product is not significant until the thermal flux level is about 10 14n/cm2-sec.The error involved in the measurement of the specific activity of the detector after irradiation is estimated to be 5 percent.

5.3.1.6.2 Calculation of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples The energy and spatial distribution of neutron flux within the reactor geometry is obtained from the DOT (Ref. 1) two-dimensional Sn transport code. The

radial and azimuthal distributions are obtained from an R,R computation wherein

the reactor core as well as the water and steel annuli surrounding the core are

modeled explicitly. The axial variations are then obtained from an R,Z DOT

calculation, using the equivalent cylindrical core concept. The neutron flux

at any point in the geometry is then given by: (E,R,,Z) = í(E,R,) F(Z) Where f(E,R,) is obtained directly from the R, calculation and F(Z) is a normalized function obtained from the R,Z analysis. The core power distributions used in both the R, and R,Z computations represent the expected average over the life of the station.

Having the calculated neutron flux distributions within the reactor geometry, the exposure of the capsule as well as the lead factor between the capsule and

the vessel may be determined as follows:

The neutron flux at the surveillance capsule is given by: c = (E,R c,c,Zc)and the flux at the location of peak exposure on the pressure vessel inner diameter is: v-max = (E,Rvv-max,Zv-max) 5.3-11 Rev. 1 WOLF CREEK The lead factor then becomes: LF = cv-maxSimilar expressions may be developed for points within the pressure vessel wall; and, thus, together with the surveillance program dosimetry, serve to

correlate the radiation induced damage to test specimens with that of the reactor vessel.

5.3.1.6.3 Ex-vessel surveillance program The Reactor Cavity Neutron Measurement Program at Wolf Creek after Refuel 14 is designed to provide a verification of fast neutron exposure distributions within the reactor vessel wall and to establish a mechanism to enable long term monitoring of those portions of the reactor vessel and vessel support structure that could experience significant radiation induced increases in reference nil ductility transition temperature (RT NDT) over the service lifetime of the plant.

When used in conjunction with dosimetry from internal surveillance capsules and with the results of neutron transport calculations, the reactor cavity neutron measurements allow the projection of embrittlement gradients through the reactor vessel wall with a minimum uncertainty. Minimizing the uncertainty in the neutron exposure projections will, in turn, help to assure that the reactor can be operated in the least restrictive mode possible with respect to10CFR50 Appendix G pressure/temperature limit curves for normal heat up and cool down of the reactor coolant system, Emergency Response Guideline (ERG) pressure/temperature limit curves, and Pressurized thermal shock (PTS) RT NDT screening criteria.

In addition, an accurate measure of the neutron exposure of the reactor vessel and support structure can provide a sound basis for requalification should operation of the plant beyond the current design and/or licensed lifetime prove to be desirable. The reactor cavity neutron dosimetry is installed in the annular air gap between the reactor vessel insulation and the primary concrete shield wall. The reactor cavity neutron dosimetry consist of aluminum dosimeter capsules connected to and supported by stainless steel bead chain. Each dosimetry chain is attached to and hangs from a stainless steel spring hook mounting plate. The local attachment plates are affixed to the horizontal portion of the reflective insulation below the reactor vessel nozzles (plant elevation 2012'+0.5") using four No. 14 x 3/4-long self-tapping sheet metal screws. The attachment plates are located in the vicinity of the Loop 1 outlet nozzle (at Reactor Angles of 5°, 15°, 30°, and 40°).

In some pressurized water reactor designs (like Wolf Creek) the neutron exposure rate at the surveillance capsule locations is much greater than that at the peak location on the reactor vessel. The ratio of these exposure rates is referred to as the surveillance capsule lead factor. Lead factors of three to five are not uncommon. With a high lead factor the reactor vessel material samples in a surveillance capsule may, if left in the reactor, receive neutron damage well beyond any projected end-of-life condition, thus rendering them useless. For example, a capsule with a lead factor of five would receive a 60-year exposure in as little as 12 years. This issue is particularly important for those plants planning for license renewal. The recently issued Generic Aging Lessons Learned (GALL) Report (NUREG-1801, April 2001),Section XI.M31 Reactor Vessel Surveillance, provides the following guidance for surveillance capsule management. 5.3-12 Rev. 19 WOLF CREEK A plant with a surveillance program containing capsules with projected fast neutron fluence exceeding a 60-year fluence at the end of 40 years, i.e., a lead factor greater than 1.5, should remove the capsules when they reach the 60-year exposure. One of these capsules should be tested to meet the requirements of ASTM E185 and the remaining capsules should be placed in storage without material testing. Subsequently, an alternative dosimetry program will need to be instituted to monitor reactor vessel neutron exposure through the license renewal period.

The NRC staff has recognized the importance of preserving the material specimens within the surveillance capsules. Any capsules that are to be left in the reactor vessel are to provide meaningful metallurgical data. For a high lead factor plant, if the remaining surveillance capsules are left in place, the material specimens will be irradiated well beyond the predicted end-of-life fast neutron exposure. At a projected end-of-life of 40 years, a surveillance capsule with a lead factor of three will have experienced the equivalent of a reactor vessel exposure of 120 years. Thus the material specimens would be damaged to such an extent that they would be unable to provide any useful data. With passive neutron sensors located in the reactor cavity the neutron exposure of the reactor vessel can be continuously monitored throughout plant life, as required by Appendix H, and the surveillance capsules can be removed and stored on site thus preserving this critical, irreplaceable material for future use.

Thus the material specimens would: Monitor important azimuthal and axial exposure gradients over the entire beltline region of reactor vessel (unavailable with surveillance capsules) and provide measurements in proximity to critical areas on the reactor vessel. Provide long term monitoring that permits continuous evaluation of the effect of changes in reactor operation and changing fuel management schemes on the reactor vessel exposure, and Minimize the uncertainty in reactor vessel exposure projections using a combination of measurements and analytical predictions. Within the nuclear industry it has been common practice to base estimates of the fast neutron exposure of reactor vessels either directly on the results of neutron transport calculations or on the analytical results normalized to measurements obtained from internal surveillance capsules. There are potential drawbacks associated with both of these approaches to exposure assessment.

In performing neutron transport calculations for pressurized water reactors, several design and operational variables have an impact on the magnitude of the analytical prediction of fast neutron exposure rates within the reactor vessel wall. Particularly important are cycle-to-cycle variations in core power distributions (especially with the implementation of low leakage loading patterns), variations of water temperature (density) in the peripheral fuel assemblies and the downcomer regions of the reactor internals, and deviations in as-built versus design dimensions for the reactor internals and vessel. Treatment of these important variables in the analysis leads to an increased uncertainty in the exposure predictions for the reactor vessel and may well result in the use of overly conservative estimates of reactor vessel embrittlement in the assessment of pressure / temperature limitations as well as of the expected lifetime of the components.

With the addition of supplementary passive neutron sensors in the reactor cavity annulus between the reactor vessel wall and the biological shield, the deficiencies in both surveillance capsule dosimetry and analytical prediction can be alleviated and the uncertainties associated with exposure estimates for the reactor vessel can be minimized. With state of the art neutron sensors deployed to establish the 5.3-13 Rev. 19 WOLF CREEK absolute magnitude of the azimuthal and axial exposure rate distributions in the reactor cavity, the burden placed on the neutron transport calculation is reduced.An ex-vessel neutron dosimetry program can also provide additional data to support license renewal. As a comprehensive system to characterize the neutron exposure of the reactor vessel, it has the flexibility Studies have shown that the operational and design variables cited above (that have a strong impact on the calculated magnitude of exposure rates) have only a minor effect on both the interpretation of reactor cavity measurements and on the extrapolation of measurement results to key reactor vessel locations. It is possible, therefore, to employ reactor cavity neutron measurements and plant specific calculations to produce reactor vessel exposure projections with a reduced uncertainty and without the excess conservatism inherent in an approach based on analysis alone. Furthermore, since the reactor cavity neutron measurements are not directly tied to the materials surveillance program, measurement intervals can be chosen to easily provide integral reactor vessel exposure over plant lifetime.

When the last surveillance capsule is removed for analysis, it is highly desirable to also analyze the Ex-Vessel Neutron Dosimetry. This provides a simultaneous in-vessel and ex-vessel measurement that results in the lowest uncertainty in the projected reactor vessel fluence and provides the most direct link between the existing in-vessel measurements and the ex-vessel measurements that will be used to monitor the neutron exposure of the vessel once the remaining surveillance capsules are withdrawn and placed in storage. The use of fast (E > 1.0 MeV) neutron fluence to correlate measured materials properties changes to the neutron exposure of the material for light-water reactor applications has traditionally been accepted for the development of damage trend curves as well as for the implementation of trend curve data to assess reactor vessel condition. In recent years, however, it has been suggested that an exposure model that accounts for differences in neutron energy spectra between surveillance capsule locations and positions within the reactor vessel wall could lead to an improvement in the uncertainties associated with damage trend curves as well as to a more accurate evaluation of damage gradients through the reactor vessel wall.

Because of this potential shift away from a threshold fluence toward an energy dependent damage function for data correlation, ASTM Standard Practice E853, Analysis and Interpretation of Light-Water Reactor Surveillance Results, recommends reporting displacements per iron atom (dpa) along with fast neutron fluence (E > 1.0 MeV) to provide a data base for future reference. The energy dependent dpa function to be used for this evaluation is specified in ASTM Standard Practice E693, Characterizing Neutron Exposures in Iron and Low Alloy Steels in Terms of Displacements Per Atom. The application of the dpa parameter to the assessment of embrittlement gradients through the thickness of the reactor vessel wall has already been promulgated in Revision 2 to Regulatory Guide 1.99, Radiation Damage to Reactor Vessel Materials.

With the aforementioned views in mind, the Ex-Vessel Neutron Dosimetry Program was established to meet the following objectives: Determine azimuthal and axial gradients of fast neutron exposure over the beltline region of the reactor vessel, Provide measurement capability sufficient to allow the determination of exposure parameters in terms of both fast (E > 1.0 MeV) neutron fluence and iron displacements per atom (dpa), and Provide a long-term monitoring capability for the beltline region of the reactor vessel and vessel support structure. 5.3-14 Rev. 19 WOLF CREEK Technical Description To achieve the goals of the Ex-Vessel Neutron Dosimetry (EVND) Program, two types of measurements are made. Comprehensive sensor sets including radiometric monitors (RM) are employed at discrete locations within the reactor cavity to characterize the neutron energy spectrum variations axially and azimuthally over the beltline region of the reactor vessel. In addition, stainless steel gradient chains are used in conjunction with the encapsulated dosimeters to complete the mapping of the neutron environment between the discrete locations chosen for spectrum determinations.

In choosing sensor set locations for the Ex-Vessel Neutron Dosimetry Program, advantage is taken of the octant symmetry typical of pressurized water reactors. That is, subject to access limitations, spectrum measurements are concentrated to obtain azimuthal flux distributions in a single forty-five degree sector. Placement of the discrete sensor sets is such that spectrum determinations are made at various locations (5, 15, 30, and 40 degrees) on the midplane of the active core to measure the spectrum changes caused by the varying amounts of water located between the core and the reactor vessel. These thickness changes are due to the stair step shape of the reactor core periphery relative to the cylindrical geometry of the reactor internals and vessel and to the local nature of the neutron pads. The remaining sensor sets may be positioned opposite the top and bottom of the active core or opposite key reactor vessel welds at particular azimuthal angles of interest. Here the intent is to measure axial variations in neutron spectrum over the core height, particularly near the top of the fuel where back scattering of neutrons from primary loop nozzles and reactor vessel support structures can produce significant differences. At each of the azimuthal locations selected for spectrum measurements, stainless steel gradient chains extend over the full height of the active fuel.

Sensor Sets The Ex-Vessel Neutron Dosimetry Program employs advanced sensor sets that are recommended by and are designed to the latest ASTM neutron dosimetry standards.

The sensor sets consist of the following encapsulated dosimeters and gradient chains. Table 1 lists the neutron reactions that are of interest.

1. Radiometric Monitors (RM) - these include cadmium-shielded foils of the following metals: copper, titanium, iron, nickel, and cobalt-aluminum. Cadmium shielded fast fission reactions include 238U and 237Np in vanadium encapsulated oxide detectors. Bare iron and cobalt monitors are also included.

2. Gradient Chains - These stainless steel bead chains connect and support the dosimeter capsules containing the radiometric monitors. These segmented chains provide iron, nickel, and cobalt reactions that are used to complete the determination of the axial and azimuthal gradients. The high purity iron, nickel, and cobalt-aluminum foils contained in the multiple foil sensor sets provide a direct correlation with the measured reaction rates from these gradient chains. These crosscomparisons permit the use of the gradient measurements to derive neutron flux distributions in the reactor cavity with a high level of confidence. 5.3-15 Rev. 19 WOLF CREEK MaterialReaction of InterestNeutronEnergyResponse(a)

ProductHalf-Life Dosimeter CapsulePosition(b)

GradientChain(c)Copper63Cu(n,)60Co4.53-11 MeV 5.271 yr 2-CdNoTitanium46Ti(n,p) 46Sc3.70-9.43 MeV83.79 d 2-CdNoIron54Fe(n,p) 54Mn2.27-7.54 MeV312.3 d 1-B & 2-Cd YesNickel58Ni(n,p) 58Co1.98-7.51 MeV70.82 d 2-CdYes238U(d)238U(n,f)137Cs1.44-6.69 MeV30.07 yr 3-CdNo46Np46237Np(n,f)137Cs0.68-5.61 MeV30.07 yr 3-CdNoCobalt-Al 59Co(n,) 60CoThermal5.271 yr 1-B & 2-Cd YesNotes:a) Energies between which 90% of activity is produced (

235U fission spectrum).

b) B denotes bare and Cd denotes cadmium shielded c) Determined with additional radiochemical analysis d) For the fission monitors 95Zr (64.02 d) and 103Ru (39.26 d) activities are also reported 5.3.1.7 Reactor Vessel Fasteners The reactor vessel closure studs, nuts, and washers are designed and fabricated in accordance with the requirements of the ASME Code,Section III. The closure

studs are fabricated of SA-540, Class 3, Grade B24. The closure stud material

meets the fracture toughness requirements of the ASME Code,Section III and 10

CFR 50, Appendix G. Compliance with Regulatory Guide 1.65, "Materials and

Inspections for Reactor Vessel Closure Studs," is discussed in Appendix 3A.

Nondestructive examinations are performed in accordance with the ASME Code,

Section III.

Refueling procedures require that the studs, nuts, and washers be removed from the reactor closure and be placed in storage racks or suspended in the reactor vessel head belt ring holes while the head is removed to its storage stand during preparation for refueling. The storage racks are then removed from the refueling cavity and stored at convenient locations in containment or their cleaning location prior to removal of the reactor closure head and refueling cavity flooding. When a stud cannot be removed from the reactor vessel flange,

it is covered with a protective cover. Therefore, the reactor closure studs

are never exposed to the borated refueling cavity water. Additional protection

against the possibility of incurring corrosion effects is assured by the use of a manganese base phosphate surfacing treatment.

The stud holes in the reactor flange are sealed with special plugs prior to flooding the reactor cavity, thus preventing leakage of the borated refueling water into the stud holes. When a stud cannot be removed, the protective cover installed over the stud also protects the stud hole from the borated refueling

water. 5.3-16 Rev. 19 WOLF CREEK 5.3.2 PRESSURE - TEMPERATURE LIMITS 5.3.2.1 Limit Curves Startup and shutdown operating limitations are based on the properties of the reactor pressure vessel beltline materials. Actual material property test data

are used. The methods outlined in Appendix G to Section III of the ASME Code

are employed for the shell regions in the analysis of protection against

nonductile failure. The initial operating curves are calculated, assuming a

period of reactor operation such that the beltline material is that the

beltline material is limiting. The heatup and cooldown curves are given in the

Pressure and Temperature Limits Report. Beltline material properties degrade

with radiation exposure, and this degradation is measured in terms of the adjusted reference nil-ductility temperature, which includes a reference nil-ductility temperature shift (RTNDT).PredictedRTNDT values are derived using two curves: the effect of fluence and copper content on the shift of RT NDT for the reactor vessel steels exposed to 550°F temperature curve and the maximum fluence at 1/4 T (thickness) and 3/4 T location (tips of the code reference flaw when flaw is assumed at inside diameter and outside diameter locations, respectively) curve. These curves are

presented in the PTLR. For a selected time of operation, this shift is

assigned a sufficient magnitude so that no unirradiated ferritic materials in

other components of the reactor coolant system (RCS) is limiting in the

analysis.

The operating curves including pressure-temperature limitations are calculated in accordance with 10 CFR 50, Appendix G and ASME Code,Section III, Appendix

G, requirements.

The results of the material surveillance program described in Section 5.3.1.6 is used to verify that the RTNDT predicted from the effects of the fluence and copper content curve is appropriate and to make any changes necessary to

correct the fluence and copper curves if RTNDT determined from the surveillance program is greater than the predicted RTNDT. Temperature limits for preservice hydrotests and inservice leak and hydrotests are calculated in accordance with Appendix G of the ASME Code,Section III.

Compliance with Regulatory Guide 1.99 is discussed in Appendix 3A.

5.3.2.2 Operating Procedures The transient conditions that are considered in the design of the reactor vessel are presented in Section 3.9(N).1.1. These transients are representative of the operating conditions that should prudently be considered to occur during plant operation. The transients selected form a conservative basis for evaluation of the RCS to insure the integrity of the RCS equipment.

Those transients listed as upset condition transients are given in Table 3.9(N)-1. None of these transients result in pressure-temperature changes

which exceed the heatup and cooldown limitations, as described in Section 5.3.2.1 and in the PTLR. 5.3-17 Rev. 19 WOLF CREEK 5.3.3 REACTOR VESSEL INTEGRITY 5.3.3.1 Design The reactor vessel is cylindrical with a welded hemispherical bottom head and a removable, bolted, flanged, and gasketed hemispherical upper head. The reactor vessel flange and head are sealed by two hollow metallic 0-rings. Seal leakage is detected by means of two leakoff connections: one between the inner and outer ring and one outside the outer 0-ring. The vessel contains the core, core support structures, control rods, and other parts directly associated with the core. The reactor vessel closure head contains head adapters. These head adapters are tubular members, attached by partial penetration welds to the underside of the closure head. The upper end of these adapters contains Acme

threads for the assembly of control rod drive mechanisms or instrumentation adapters. The seal arrangement at the upper end of these adapters consists of a welded flexible canopy seal. Inlet and outlet nozzles are located

symmetrically around the vessel. Outlet nozzles are arranged on the vessel to

facilitate optimum layout of the RCS equipment. The inlet nozzles are tapered from the coolant loop vessel interfaces to the vessel inside wall to reduce loop pressure drop.

The bottom head of the vessel contains penetration nozzles for connection and entry of the nuclear incore instrumentation. Each nozzle consists of a tubular member made of either an Inconel or an Inconel-stainless steel composite tube.

Each tube is attached to the inside of the bottom head by a partial penetration

weld.Internal surfaces of the vessel which are in contact with primary coolant are weld overlay with 0.125 inch minimum of stainless steel or Inconel.

The reactor vessel is designed and fabricated in accordance with the requirements of the ASME Code,Section III. Principal design parameters of the

reactor vessel are given in Table 5.3-2. The reactor vessel is shown in Figure

5.3-1.There are no special design features which would prohibit the in-situ annealing of the vessel. If the unlikely need for an annealing operation was required to restore the properties of the vessel material opposite the reactor core because of neutron irradiation damage, a metal temperature greater than 650°F for a period of 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> maximum would be applied. Various modes of heating may be used, depending on the temperature required. 5.3-18 Rev. 19 WOLF CREEK The reactor vessel materials surveillance program is adequate to accommodate the annealing of the reactor vessel. Sufficient specimens are available to

evaluate the effects of the annealing treatment.

Cyclic loads are introduced by normal power changes, reactor trips, and startup and shutdown operations. These design base cycles are selected for fatigue evaluation and constitute a conservative design envelope for the projected plant life. Vessel analysis results in a usage factor that is less than 1.

The design specifications require analysis to prove that the vessel is in compliance with the fatigue and stress limits of the ASME Code,Section III.

The loadings and transients specified for the analysis are based on the most severe conditions expected during service. The analyzed heatup and cooldown rates imposed by plant operating limits are 100°F in any one hour except for cooldown of the pressurizer, which is limited to 200°F in any one hour. In

practice, these operations occur more slowly. These rates are reflected in the

vessel design specifications.

5.3.3.2 Materials of Construction The materials used in the fabrication of the reactor vessel are discussed in Section 5.2.3.

5.3.3.3 Fabrication Methods The WCGS reactor vessel manufacturer is Combustion Engineering Corporation.

The fabrication methods used in the construction of the reactor vessel are discussed in Section 5.3.1.2.

5.3.3.4 Inspection Requirements The nondestructive examinations performed on the reactor vessel are described in Section 5.3.1.3.

5.3.3.5 Shipment and Installation The reactor vessel is shipped in a horizontal position on a shipping sled with a vessel-lifting truss assembly. All vessel openings are sealed to prevent the

entrance of moisture, and an adequate quantity of desiccant bags is placed

inside the vessel. These are usually placed in a wire mesh basket attached to

the vessel cover. All carbon steel surfaces, except for the vessel support

surfaces and the top surface of the external seal ring, are painted with a

heat-resistant paint before shipment. 5.3-19 Rev. 19 WOLF CREEK The closure head is also shipped with a shipping cover and skid. An enclosure attached to the ventilation shroud support ring protects the control rod

mechanism housings. All head openings are sealed to prevent the entrance of moisture, and an adequate quantity of desiccant bags is placed inside the head.

These are placed in a wire mesh basket attached to the head cover. All carbon

steel surfaces are painted with heat-resistant paint before shipment. A lifting frame is provided for handling the vessel head.

5.3.3.6 Operating Conditions Operating limitations for the reactor vessel are presented in Section 5.3.2, as well as in the PTLR.

In addition to the analysis of primary components discussed in Section 3.9(N).1.4, the reactor vessel is further qualified to ensure against unstable

crack growth under faulted conditions. Actuation of the emergency core cooling

system (ECCS) following a loss-of-coolant accident produces relatively high thermal stresses in regions of the reactor vessel which come into contact with ECCS water. Primary consideration is given to these areas, including the reactor vessel beltline region and the reactor vessel primary coolant nozzle,

to ensure the integrity of the reactor vessel under this severe postulated transient.

The principles and procedures of linear elastic fracture mechanics (LEFM) are used to evaluate thermal effects in the regions of interest. The LEFM approach to the design against failure is basically a stress intensity consideration in which criteria are established for fracture instability in the presence of a crack. Consequently, a basic assumption employed in LEFM is that a crack or

crack-like defect exists in the structure. The essence of the approach is to

relate the stress field developed in the vicinity of the crack tip to the applied stress on the structure, the material properties, and the size of

defect necessary to cause failure.

The elastic stress field at the crack tip in any cracked body can be described by a single parameter designated as the stress intensity factor, K. The

magnitude of the stress intensity factor K is a function of the geometry of the

body containing the crack, the size and location of the crack, and the

magnitude and distribution of the stress.

The criterion for failure in the presence of a crack is that failure will occur whenever the stress intensity factor exceeds some critical value. For the

opening mode of loading (stresses 5.3-20 Rev. 19 WOLF CREEK perpendicular to the major plane of the crack), the stress intensity factor is designated as K I and the critical stress intensity factor is designated K IC.Commonly called the fracture toughness, K IC is an inherent material property which is a function of temperature and strain rate. Any combination of applied load, structural configuration, crack geometry, and size which yields a stress intensity factor K IC for the material will result in crack instability.

The criterion of the applicability of LEFM is based on plasticity considerations at the postulated crack tip. Strict applicability (as defined

by ASTM) of LEFM to large structures where plane strain conditions prevail

requires that the plastic zone developed at the tip of the crack does not

exceed 2.25 percent of the crack depth. In the present analysis, the plastic

zone at the tip of the postulated crack can reach 20 percent of the crack

depth. However, LEFM has been successfully used to provide conservative

brittle fracture prevention evaluations, even in cases where strict

applicability of the theory is not permitted due to excessive plasticity.

Recently, experimental results from the Heavy Section Steel Technology (HSST)

Program intermediate pressure vessel tests have shown that LEFM can be applied

conservatively as long as the pressure component of the stress does not exceed

the yield strength of the material. The addition of the elastically calculated

thermal stresses, which results in total stresses in excess of the yield

strength, does not affect the conservatism of the results, provided that these

thermal stresses are included in the evaluation of the stress intensity

factors. Therefore, for faulted conditions analyses, LEFM is considered

applicable for the evaluation of the vessel inlet nozzle and beltline region.

In addition, it has been well established that the crack propagation of existing flaws in a structure subjected to cyclic loading can be defined in

terms of fracture mechanics parameters. Thus, the principles of LEFM are also

applicable to fatigue growth of a postulated flaw at the vessel inlet nozzle and beltline region.

Additional details on this method of analysis of reactor vessels under severe transients are given in Reference 2.

5.3.3.7 Inservice Surveillance The internal and external surfaces of the reactor vessel are accessible for periodic inspection. Visual and/or nondestructive techniques are used. During

refueling, the vessel cladding is capable of being inspected in certain areas

between the closure flange and the primary coolant inlet nozzles, and, if

deemed necessary, the core barrel is capable of being removed, making the

entire inside vessel surface accessible. 5.3-21 Rev. 19 WOLF CREEK The closure head is examined visually during each refueling, Optical devices permit a selective inspection of the cladding, control rod drive mechanism

nozzles, and the gasket seating surface. The knuckle transition piece, which is the area of highest stress of the closure head, is accessible on the outer surface for visual inspection, dye penetrant or magnetic particle, and

ultrasonic testing. The closure studs and nuts can be inspected periodically using visual, magnetic particle, and ultrasonic techniques.

The closure studs, nuts, washers, and the vessel flange seal surface, as well as the full penetration welds in the following areas of the installed reactor

vessel, are available for nondestructive examination:

a. Vessel shell - from the inside and outside surfaces

b. Primary coolant nozzles - from the inside and outside surfaces

• c. Closure head - from the inside and outside surfaces.

Bottom head - from the inside and outside surfaces.

d. Field welds between the reactor vessel nozzle safe ends and the main coolant piping - from the inside and outside

surfaces.

The design considerations which have been incorporated into the system design to permit the above inspection are as follows:

a. All reactor internals are completely removable. The tools and storage space required to permit these

inspections are provided.

b. The closure head is stored dry on the reactor operating deck during refueling to facilitate direct visual

inspection.

c. Reactor vessel studs, nuts, and washers can be removed to dry storage during refueling. Studs which cannot be removed are covered to protect from borated refueling pool water, subsequently cleaned and inspected in-situ.

d. Access is provided to the reactor vessel nozzle safe

ends. The insulation covering the nozzle-to-pipe welds

may be removed.

• Only partial outside diameter coverage is provided. 5.3-22 Rev. 19 WOLF CREEK

e. Reactor cavity is designed to allow access to the outside surface of the vessel. Tracks are installed to allow

mechanical equipment to inspect the vessel surface.

The reactor vessel presents access problems because of the radiation levels and remote underwater accessibility to this component. Because of these limitations on access to the reactor vessel, several steps have been incorporated into the design and manufacturing procedures in preparation for

the periodic nondestructive tests, which are required by the ASME inservice inspection code. These are:

a. Shop ultrasonic examinations are performed on all internally clad surfaces to an acceptance and repair standard to assure an adequate cladding bond to allow later ultrasonic testing of the base metal from inside

surface. The size of cladding bond defect allowed is 1/4

inch by 3/4 inch with the greater direction parallel to

the weld in the region bounded by 2T (T = wall thickness)

on both sides of each full penetration pressure boundary

weld. Unbounded areas exceeding 0.442 square inches (3/4

inch diameter) in all other regions are rejected.

b. The design of the reactor vessel shell is an uncluttered cylindrical surface to permit future positioning of the test equipment without obstruction.

c. The weld deposited clad surface on both sides of the welds to be inspected is specifically prepared to assure

meaningful ultrasonic examinations.

d. During fabrication, all full penetration ferritic pressure boundary welds are ultrasonically examined in addition to Code examinations.

e. After the shop hydrostatic testing, all full penetration ferritic pressure boundary welds, as well as the nozzle

to safe end welds, are ultrasonically examined from both

the inside and outside diameters in addition to ASME

Code,Section III requirements.

The vessel design and construction enable inspection in accordance with the ASME Code,Section XI. The reactor vessel inservice inspection program is in

accordance with ASME Section XI as described in the Inservice Inspection

Program and PTLR. 5.3-23 Rev. 19 WOLF CREEK 5.

3.4 REFERENCES

1. Soltesz, R. G., et al., "Nuclear Rocket Shielding Methods, Modification, Updating, and Input Data Preparation, Volume 5 -

Two-Dimensional Discrete Ordinates Techniques,"

WANL-PR-(LL)-034, August, 1970.

2. Bachalet, C., Bamford, W. H., and Chirigos, J. N., "Method for Fracture Mechanics Analysis of Nuclear Reactor Vessels Under Severe Thermal Transients," WCAP-8510, December 1975.3. Singer, L. R. Kansas Gas and Electric Company Wolf Creek Generating Station Unit No. 1 Reactor Vessel Radiation Surveillance Program, WCAP-10015, June 1982. 5.3-24 Rev. 19 WOLF CREEK TABL E 5.3-1 R EACTOR VESSEL QUALITY ASSURANC E PROGRAM RT* UT*

PT*

MT*

Forgings Flanges Yes Yes

Studs and nuts Yes Yes CRD head adapter flange Yes Yes CRD head adapter tube Yes Yes

Instrumentation tube Yes Yes

Main nozzles Yes Yes

Nozzle safe ends Yes Yes Plates Yes Yes Weldments Main seam Yes Yes Yes

CRD head adapter to clos-

ure head connection Yes

Instrumentation tube to bottom head connection Yes

Main nozzle Yes Yes Yes

Cladding Yes Yes

Nozzle to safe ends Yes Yes Yes

CRD head adapter flange

to CRD head adapter

tube Yes Yes

All full penetration ferri-

tic pressure boundary

welds accessible after

hydrotest Yes Yes

Full penetration nonferri-

tic pressure boundary

welds accessible after

hydrotest

a. Nozzle to safe ends Yes Yes

b. CRD head adapter

flange to CRD head

adapter tube Yes Rev. 0 WOLF CREEK TABL E 5.3-1 (Sheet 2)

RT* UT*

PT*

MT*

Seal ledge Yes Head lift lugs Yes

Core pad welds Yes

• RT - Radiographic UT - Ultrasonic

PT - Dye Penetrant

MT - Magnetic Particle NOTE:Base metal weld repairs as a result of UT, MT, RT, and/or PT indications are cleared by the same ND E technique/procedure by which the indications were found. The repair meets all Section

III requirements.

In addition, UT examination per the in-process/post-hydro UT requirements is performed on the following:

1. Base metal repairs in the core region.

2. Base metal repairs in the ISI zone (1/2 T).

Rev. 0 WOLF CREEK TABL E 5.3-2 R EACTOR VESSEL DESIGN PARAM ETERSDesign/operating pressure, psig 2,485/2,317

• Design temperature, F 650 Overall height of vessel and closure head, bottom head outside diameter to top of

control rod mechanism adapter, ft-in. 43-10 Thickness of RPV head insulation, minimum, in. 3

Number of reactor closure head studs 54

Diameter of reactor closure head/studs, minimum shank, in. 6-13/16 Outside diameter of flange, in. 205

Inside diameter of flange, in. 167

Outside diameter at shell, in. 190-1/2

Inside diameter at shell, in. 173

Inlet nozzle inside diameter, in. 27-1/2 Outlet nozzle inside diameter, in. 29

Clad thickness, minimum, in. 1/8

Lower head thickness, minimum, in. 5-3/8

Vessel beltline thickness, minimum, in. 8-5/8

Closure head thickness, in. 7 Nominal water volume, ft 3 3,700

• The operating pressure used to control the plant is 2,235 psig and is measured in the pressurizer.

Rev. 0 WOLF CREEK TABL E 5.3-3 R EACTOR VESSEL MATERIAL PROP ERTIES Avg. Upper Shelf MAT ERIAL Cu P TNDT RTNDT NMWD

• • MWD*COMPONENT COD E NO. SPEC. NO. (%)

(%) (F)

(F) (FT-LB)

(FT-LB)

Closure Head Dome R2516-1 A533B, CL.1 0.12 0.010 -40 0 112 -

Closure Head Torus R2515-1 A533B, CL.1 0.11 0.009 -20 -20 119 -

Closure Head Flange R2504-1 A508 CL. 2 - 0.013 20 20 139 -

Vessel Flange R2501-1 A508 CL. 2 - 0.012 20 20 102 -

Inlet Nozzle R2502-1 A508 CL. 2 - 0.010 -20 -20 147 -

Inlet Nozzle R2502-2 A508 CL. 2 - 0.009 -20 -20 137 -

Inlet Nozzle R2502-3 A508 CL. 2 0.11 0.010 -20 -20 156 -

Inlet Nozzle R2502-4 A508 CL. 2 0.11 0.010 -30 -30 156 -

Outlet Nozzle R2503-1 A508 CL. 2 - 0.006 -10 -10 126 -

Outlet Nozzle R2503-2 A508 CL. 2 - 0.009 0 0 129 -

Outlet Nozzle R2503-3 A508 CL. 2 - 0.007 0 0 136 -

Outlet Nozzle R2503-4 A508 CL. 2 - 0.007 0 0 114 -

Nozzle Shell R2004-1 A533B, CL. 1 0.05 0.010 -40 10 118 -

Nozzle Shell R2004-2 A533B, CL. 1 0.04 0.011 -40 20 121 -

Nozzle Shell R2004-3 A533B, CL. 1 0.04 0.008 -50 0 133 -

Inter. Shell R2005-1 A533B, CL. 1 0.04 0.008 -20 -20 127 156

Inter. Shell R2005-2 A533B, CL. 1 0.04 0.007 -30 -20 127 143

Inter. Shell R2005-3 A533B, CL. 1 0.05 0.007 -30 -20 135 164

Lower Shell R2508-1 A533B, CL. 1 0.09 0.009 -40 0 87 118

Lower Shell R2508-2 A533B, CL. 1 0.06 0.008 -10 10 100 127

Lower Shell R2508-3 A533B, CL. 1 0.07 0.008 -20 40 86 127

Bottom Head Torus R2517-1 A533B, CL. 1 0.11 0.010 -80 -30 92 -

Bottom Head Dome R2518-1 A533B, CL. 1 0.12 0.009 -60 -60 154 -

Inter. and lower shell G2.06 SAW 0.04 0.006 -50 -50 150 -

long. weld seams Inter. to lower shell E3.16 SAW 0.05 0.007 -50 -50 98 -

girth weld seam

Weld HAZ - - - - -80 -80 171 -

_________________

• Major working direction

• • Normal to major working direction Rev. 0 WOLF CREEK TABLE 5.3-4 HAS BEEN DELETED REV. 0 WOLF CREEK TABLE 5.3-5 IS DELETED REV. 0 TABL E 5.3-6Deleted Rev. 14 WOLF CREEK TABLE 5.3-7 VESSEL BELTLINE REGION WELD METAL IDENTIFICATION INFORMATION Weld Weld Procedure Weld Wire Flux Weld Seam Identification Control No. Qual. No. Type Heat No. Type Lot No.Int. shell long weld seam 101-124A, B, and C G2.06 SAA-SMA-12.12-102 B4 90146Linde 0091 0842Lower shell long weld seam 101-142A, B, and C G2.06 SAA-SMA-12.12-102 B4 90146Linde 0091 0842 Inter. to lower shell girth seam 101-171 E3.16 SAA-SMA-3.3-118 B4 90146Linde 124 1061 Surveillance test weld E3.16 SAA-SMA-3.3-118 B4 90146Linde 124 1061 Weld Metal Chemical Composition (Wt. %) C M P S S C N M C V Weld Control No. n i r i o u G2.06 .15 1.16 .006 .011 .18 .05 .04 .51 .04 .005 E3.16 .097 1.27 .007 .011 .52 .09 .05 .50 .05 .004 NOTES1. The test weld was fabricated from plates R2508-1 and R2508-3.2. The test weldment was stress relieved at 1150

°F for 10.25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> - furnace cooled.

Rev. 0 WOFL CREEK TABLE 5.3-8 BELTLINE REGION INTERMEDIATE SHELL PLATE TOUGHNESS Plate R2005-1 Plate R2005-2 Plate R2005-3 Temp. Energy Shear Lat. Exp. Temp. Energy Shear Lat. Exp. Temp. Energy Shear Lat. Exp.

(F) (ft lb) (%)

(mils)

(F)

(ft lb) (%)

(mils)

(F)

(ft lb) (%)

(mils)

-60 6 0 2 -60 10 0 4 -60 6 0 2

-60 7 0 3 -60 11 0 6 -60 7 0 3

-60 7 0 2 -60 8 0 3 -60 6 0 2

-20 20 5 14 -20 25 5 18 -20 20 5 10

-20 27 10 17 -20 48 20 32 -20 11 0 4

-20 14 0 8 -20 37 15 24 -20 12 0 4

40 72 30 48 30 39 15 28 30 49 20 35

40 62 25 40 30 65 30 46 30 55 25 38

40 58 25 39 30 70 35 48 30 59 30 41

60 73 30 46 40 69 35 49 40 65 30 44

60 56 25 36 40 79 40 55 40 58 30 40

60 69 30 44 40 82 40 56 40 84 40 58

100 95 40 65 60 78 30 51 60 65 25 45

100 96 50 64 60 89 30 53 60 87 30 52

100 89 50 63 60 80 30 52 60 86 30 57

160 122 100 77 100 105 70 69 100 94 40 62

160 126 100 76 100 102 70 70 100 97 40 61

160 132 100 80 100 108 70 75 100 108 50 72

160 128 100 84 160 140 100 81

160 125 100 78 160 136 100 74

160 127 100 79 160 129 100 77 T

NDT -20°F T NDT -30°F T NDT -30°F RT NDT -20°F RT NDT -20°F RT NDT -20°F Rev. 0 WOLF CREEK TABLE 5.3-9 BELTLINE REGION LOWER SHELL PLATE TOUGHNESS Plate R2508-1 Plate R2508-2 Plate R2508-3 Temp. Energy Shear Lat. Exp. Temp. Energy Shear Lat. Exp. Temp. Energy Shear Lat. Exp.

(F) (ft lb) (%)

(mils)

(F) (ft lb) (%)

(mils)

(F)

(ft lb) (%)

(mils)

-40 12 0 5 -30 22 5 11 -40 5 0 2

-40 12 0 6 -30 17 0 8 -40 4 0 1

-40 13 0 6 -30 23 5 13 -40 5 0 1

0 28 10 22 10 28 10 15 0 19 5 15

0 29 10 22 10 31 10 19 0 15 0 12

0 27 10 22 10 29 10 17 0 16 0 12

20 32 10 26 50 41 15 26 40 34 15 23

20 37 15 30 50 52 25 36 40 29 10 19

20 40 20 32 50 49 20 32 40 27 10 16

50 53 30 40 60 48 20 34 90 54 25 44

50 52 35 38 60 47 20 34 90 48 25 38

50 46 30 33 60 45 20 33 90 53 25 42

60 58 40 42 70 56 25 39 100 52 25 41

60 65 50 51 70 55 25 40 100 57 30 43

60 56 40 41 70 60 30 42 100 58 30 47

100 84 80 61 100 63 40 45 160 93 100 71

100 74 70 58 100 59 30 42 160 79 100 68

100 78 70 60 100 76 50 53 160 86 100 74

160 87 100 62 160 96 90 68 212 85 100 66

160 88 100 65 160 96 90 64 212 80 100 64

160 87 100 66 160 97 90 68 212 87 100 66

212 100 100 68

212 96 100 64

212 104 100 71 T

NDT -40°F T NDT -10°F T NDT -20°F RT NDT 0°F RT NDT 10°F RT NDT 40°F Rev. 0 WOLF CREEK TABLE 5.3-10 BELTLINE REGION WELD METAL TOUGHNESS Weld Control No. G2.06 Weld Control No. E3.16 Temp. Energy Shear Lat. Exp. Temp. Energy Shear Lat. Exp.(°F) (ft lb) (%) (mils) (°F) (ft lb) (%) (mils)

-60 20 0 12 -80 11 0 9

-60 23 5 10 -80 8 0 4

-60 26 5 14 -80 7 0 6

-40 39 20 23 -40 45 20 33

-40 31 15 16 -40 42 20 30

-40 43 20 26 -40 32 15 27

-20 75 40 50 10 58 30 41

-20 108 60 63 10 52 25 37

-20 58 30 38 10 60 40 46 10 102 60 61 60 106 80 69

10 128 80 79 60 92 90 64

10 120 70 71 60 97 90 61

20 125 80 77 100 97 95 73 20 119 70 78 100 95 95 68

20 123 70 68 100 103 95 72

60 151 100 88 160 99 100 71 60 150 100 87 160 96 100 72

60 148 100 87 160 95 100 79

100 148 100 80

100 155 100 85

100 145 100 81 T

NDT -50°F T NDT -50°F RT NDT -50°F RT NDT -50°F Rev. 0 WOLF CREEK TABLE 5.3-11 REACTOR VESSEL MATERIAL SURV EILLANCE PROGRAM - WITHDRAWAL SCH EDULE CAPSULE VESSEL LEAD NUMBER LOCATION FACTOR WITHDRAWAL TIM E U 58.5° 4.25 1.07 EFPY(b) Y 241° 3.93 4.79 EFPY(b) V 61° 4.02 9.78 EFPY(b) X 238.5° 4.30 13.83 EFPY(b) W 121.5° 4.11 14 th Refueling (Storage) Z 301.5° 4.11 14 th Refueling (Storage) (a) Updated in Capsule X dosimetry analysis. (b) Capsule withdrawn and analyzed.

NOTE: Changes to the schedule for removal of the capsules is required to be approved by the NRC in accordance with Appendix H of 10CFR50.

Rev. 18 I I I I I i \ \ 0 .. " "' \\1$. l I ' I I I i I i ' I I i I j I I i I I I I I ' r ) I I l. I t 2 = Ill .. ... Ill -... I "' ,..., "' "' == 1.1) > u.,. ... a: .. li a: 0 => .... "' <.> ... < ... Ill a: i Do Cl I CORE WOLF CREEK -l -l w I (I) ex: w 1-2 -l -l w I (I) R2005-1 R2508-2 ex:

w 0 -l 101-142C 101-124A 101-1248 270° goo 101-142A 101-1428 R2508-1 270° Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.3-2 WOLF CREEK UNIT 1 REACTOR VESSEL BELTLINE REGION MATERIAL IDENTIFICATION AND LOCATION WOLF CREEK 5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4.1 REACTOR COOLANT PUMPS

5.4.1.1 Design Bases

The reactor coolant pump provides an adequate core cooling flow rate for heat

transfer to maintain a departure from nucleate boiling ratio (DNBR) greater

than the Safety Analysis Limit DNBR as defined in the COLR within the parameters of operation. The required net positive suction head is by

conservative pump design always less than that available by system design and

operation. Sufficient pump rotation inertia is provided by a flywheel, in

conjunction with the impeller and motor assembly, to provide adequate flow

during coastdown. This forced flow following an assumed loss of pump power, and the subsequent natural circulation effect provides the core with adequate

cooling flow.

The reactor coolant pump motor is tested, without mechanical damage, at

overspeeds up to and including 125 percent of normal speed. The retention of

integrity of the flywheel during a LOCA is demonstrated in Reference 1.

Steam/water tests planned jointly by Westinghouse, Framatome, and the French

Atomic Energy Commission (CEA) are discussed in Reference 2. The ultimate use

of the data from this testing will be to develop an empirical two-phase flow pump performance model. It is expected that this new model will confirm that the present pump model conservatively predicts performance in all LOCA

conditions and thus increase the safety margin available in the emergency core

cooling system (ECCS) and reactor coolant pump overspeed analyses.

The pump/motor system is designed for the SSE at the site.

5.4.1.2 Pump Description 5.4.1.2.1 Design Description

The reactor coolant pump is shown in Figure 5.4-1. The reactor coolant pump design parameters are given in Table 5.4-1. Code and material requirements are

provided in Section 5.2.

The reactor coolant pump is a vertical, single stage, controlled leakage,

centrifugal pump designed to operate at high temperatures and pressures.

The pump consists of three major sections. They are the hydraulics, the seals,

and the motor.

5.4-1 Rev. 13 WOLF CREEK

a. The hydraulic section consists of the casing, thermal

barrier, flange, impeller/diffuser, and diffuser

adapter.

b. The shaft seal section consists of three primary devices. They are the number 1 controlled leakage, film riding face seal, and the number 2 and number 3 rubbing face seals. These seals are contained within the thermal barrier heat exchanger assembly and seal housing.

Collectively, they provide a pressure breakdown from the reactor coolant system (RCS) pressure to ambient conditions. A fourth sealing device called a shutdown seal is housed within the No. 1 seal area and is passively actuated by high temperature if seal cooling is lost.

c. The motor is a drip-proof squirrel cage induction motor

with a vertical solid shaft, an oil lubricated double-

acting Kingsbury type thrust bearing, upper and lower

oil lubricated radial guide bearings, and a flywheel.

Additional components of the pump are the shaft, pump radial bearing, thermal

barrier heat exchanger, coupling, spool piece, and motor stand.

5.4.1.2.2 Description of Operation

Reactor coolant enters the suction nozzle, is directed to the impeller by the

diffuser adapter, is pumped through the diffuser, and exits through the

discharge nozzle.

Seal injection flow, under slightly higher pressure than the reactor coolant,

enters the pump through a connection of the thermal barrier flange and is

directed into the plenum between the thermal barrier housing and the shaft.

The flow splits with a portion flowing down the shaft through the radial

bearing and into the RCS; the remainder flows up the shaft through the seals.

Component cooling water is provided to the thermal barrier heat exchanger.

During normal operation, the thermal barrier limits the heat transfer from hot

reactor coolant to the radial bearing and to the seals. In addition, if a loss

of seal injection flow should occur, the thermal barrier heat exchanger cools

reactor coolant to an acceptable level before it enters the bearing and seal

area.

Reactor coolant pump operation with either seal water injection or component

cooling water alone is acceptable for an unlimited time. As described in

Sections 9.2.2 and 9.3.4 the component cooling water and the injection paths

provide diverse cooling means which precludes seal failures due to any single

failure or due to the effects of an SSE.

5.4-2 Rev. 27 WOLF CREEK The reactor coolant pump motor bearings are of conventional design. The radial

bearings are the segmented pad type, and the thrust bearing is a double-acting

Kingsbury type. All are oil lubricated. Component cooling water is supplied

to the external upper bearing oil cooler and to the integral lower bearing oil cooler. The reactor coolant pump motor bearings are qualified for 10 minutes

operation without component cooling water with no resultant damage.

The motor is a water/air cooled, Class F thermalastic epoxy insulated, squirrel

cage induction motor. The rotor and stator are of standard construction and

are cooled by air.

Six resistance temperature detectors are imbedded in the stator windings to

sense stator temperature. The top of the motor consists of a flywheel and an

antireverse rotation device.

The internal parts of the motor are cooled by air. Integral vanes on each end

of the rotor draw air in through cooling slots in the motor frame. This air

passes through the motor with particular emphasis on the stator end turns. It

is then routed to the external water/air heat exchangers, which are supplied

with component cooling water. Each motor has two such coolers, mounted

opposite each other . In passing through the coolers, the air is cooled to

below 122°F so that little heat is rejected to the containment from the motors.

Each of the reactor coolant pumps is equipped for continuous monitoring of

reactor coolant pump shaft and frame vibration levels. Shaft vibration is

measured by two relative shaft probes mounted on top of the pump seal housing;

the probes are located 90 degrees apart in the same horizontal plane and

mounted near the pump shaft. Frame vibration is measured by two velocity

seismoprobes located 90 degrees apart in the same horizontal plane and mounted at the top of the motor support stand. The converter's output, which linearizes the probe output, and proximeter output is displayed in the control

room. The displays automatically indicate the highest output from the relative

probes and seismoprobes; manual selection allows the monitoring of individual

probes. Indicator lights display caution and danger limits of vibration.

A removable shaft segment, the spool piece, is located between the motor

coupling flange and the pump coupling flange; the spool piece allows removal of

the pump seals with the motor in place. The pump internals, motor, and motor

stand can be removed from the casing without disturbing the reactor coolant

piping. The flywheel is available for inspection by removing the cover.

5.4-3 Rev. 1 WOLF CREEK Parts of the pump in contact with the reactor coolant are austenitic stainless

steel, except for seals, bearings, and special parts.

5.4.1.3 Design Evaluation

5.4.1.3.1 Pump Performance

The reactor coolant pumps are sized to deliver flow at rates which equal or exceed the flow rates required for core cooling. Initial RCS tests confirm the

total delivery capability. Thus, assurance of adequate forced circulation

coolant flow is provided prior to initial plant operation.

The estimated performance characteristic is shown in Figure 5.4-2. The "knee"

at about 45-percent design flow introduces no operational restrictions, since

the pumps operate at full flow.

The reactor trip system assures that pump operation and core cooling capability

are within the assumptions used for loss of flow analyses (See Chapter 15.0).

In addition, in the event that a reactor coolant pump is taken out of service during operation, adequate core cooling is provided, and continued plant

operation without a reactor trip can be accommodated if the reactor coolant

pump is stopped following an orderly reduction in power. The WCGS Technical

Specifications require shutdown to hot standby within six hours after a reactor

coolant pump stops.

Long-term tests have been conducted on less than full scale prototype seals, as

well as on full size seals. Operating plants continue to demonstrate the

satisfactory performance of the controlled leakage shaft seal pump design.

The support of the stationary member of the number 1 seal ("seal ring" ) is

such as to allow large deflections, both axial and tilting, while still

maintaining its controlled gap relative to the seal runner. Even if all the

graphite were removed from the pump bearing, the shaft could not deflect far enough to cause opening of the controlled leakage gap. The "spring-rate" of the hydraulic forces associated with the maintenance of the gap is high enough

to ensure that the ring follows the runner under very rapid shaft deflections.

Testing of pumps with the number 1 seal entirely bypassed (full system pressure

on the number 2 seal) shows that small (approximately 4 to 12 gpm) leakage

rates would be maintained for a period of time sufficient to secure the pump.

Even if the number 1 seal were to fail entirely during normal operation, the

number 2 seal would maintain these small leakage rates if the proper action is

5.4-4 Rev. 0 WOLF CREEK taken by the operator. An increase in number 1 seal leakoff rate will warn the

plant operator of number 1 seal damage. Following warning of excessive seal

leakage conditions, the plant operator will take corrective actions. Gross

leakage from the pump does not occur if these procedures are followed.

Loss of offsite power causes loss of power to the pump and causes a temporary

stoppage in the supply of seal injection flow to the pump and also of the

component cooling water flow to the pump and motor. The emergency diesel

generators are started automatically due to loss of offsite power so that seal

injection flow is provided by the charging pumps. Component cooling water flow

is subsequently restored automatically, within 2 minutes. Load shedding and

sequencing is discussed in Section 8.3.

In the event of a loss of all AC power and/or loss of all seal cooling, the shutdown seal (SDS) will actuate on high seal cooling temperature to limit leakage from the RCP seal package. Leakage is limited when a thermal actuator retracts and causes the SDS piston ring and polymer ring to clamp down around the pump shaft

5.4.1.3.2 Coastdown Capability

It is important to reactor protection that the reactor coolant flow is

maintained for a short time after a pump trip in order to remove heat stored in

the fuel elements of the core. In order to provide this flow after

interruption of power to the pumps, each reactor coolant pump is provided with

a flywheel. The rotating inertia of the pump, motor, and flywheel is employed

during the coastdown period to continue the reactor coolant flow. An inadvertent early actuation of the SDS on the pump shaft, with the shaft still rotating, will not adversely impact RCP coastdown. The coastdown flow transients are provided in the figures in Section 15.3. The coastdown

capability of the pumps is maintained even under the most adverse case of a

blackout coincident with the SSE. Core flow transients and figures are

provided in Sections 15.3.1 and 15.3.2.

5.4.1.3.3 Bearing Integrity

The design requirements for the reactor coolant pump bearings are primarily

aimed at giving an accurate alignment and smooth operation over long periods of

time in order to ensure a long life with negligible wear. The surface-bearing

stresses are held at a very low value, and even under the most severe seismic

transients remain below stress values that can be adequately carried for short

periods of time.

Because there are no established criteria for short-time stress-related

failures in such bearings, it is not possible to make a meaningful

quantification of such parameters as margins to failure, safety factors, etc.

A qualitative analysis of the bearing design, embodying such considerations,

gives assurance of the adequacy of the bearing to operate without failure.

5.4-5 Rev. 27 WOLF CREEK Low oil levels in the lube oil sumps signal alarms in the control room and

require shutting down of the pump. Each motor bearing contains embedded

temperature detectors and so initiation of failure, separate from loss of oil,

is indicated and alarmed in the control room as a high bearing temperature.

This, again, requires pump shutdown. If these indications are ignored, and the

bearing proceeded to failure, the low melting point of Babbitt metal on the pad

surfaces ensures that sudden seizure of the shaft will not occur. In this

event, the motor continues to operate, as it has sufficient reserve capacity to

drive the pump under such conditions. However, the high torque required to

drive the pump will require high current which will lead to the motor being

shutdown by the electrical protection systems.

5.4.1.3.4 Locked Rotor

It may be hypothesized that the pump impeller might severely rub on a

stationary member and then seize. This constitutes a loss-of-coolant flow in

the loop. Analysis has shown that under such conditions, assuming

instantaneous seizure of the impeller, the pump shaft fails in torsion just

below the coupling to the motor, thus disengaging the flywheel and motor from

the shaft. Following such a postulated seizure, the motor continues to run

without any overspeed, and the flywheel maintains its integrity, as it is still

supported on a shaft with two bearings. Flow transients are provided in the

figures in Section 15.3.3 for the assumed locked rotor.

There are no credible sources of shaft seizure other than impeller rubs. A

sudden seizure of the pump bearing is precluded by graphite in the bearing.

Any seizure in the seals results in a shearing of the antirotation pin in the

seal ring. An inadvertent actuation of the shutdown seal on the shaft will not interrupt core cooling flow provided by the RCP. The motor has adequate power to continue pump operation even after the above occurrences. Indications of

pump malfunction in these conditions are initially by high temperature signals

from the bearing water temperature detector and excessive number 1 seal leakoff

indications, respectively. Following these signals, pump vibration levels are

checked. Excessive vibration indicates mechanical trouble and the pump is shut

down for investigation.

5.4.1.3.5 Critical Speed

The reactor coolant pump shaft is designed so that its operating speed is below

its first critical speed. This shaft design, even under the most severe

postulated transient, gives low values of actual stress.

5.4-6 Rev. 27 WOLF CREEK 5.4.1.3.6 Missile Generation

Precautionary measures taken to preclude missile formation from primary coolant

pump components assure that the pumps do not produce missiles under any anticipated accident condition. Each component of the primary pump motors has

been analyzed for missile generation. Any fragments of the motor rotor would

be contained by the heavy stator. The same conclusion applies to the pump

impeller because the small fragments that might be ejected would be contained

in the heavy casing. Further discussion and analysis of missile generation is

contained in Reference 1 and Section 3.5.

5.4.1.3.7 Pump Cavitation

The minimum net positive suction head required by the reactor coolant pump at running speed is approximately a 192-foot head (approximately 85 psi). In order for the controlled leakage seal to operate correctly, it is necessary to

require a minimum differential pressure of approximately 200 psi across the

number 1 seal. This corresponds to a primary loop pressure at which the

minimum net positive suction head is exceeded, and no limitation on pump

operation occurs.

5.4.1.3.8 Pump Overspeed Considerations

For turbine trips actuated by either the reactor trip system or the turbine

protection system, the generator and reactor coolant pumps are maintained

connected to the external network for 30 seconds to prevent any pump overspeed

condition. The overspeed condition is prevented by the dynamic braking action

of the pump motor. In case a generator trip de-energizes the pump busses, the

reactor coolant pump motors are transferred to offsite power within 6 to 10 cycles. Further discussion of pump overspeed considerations and missile generation is contained in Reference 1 and Section 3.5.

5.4.1.3.9 Antireverse Rotation Device

Each of the reactor coolant pumps is provided with an antireverse rotation

device in the motor. This antireverse mechanism consists of pawls mounted on

the outside diameter of the flywheel, a serrated ratchet plate mounted on the

motor frame, a spring return for the ratchet plate, and two shock absorbers.

5.4-7 Rev. 1 WOLF CREEK At an approximate forward speed of 70 rpm, the pawls drop and bounce across the

ratchet plate; as the motor continues to slow, the pawls drag across the

ratchet plate. After the motor has slowed and come to a stop, the dropped

pawls engage the ratchet plate and, as the motor tends to rotate in the

opposite direction, the ratchet plate also rotates until it is stopped by the

shock absorbers. The rotor remains in this position until the motor is

energized again. When the motor is started, the ratchet plate is returned to

its original position by the spring return. As the motor begins to rotate, the

pawls drag over the ratchet plate. When the motor reaches sufficient speed,

the pawls are bounced into an elevated position and are held in that position

by friction resulting from centrifugal forces acting upon the pawls. While the

motor is running at speed, there is no contact between the pawls and ratchet

plate.

Considerable plant experience with the design of the antireverse rotation

device has shown high reliability of operation.

5.4.1.3.10 Shaft Seal Leakage

During normal operation, leakage along the reactor coolant pump shaft is controlled by three shaft seals arranged in series so that reactor coolant

leakage to the containment is essentially zero. Injection flow is directed to

each reactor coolant pump via a seal water injection filter. It enters the

pumps through a connection of the thermal barrier flange and flows to an

annulus around the shaft inside the thermal barrier. Here the flow splits: a

portion flows down the shaft to cool the bearing and enters the RCS; the

remainder flows up the shaft through the seals. This flow provides a

backpressure on the number 1 seal and a controlled flow through the seal.

Above the seal, most of the flow leaves the pump via the number 1 seal

discharge line. Minor flow passes through the number 2 seal and leakoff line.

A back flush injection from a head tank flows into the number 3 seal between

its "double dam" seal area. At this point, the flow divides with half flushing

through one side of the seal and out the number 2 seal leakoff while the

remaining half flushes through the other side and out of the number 3 seal

leakoff. This arrangement assures essentially zero leakage of reactor coolant

or trapped gases from the pump.

In the event of a loss of all AC power and/or loss of all seal cooling, reactor coolant begins to travel along the RCP shaft and displace the cooler seal injection water. The shutdown seal (SDS) actuates once the No. 1 seal package temperature reaches the SDS actuation temperature. SDS actuation controls shaft seal leakage and limits the loss of reactor coolant through the RCP seal package.

5.4.1.3.11 Seal Discharge Piping

The number 1 seal reduces the coolant pressure to that of the volume control

tank. Water from each pump number 1 seal is piped to a common manifold,

through the seal water return filter, and through the seal water heat exchanger

where the temperature is

5.4-8 Rev. 27 WOLF CREEK reduced to that of the volume control tank. The number 2 and number 3 leakoff

lines dump number 2 and 3 seal leakage to the reactor coolant drain tank and

the containment sump, respectively.

5.4.1.4 Tests and Inspections The reactor coolant pumps can be inspected in accordance with the ASME Code,

Section XI, for inservice inspection of nuclear reactor coolant systems.

The pump casing is cast in one piece, eliminating welds in the casing. Support

feet are cast integral with the casing to eliminate a weld region.

The design enables disassembly and removal of the pump internals for usual

access to the internal surfaces of the pump casing.

The reactor coolant pump quality assurance program is given in Table 5.4-2.

5.4.1.5 Pump Flywheels 5.4.1.5.1 Pump Flywheel Integrity

The integrity of the reactor coolant pump flywheel is assured on the basis of the following design and quality assurance procedures.

5.4.1.5.2 Design Basis

The calculated stresses at operating speed are based on stresses due to

centrifugal forces. The stress resulting from the interference fit of the

flywheel on the shaft is less than 2,000 psi at zero speed, but this stress

becomes zero at approximately 600 rpm because of radial expansion of the hub.

The primary coolant pumps run at approximately 1,190 rpm and may operate

briefly at overspeeds up to 109 percent (1,295 rpm) during loss of load. For conservatism, however, 125 percent of operating speed was selected as the design speed for the primary coolant pumps. The flywheels were given a

preoperational test of 125 percent of the maximum synchronous speed of the

motor.

5.4.1.5.2.1 Fabrication and Inspection

The flywheel consists of two thick plates bolted together. The flywheel

material is produced by a process that minimizes flaws in the material and

improves its fracture toughness properties, such as vacuum degassing, vacuum

melting, or electroslag remelting. Each plate is fabricated from SA-533, Grade

B, Class 1 steel.

5.4-9 Rev. 0 WOLF CREEK Supplier certification reports are available for all plates and demonstrate the

acceptability of the flywheel material on the basis of the requirements of

Regulatory Guide 1.14.

Flywheel blanks are flame-cut from the SA-533, Grade B, Class 1 plates with at

least 1/2 inch of stock left on the outer and bore radii for machining to final

dimensions. The flywheel plates, both before and after assembly, are subjected

to magnetic particle or liquid penetrant examination. Included in this

examination are all surfaces within a minimum radial distance of 4 inches

beyond the final machined bore. This includes the bore surface and the

keyways. The finished flywheels, as well as the flywheel material (rolled

plate), are subjected to 100-percent volumetric ultrasonic inspection, using

procedures and acceptance standards specified in Section III of the ASME Code.

5.4.1.5.2.2 Material Acceptance Criteria

The reactor coolant pump motor flywheel conforms to the following material

acceptance criteria:

a. The nil-ductility transition temperature (NDTT) of the

flywheel material is obtained by two drop weight tests

(DWT) which exhibit "no-break" performance at 20°F in

accordance with ASTM E-208. The above drop weight tests

demonstrate that the NDTT of the flywheel material is no

higher than 10°F.

b. A minimum of three Charpy V-notch impact specimens from

each plate are tested at ambient (70°F) temperature in

accordance with the specification ASME SA-370. The Charpy V-notch (C V) energy in both the parallel and normal orientation with respect to the rolling direction of the flywheel material is at least 50 foot pounds at

70°F, and, therefore, RT NDT of 10°F can be assumed. An evaluation of flywheel overspeed has been performed

which concludes that flywheel integrity will be

maintained (Ref. 1).

As stated in reference 1, the normal operating temperature is 120°F. The

charpy V-notch and dropweight tests confirm that the normal operating

temperature is in excess of 100°F above the RT NDT of the flywheel material.

Thus, it is concluded that flywheel plate materials are suitable for use and

can meet Regulatory Guide 1.14 acceptance criteria on the bases of the

suppliers' certification data. The degree of compliance with Regulatory Guide

1.14 is further discussed in Appendix 3A.

5.4-10 Rev. 1 WOLF CREEK 5.4.1.5.2.3 Accessibility

The reactor coolant pump motors are designed so that, by removing the cover to

provide access, the flywheel is available to allow an inservice inspection program in accordance with requirements of Section XI of the ASME Code and the

recommendations of Regulatory Guide 1.14.

5.4.1.5.2.4 Spin Testing

Each flywheel assembly is spin tested at the design speed of the flywheel,

i.e., 125 percent of the maximum synchronous speed of the motor.

5.4.1.5.3 Preservice Inspection

Post spin testing of reactor coolant pump flywheels is discussed in Appendix 3A under the response to Regulatory Guide 1.14.

5.4.1.5.4 Inservice Inspection

The reactor coolant pump flywheels are inservice inspected in accordance with

the recommendations given in Regulatory Guide 1.14, "Reactor Coolant Pump

Flywheel Integrity," Revision 1, August 1975. The Administrative Controls portion of the Technical Specifications provides specific information on the commitment to the inspection requirements of Regulatory Guide 1.14.

5.4.2 STEAM GENERATORS

5.4.2.1 Design Bases

Steam generator design data are given in Table 5.4-3. Code classifications of

the steam generator components are given in Section 3.2. Although the ASME

classification for the secondary side is specified to be Class 2, all pressure-

retaining parts of the steam generator, and thus both the primary and secondary

pressure boundaries, are designed to satisfy the criteria specified in Section

III of the ASME Code for Class 1 components. The design stress limits,

transient conditions, and combined loading conditions applicable to the steam

generator are discussed in Section 3.9(N).1. Estimates of radioactivity levels

anticipated in the secondary side of the steam generators during normal

operation and the bases for the estimates are given in Chapter 11.0. The accident analysis of a steam generator tube rupture is discussed in Chapter 15.0.

5.4-11 Rev. 10 WOLF CREEK The internal moisture separation equipment is designed to ensure that moisture

carryover does not exceed 0.25 percent by weight under the following

conditions:

a. Steady state operation up to 100 percent of full load

steam flow, with water at the normal operating level.

b. Loading or unloading at a rate of 5 percent of full

power steam flow per minute in the range from 15 to 100

percent of full load steam flow.

c. A step load change of 10 percent of full power in the

range from 15 to 100 percent full load steam flow.

The water chemistry on the reactor side is selected to provide the necessary boron content for reactivity control and to minimize corrosion of RCS surfaces.

The water chemistry of the steam side and its effectiveness in corrosion

control are discussed in Chapter 10.0. Compatibility of steam generator tubing

with both primary and secondary coolants is discussed further in Section

5.4.2.3.2.

The steam generator is designed to prevent unacceptable damage from mechanical

or flow-induced vibration. Tube support adequacy is discussed in Section

5.4.2.5.3. The tubes and tube sheet are analyzed and confirmed to withstand

the maximum accident loading conditions as they are defined in Section

3.9(N).1. Further consideration is given in Section 5.4.2.5.4 to the effect of

tube wall thinning on accident condition stresses.

Access is provided to the primary side channel heads of the steam generator in order to permit inservice inspection and tube plugging, when required. Access is provided to the shell side of the steam generator in the region of the tube

sheet and flow distribution baffle in order to permit inservice inspection and

removal of accumulated sludge.

5.4.2.2 Design Description The steam generator is a Westinghouse Model F, vertical shell and U-tube

evaporator, with integral moisture separating equipment. Figure 5.4-3

illustrates the design, indicating several of its design features which are described in the following paragraphs.

The Model F steam generator is similar in configuration to the Model 51 steam

generators in Westinghouse-supplied plants that are in operation. The Model F

incorporates several improved features that have been developed through

modification programs in operating steam generators. These features are

illustrated in Figure

5.4-12 Rev. 0 WOLF CREEK 5.4-4 and include: preferential distribution of feedwater to the hot leg

portion of the tube bundle, removal of downcomer resistance, blockage of the

tube lane, and improvements to the primary and secondary steam separators. The

net effect of these changes, as has been demonstrated with the use of special instrumentation at Prairie Island, is to increase the flow velocities within

the tube bundle, to reduce the tendency for deposition of sludge where it

cannot be removed by the continuously operating blowdown system, to reduce the

tendency for vapor generation at the tube sheet, and, to reduce moisture

carryover with the steam.

The Model F steam generator incorporates several other improved features.

These features are illustrated in Figure 5.4-5. A sealed thermal sleeve and J-

nozzles on the feedring prevent the draining of water from the feedring inside

the steam generator, and, together with a short horizontal length of feedwater piping to the feedring, have been incorporated to prevent water hammer.

The holes in the tube support plates of the Model F generator have a four-lobe

shape that provides four lands to support the tube laterally. The holes are

fabricated by drilling, followed by broaching. Figure 5.4-6 is an illustration

of the "quatrefoil" broached holes.

The tubes are seal welded to the tube sheet cladding. Fusion welds are

performed in compliance with Sections III and IX of the ASME Code and are dye

penetrant inspected and leakproof tested. After welding, each tube is

hydraulically expanded for the full depth of the tube sheet to the secondary

surface to eliminate crevices between the tube and tube sheet.

On the primary side, the reactor coolant flows through the inverted U-tubes,

entering and leaving through nozzles located in the hemispherical bottom head of the steam generator. The head is divided into inlet and outlet chambers by a vertical divider plate extending from the apex of the head to the tube sheet.

Steam is generated on the shell side, flows upward, and exits through the

outlet nozzle at the top of the vessel. Feedwater enters the steam generator

at an elevation above the top of the U-tubes, through a feedwater nozzle. The

water is distributed circumferentially around the steam generator by means of a

feedwater ring and then flows downward through an annulus between the tube

wrapper and shell. The feedwater enters the ring via a welded thermal sleeve

connection and leaves it through inverted "J" tubes located at the flow holes,

which are at the top of the ring. These features are designed to prevent a

condition which

5.4-13 Rev. 0 WOLF CREEK can result in water hammer occurrences in the feedwater piping. At the bottom

of the wrapper, the water is directed toward the center of the tube bundle by a

flow distribution baffle. This baffle arrangement serves to minimize the

tendency of relatively low velocity fluid to deposit sludge in the tube bundle.

Flow blockers, installed on the tube lane, restrict feedwater from flowing

through the tube lane and bypassing the tubes. The steam-water mixture from

the tube bundle rises into the steam drum section, where 16 individual

centrifugal moisture separators remove most of the entrained water from the

steam. The steam continues to the secondary separators, which remove most of

the remaining moisture and provide a quality of at least 99.75 percent. The

separated water is combined with entering feedwater to flow back down the

annulus between the wrapper and shell for recirculation through the steam

generator. The dry steam exits from the steam generator through the outlet

nozzle which is provided with a steam flow restriction, described in Section 5.4.4.

5.4.2.3 Steam Generator Materials 5.4.2.3.1 Selection and Fabrication of Materials

Pressure boundary materials used in the steam generator are selected and fabricated in accordance with the requirements of Section III of the ASME Code.

A general discussion of materials specifications is given in Section 5.2.3,

with types of materials listed in Tables 5.2-2 and 5.2-3. Fabrication of

reactor coolant pressure boundary materials is also discussed in Section 5.2.3,

particularly in Sections 5.2.3.3 and 5.2.3.4.

The steam generator materials are carbon steel, except for the U and J tubes,

tube support plates, flow distribution baffle, antivibration bars, and the

channel head divider plate. The interior surfaces of the reactor coolant

channel head, nozzles, and manways are clad with austenitic stainless steel.

The primary side of the tube sheet is weld clad with Inconel (ASME SFA-5.14).

The U and J tubes are Inconel-600, a nickel-chromium-iron alloy (ASME SB-163).

The channel head divider plate is Inconel (SB-168). Tube support plates and

the flow distribution baffle are ferritic stainless steel (Type 405). The

antivibration bars are Inconel-600, which is chrome plated to improve wear

resistance.

The Inconel tubing has been subjected to a thermal treatment process, which has

been defined on the basis of laboratory tests and which provides increased

resistance to stress corrosion cracking.

5.4-14 Rev. 0 WOLF CREEK Code cases used in material selection are discussed in Section 5.2.1. The

extent of conformance with Regulatory Guides 1.84 and 1.85 is discussed in

Appendix 3A.

During manufacture, cleaning is performed on the primary and secondary sides

for the steam generator, in accordance with written procedures which follow the

guidance of Regulatory Guide 1.37 and the ANSI Standard N45.2.1-1973, "Cleaning

of Fluid Systems and Associated Components for Nuclear Power Plants." Onsite

cleaning and cleanliness control also follow the guidance of Regulatory Guide

1.37, as discussed in Appendix 3A. Cleaning process specifications are

discussed in Section 5.2.3.4.

The fracture toughness of the materials is discussed in Section 5.2.3.3.

Adequate fracture toughness of ferritic materials in the reactor coolant pressure boundary is provided by compliance with Appendix G of 10 CFR 50 and with Paragraph NB-2300 of Section III of the ASME Code. As discussed in

Section 5.4.2.1, consideration of fracture toughness is only necessary for

materials in Class 1 components.

5.4.2.3.2 Compatibility of Steam Generator Tubing with

Primary and Secondary Coolants

As mentioned in Section 5.4.2.3.1, corrosion tests, which subjected the steam

generator tubing material, Inconel-600 (ASME SB-163), to simulated steam

generator water chemistry, have indicated that the loss due to general

corrosion over the 40-year plant life is insignificant, compared to the tube

wall thickness. Testing to investigate the susceptibility of heat exchanger

construction materials to stress corrosion in caustic and chloride aqueous

solutions has indicated that Inconel-600 has excellent resistance to general and pitting type corrosion in severe operating water conditions. Many reactor years of successful operation have shown the same low general corrosion rates

as indicated by the laboratory tests.

Recent operating experience, however, has revealed areas on secondary surfaces

where localized corrosion rates were significantly greater than the low general

corrosion rates. Both intergranular stress corrosion and tube wall thinning

were experienced in localized areas, although not at the same location nor

under the same environmental conditions (water chemistry, sludge composition).

Adoption of the all volatile treatment (AVT) chemistry control program

eliminates the possibility for recurrence of the tube wall thinning phenomenon

related to phosphate chemistry control. Successful AVT operation requires

maintenance of low concentration of impurities in the steam generator water,

thus reducing the potential for formation of highly concentrated solutions in

low

5.4-15 Rev. 1 WOLF CREEK flow zones, which is the precursor of corrosion. By restriction of the total

alkalinity in the steam generator and prohibition of extended operation with

free alkalinity, the AVT control program minimizes the possibility for

occurrence of intergranular corrosion in localized areas due to excessive levels of free caustic.

Laboratory testing has shown that the Inconel-600 tubing is compatible with the

AVT environment. Isothermal corrosion testing in high purity water has shown

that commercially produced Inconel-600 exhibiting normal microstructures tested

at normal engineering stress levels does not suffer intergranular stress

corrosion cracking in extended exposure to high temperature water. These tests

also showed that no general type of corrosion occurred. A series of autoclave

tests in reference secondary water with planned excursions have produced no

corrosion attack after 1,938 days of testing on any as produced Inconel-600 tube samples.

AVT chemistry control has been employed successfully in plant operations for

considerable periods. Plants with stainless steel tubes which have

demonstrated successful AVT operation include Selni, Sena, and Yankee-Rowe.

Selni has operated with AVT since 1964, Sena since 1966, and Yankee-Rowe since

1967. Approximately 20 plants with Inconel tubes have operated with AVT or

limited phosphate exposure for periods up to 4 to 4-1/2 years. There have been

only a few tube leaks, and annual eddy current inspections have revealed no

tube thinning and virtually no corrosion-induced cracking.

Additional extensive operating data are presently being accumulated with the

conversion to AVT chemistry. A comprehensive program of steam generator

inspections, including the recommendations of NEI 97-06, with the exceptions as stated in Appendix 3A, will ensure detection and correction of any unanticipated degradation that might occur in the steam generator tubing.

Another corrosion-related phenomenon, termed tube denting, was first discovered

during the April 1975 steam generator inspection at the Surry Unit No. 2 plant.

This discovery was evidenced by eddy current signals resembling those produced

by scanning dents and by difficulty in passing the standard eddy current probe

through the tubes at the intersections with the support plates. Subsequent to

the initial finding, steam generator inspections at other operating plants

revealed indications of denting to various degrees.

5.4-16 Rev. 24 WOLF CREEK An intensive program of investigations, which has included removal of dented

tubes and tube/support plate samples from affected steam generators and

laboratory tests of heated crevices and model boilers, has revealed that the

source of tube denting is corrosion of the carbon steel tube support plate (TSP) in the crevices between the tube and TSP. The corrosion rate in these

locations is apparently accelerated by deposition of impurities from the

secondary fluid, caused by low flow velocity and superheated fluid in the

crevice. The corrosion product has a larger volume than the base metal. The

results are simultaneous reduction of the tube diameter, dilation of the hole

in the TSP, and secondary effects (e.g., TSP distortions) related to dilation

of the TSP holes. Denting has been most pronounced in plants having a history

of chloride contamination resulting from condenser leakage. The presence of

acid chloride has been found to be a common factor in tube denting produced in

laboratory tests. Measures to inhibit denting concentrate on providing a more corrosion resistant TSP material and on eliminating conditions conducive to corrosion at the tube support locations (e.g., chemical impurities in the

secondary fluid and localized superheat).

The tube support plates and flow distribution baffle used in the Model F steam

generator are Type 405 ferritic stainless steel which has been shown in

laboratory tests to be resistant to corrosion in the AVT environment. When

corrosion of ferritic stainless steel does occur, the volume of the corrosion

products is equivalent to the volume of the parent material. Thus,

substitution of Type 405 ferritic stainless steel for carbon steel used in

previous steam generators substantially reduces the potential for tube denting.

Other features of the Model F generator further reduce the potential for tube

denting. The quatrefoil geometry of the tube support plates is less

susceptible to the accumulation of corrosion products which cause tube denting.

The quatrefoil geometry also results in a reduced fluid pressure drop across the tube support plates and, therefore, a higher recirculation ratio and higher

fluid velocities in the tube bundle. The flow distribution baffle serves to

provide higher cross-flow velocity immediately above the tube sheet and to

sweep sludge to the center of the tube bundle, where the intakes to the

blowdown pipes are located. Increased capacity (90 gpm per steam generator)

blowdown pipes have been added. High volume blowdown provides protection

against inleakage of impurities from the condenser and feedwater system.

Blocking devices located adjacent to the downcomer region and at the innermost

U-bend tube row, at the tube sheet, minimize bypass flow, promoting flow into

the central regions of the bundle.

5.4-17 Rev. 0 WOLF CREEK Operating experience, verified in numerous steam generator inspections,

indicates that the tube degradation associated with phosphate water treatment

is not occurring where only AVT has been utilized. Adherence to the AVT

chemical specifications and close monitoring of the condenser integrity will assure the continued good performance of the steam generator tubing.

5.4.2.3.3 Control of Secondary-Side Impurities

Several provisions exist in the WCGS plants to limit the accumulations of

impurities in the steam generator, either by limiting ingress or by

facilitating removal. The materials of construction of the secondary system

are such as to minimize the formation of corrosion products. The materials

include stainless steel tubing in all feedwater heaters and Corten tubing in

the moisture-separator-reheaters. A full-flow condensate demineralizer system is provided. A piping connection is provided from the feedwater heater, ahead of the steam generators, to the condenser hot well. During startup, this

connection is used to circulate secondary system water through the condensate

demineralizers. The flow circulation removes suspended corrosion products that

may have accumulated during extended shutdowns.

For removal of impurities, the blowdown system has a capacity slightly in

excess of 1 percent of full-load feedwater flow. As described in Section

5.4.2.2 and 5.4.2.3.2, the design of the Model F steam generator is expected to

result in an increased efficiency of impurity removal by the blowdown system.

The feedwater system materials are discussed in Section 10.4.7, the steam

generator blowdown system is discussed in Section 10.4.8, and the condensate

demineralizer system is discussed in Section 10.4.6. Instrumentation to

monitor secondary side water chemistry is described in Section 9.3.2.

During shutdowns, sludge lancing may be used to remove accumulated material.

In sludge lancing, a hydraulic jet is inserted through an access opening

(handhole) to loosen sludge deposits, which are removed by means of a suction

pump.

5.4.2.4 Steam Generator Inservice Inspection The steam generator and associated insulation is designed to permit inspection

of Class 1 and 2 parts, including individual tubes. The design includes a

number of openings to provide access to both the primary and secondary sides of the steam generator, and the inspection program followed complies with Section

XI of the ASME Code, including addenda per 10 CFR 50.55a (g) with certain

exceptions whenever specific written relief is granted by the

5.4-18 Rev. 0 WOLF CREEK NRC per 10 CFR 50.55a (g) (6). These openings include four manways, two for

access to both chambers of the reactor coolant channel head inlet and outlet

sides and two in the steam drum for inspection and maintenance of the moisture

separators, and six 6-inch handholes, three located just above the tube sheet secondary surface and three located just above the flow distribution baffle.

Access to the tube U-bend is provided through each of the three deck plates.

For proper functioning of the steam generator, some of the deck plate openings

are covered with welded, but removable, hatch plates. Inspection/access to the

primary side is provided by two 16-inch manways located in the channel head.

In addition, a separate preservice and inservice inspection document which

complies with the recommendations of Regulatory Guide 1.83 and "NRC Staff

Guidance for complying with certain provisions of 10 CFR 50.55a (g) Inservice

Inspection Requirements" was submitted to the NRC. This document provided the details to the areas subject to examination, method of examination, extent of examination, and frequency. WCGS now uses the guidance set forth in NEI 97-06 to monitor Steam Generator integrity.

The insulation in the area of longitudinal and circumferential welds, including

tube-sheet-to-head or shell welds, primary nozzle-to-vessel head welds and

nozzle-to-head inside radiused sections; primary nozzle-to-safe end welds;

integrally welded vessel supports, circumferential butt welds, and nozzle-to-vessel welds on the secondary side is removable. The pressure-retaining

bolting can be removed for examination. Manways in the primary head allow

direct visual examination of the head cladding. The manways allow sufficient

access for the installation of the remotely operated eddy current equipment

capable of performing inservice inspections in accordance with the

recommendations given in NEI 97-06.

5.4.2.4.1 Compliance with Section XI of the ASME Code

Eddy current examinations of steam generator tubing are performed in accordance

with Section XI of the ASME Code per 10 CFR 50.55a(g), with certain exceptions whenever specific written relief is granted by the NRC per 10 CFR 50.55a, and

the WCGS Technical Specifications.

Other Class l and Class 2 components of the steam generators are examined in

accordance with the inservice inspection program. The inservice inspection

program of Class l components of the steam generators is described in Section

5.2.4. The inservice inspection of Class 2 components of the steam generators

is discussed in Section 6.6.

5.4-19 Rev. 24 WOLF CREEK 5.4.2.4.2 Program for Inservice Inspection of Steam Generator

Tubing

Steam generator tubing is inspected in accordance with the recommendations given in NEI 97-06, as discussed in Appendix 3A. This guide covers the inspection equipment, baseline inspections, tube selection, sampling and frequency of inspection, methods of recording, and required actions based on

findings. Variations in the type of equipment and calibration material are

approved for use through utilization of ASME Section XI Code Cases. The Cases

utilized are included in the inservice inspection subtier program document addressing steam generator tubing inspection, as discussed in USAR Appendix 3A

for Regulatory Guide 1.147. The design of the steam generators permits

inservice inspection and/or plugging, if required, of each tube. Regulatory

Guide 1.121 provides recommendations concerning tube plugging.

The eddy current examination equipment and procedures are capable of detecting

and locating defects with a penetration of 20 percent or more of the wall

thickness. The remotely operated equipment is capable of examining the entire

length of the tubes.

All original examination data, results, and reports are stored in a fireproof facility and in an atmosphere controlled to minimize deterioration. The data

is stored in a limited-access facility and retained for the operating life of

the plant.

Standards consisting of similar as-manufactured steam generator tubing with

known imperfections are used to establish sensitivity and to calibrate the

equipment. Where practical, these standards include reference flaws that

simulate the length, depth, and shape of actual imperfections that are

characteristic of past experience.

Personnel engaged in taking or interpreting data are tested and qualified in

accordance with American Society for Nondestructive Testing Standard SNT-TC-lA

and supplements designated by the Edition and Addenda of Section XI used during

the examination. Procedures governing the above examinations are qualified prior to examination in the plant.

All of the tubes in the steam generators are inspected by eddy current prior to

service to establish a baseline condition of the tubing.

The sample selection and testing of tubes, the inspection intervals, and the

actions to be taken if defects are identified follow the recommendations of NEI 97-06.

5.4.2.5 Design Evaluation

Seismic and LOCA loads are discussed in Section 3.9(N).

5.4-20 Rev. 24 WOLF CREEK 5.4.2.5.1 Forced Convection of Reactor Coolant

The limiting case for heat transfer capability is the "nominal 100-percent

design" case. The steam generator effective heat transfer coefficient is based on the coolant conditions of temperature and flow for this case. The best

estimate for the heat transfer coefficient applied in steam generator design

calculations and plant parameters selection is 1503 Btu/hr-ft 2-F. The coefficient incorporates a specified fouling factor resistance of 0.00005 hr-

ft2-F/Btu, which is the value selected to account for the differences in the measured and calculated heat transfer performance as well as provide the margin

indicated above. Although margin for tube fouling is available, operating

experience to date has not indicated that steam generator performance decreases

over a long-time period. Adequate tube area is selected to ensure that the

full design heat removal rate is achieved.

5.4.2.5.2 Natural Circulation of Reactor Coolant

The driving head created by the change in coolant density as it is heated in

the core and rises to the outlet nozzle initiates convection circulation. This

circulation is enhanced by the fact that the steam generators, which provide a

heat sink, are at a higher elevation than the reactor core, which is the heat

source. Natural circulation is sufficient for the removal of decay heat during

hot shutdown and cooldown in the event of a loss of forced circulation.

5.4.2.5.3 Mechanical and Flow-Induced Vibration Under

Normal Operation

The possibility of vibratory failure of tubes due to either mechanical or flow-

induced excitation has been thoroughly evaluated. This evaluation includes detailed analysis of the tube support systems as well as an extensive research program with tube vibration model tests.

In evaluating possible failure due to vibration, consideration is given to such

sources of excitation as those generated by the primary fluid flowing within

the tubes. The effects of these as well as any other mechanically induced

vibrations are considered to be negligible and should cause little concern.

Another source of possible vibratory failure in heat exchanger components is

hydrodynamic excitation by the secondary fluid on the outside of the tubes.

5.4-21 Rev. 0 WOLF CREEK Consideration of secondary flow-induced vibration involves two types of flow,

parallel and cross, and it is evaluated in three regions:

a. At the entrance of the downcomer feed to the tube bundle (cross flow)

b. Along the straight sections of the tube (parallel flow)

c. In the curved tubed section of the U-bend (cross flow)

For the case of parallel flow, analysis is done to determine the vibratory

deflections in order to verify that the flow velocities are sufficiently below

those required for damaging fatigue or impacting vibratory amplitude. Thus,

the support system is deemed adequate to preclude parallel flow excitation.

For the case of cross-flow excitation, several possible mechanisms of tube

vibration exist. For the Model F steam generator design and conditions, only

two of these mechanisms are deemed significant enough to merit extensive

consideration: 1) Von Karman vortex shedding and 2) fluidelastic vibration.

The steam generator is analyzed to ensure that the tube natural frequency is

well above the anticipated vortex shedding frequency and that unstable

fluidelastic vibration does not exist. In order to achieve this, adequate tube

supports must be provided. An evaluation using the specific parameters for the

Model F steam generator confirms the integrity of the support system.

To provide added strength as well as resistance to vibration, the quatrefoil

tube support plate thickness has been increased. In addition, 12 peripheral

supports also provide stability to the plates so that tube fretting or wear due

to flow-induced plate vibrations at the tube support contact regions is abated.

Assurance against damaging flow induced tube vibration has been accomplished by

a combination of analysis and testing. Cross and parallel flow velocities were

calculated from thermal-hydraulic analysis of the secondary flow. Three

possible vibrational mechanisms, vortex shedding, fluid-elastic excitation, and

turbulence were studied.

For vortex shedding, resonance conditions were conservatively assumed, and

amplitudes for different resonant modes were computed.

5.4-22 Rev. 0 WOLF CREEK For fluidelastic excitation, the ratios of the effective cross flow velocity to

the critical velocity of the first 20 vibration modes were calculated. The

results indicate that no fluidelastic vibration will occur during steady state

conditions as well as operational transients.

The amplitudes of turbulence-induced vibration are one order of magnitude less

than those from vortex-shedding induced vibration. Therefore, vortex shedding

is considered the predominant mechanism of flow-induced tube vibration.

Combining both vortex shedding and turbulence effects in a conservative manner,

the maximum predicted local tube wear depth over 40 years of operational life

is less than 0.006 inches. This value is considerably below the limiting wall

thickness reduction for a Model F steam generator tube.

5.4.2.5.4 Allowable Tube Wall Thinning Under Accident Conditions

An evaluation is performed to determine the extent of tube wall thinning that

can be tolerated under accident conditions. The worst-case loading conditions

are assumed to be imposed upon uniformly thinned tubes, at the most critical

location in the steam generator. Under such a postulated design basis

accident, vibration is of short enough duration that there is no endurance

problem to be considered. The steam generator tubes, existing originally at

their minimum wall thickness and reduced by a conservative general corrosion

and erosion loss, can be shown to provide an adequate safety margin, that is,

sufficient wall thickness, in addition to the minimum required for a maximum

stress less than the allowable stress limit, as it is defined by the ASME Code.

The results of a study made on "D series" (0.75 inch nominal diameter, 0.043

inch nominal wall thickness) tubes under accident loadings are discussed in Reference 3. These results demonstrate that a minimum wall thickness of 0.026 inches would have a maximum faulted condition stress (i.e., due to combined

LOCA and SSE loads) that is less than the allowable limit. This thickness is

0.010 inch less than the minimum "D series" tube wall thickness of 0.039 inch,

which is reduced to 0.036 inch by the assumed general corrosion and erosion

rate. Thus, an adequate safety margin is exhibited. The corrosion rate is

based on a conservative weight loss rate for Inconel tubing in flowing 650 F

primary side reactor coolant fluid. The weight loss, when equated to a

thinning rate and projected over a 40-year plant life with appropriate

reduction after initial hours, is equivalent to 0.083 mil thinning. The

assumed corrosion rate of 3 mils leaves a conservative 2.917 mils for general

corrosion thinning on the secondary side.

5.4-23 Rev. 0 WOLF CREEK The Model F steam generator is analyzed, using similar assumptions of general

corrosion and erosion rates. The overall similarity between the tubes studied

and the Model F tubes makes it reasonable to expect the same general results,

that is, to conclude that the ability of the Model F steam generator tubes to withstand accident loading is not impaired by a lifetime of general corrosion

losses. The results of the specific analysis are presented in WCAP 10043,

"Steam Generator Tube Plugging Analysis for the Westinghouse Standardized

Nuclear Unit Power Plant System (SNUPPS)." Wolf Creek uses the SNUPPS design.

5.4.2.6 Quality Assurance The steam generator nondestructive examination program is given in Table 5.4-4.

Radiographic inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code.

Liquid penetrant inspection is performed on weld deposited tube sheet cladding,

channel head cladding, divider plate to tube sheet and to channel head

weldments, tube-to-tube sheet weldments, and weld deposit cladding. Liquid

penetrant inspection and acceptance standards are in accordance with the

requirements of Section III of the ASME Code.

Magnetic particle inspection is performed on the tube sheet forging, channel

head casting, nozzle forgings, and the following weldments:

a. Nozzle to shell

b. Support brackets

c. Instrument connection (secondary)

d. Temporary attachments after removal

e. All accessible pressure retaining welds after

hydrostatic test

Magnetic particle inspection and acceptance standards are in accordance with

the requirements of Section III of the ASME Code.

Ultrasonic tests are performed on the tube sheet forging, tube sheet cladding, secondary shell and head plate, and nozzle forgings.

5.4-24 Rev. 0 WOLF CREEK The heat transfer tubing is subjected to eddy current testing and ultrasonic

examination.

Hydrostatic tests are performed in accordance with Section III of the ASME Code.

5.4.3 REACTOR COOLANT PIPING

5.4.3.1 Design Bases The RCS piping is designed and fabricated to accommodate the system pressures

and temperatures attained under all expected modes of plant operation or

anticipated system interactions. Stresses are maintained within the limits of Section III of the ASME Code. Code and material requirements are provided in

Section 5.2.

Materials of construction are specified to minimize corrosion/ erosion and

ensure compatibility with the operating environment.

The piping in the RCS is Safety Class 1 and is designed and fabricated in

accordance with ASME Code,Section III, Class 1 requirements.

Stainless steel pipe conforms to ANSI B36.19 for sizes 1/2 inch through 12 inches and wall thickness Schedules 40S through 80S. Stainless steel pipe outside of the scope of ANSI B36.19 conforms to ANSI B36.10.

The minimum wall thicknesses of the loop pipe and fittings are no less than

those calculated using the ASME Code,Section III, Class 1 formula of Paragraph

NB-3641.1(3) with an allowable stress value of 17,550 psi. The pipe wall

thickness for the pressurizer surge line is Schedule 160. The minimum pipe

bend radius is 5 nominal pipe diameters, and ovality does not exceed 6 percent.

Butt welds, branch connection nozzle welds, and boss welds are of a full

penetration design.

Processing and minimization of sensitization are discussed in Section 5.2.3.

Flanges conform to ANSI B16.5.

Socket weld fittings and socket joints conform to ANSI B16.11.

Inservice inspection is discussed in Section 5.2.4.

5.4-25 Rev. 0 WOLF CREEK 5.4.3.2 Design Description

The RCS piping includes those sections of piping interconnecting the reactor

vessel, steam generator, and reactor coolant pump. It also includes the

following:

a. Charging line and alternate charging line from the

system isolation valve up to the branch connections on

the reactor coolant loop

b. Letdown line and excess letdown line from the branch

connections on the reactor coolant loop to the system

isolation valve

c. Pressurizer spray lines from the reactor coolant cold legs to the spray nozzle on the pressurizer vessel

d. Residual heat removal lines to or from the reactor

coolant loops up to the designated check valve or

isolation valve

e. Safety injection lines from the designated check valve

to the reactor coolant loops

f. Accumulator lines from the designated check valve to the

reactor coolant loops

g. Loop fill, loop drain, sample

• , and instrument

• lines to or from the designated isolation valve to or from the

reactor coolant loops

h. Pressurizer surge line from one reactor coolant loop hot

leg to the pressurizer vessel inlet nozzle

i. Resistance temperature detector scoop element,

pressurizer spray scoop, sample connection

• with scoop, reactor coolant temperature element installation boss,

and the temperature element well itself

• Lines with a 3/8-inch (liquid service), 3/4-inch (steam service), or less flow restricting orifice qualify as Safety Class 2.

5.4-26 Rev. 19 WOLF CREEK

j. All branch connection nozzles attached to reactor

coolant loops.

k. Pressure relief lines* from nozzles on top of the pressurizer vessel up to and through the power operated

pressurizer relief valves and pressurizer safety valves

l. Seal injection water lines to the reactor coolant pump

from the designated check valve (injection line)

m. Auxiliary spray line from the isolation valve to the

pressurizer spray line header

n. Sample lines

• from pressurizer to the isolation valve

o. Reactor vessel head vent lines

• to the isolation valves

Principal design data for the reactor coolant piping are given in Table 5.4-5.

Details of the materials of construction and codes used in the fabrication of reactor coolant piping and fittings are discussed in Section 5.2.

The reactor coolant piping and fittings which make up the loops are austenitic

stainless steel. Pipe and fittings are cast, seamless without longitudinal or

electroslag welds, and comply with the requirements of the ASME Code, Section

II (Parts A and C),Section III, and Section IX. All smaller piping which is

part of the RCS, such as the pressurizer surge line, spray and relief line,

loop drains and connecting lines to other systems, are also austenitic

stainless steel. The nitrogen supply line for the pressurizer relief tank is

carbon steel. All joints and connections are welded, except for the

pressurizer code safety valves, where flanged joints are used. A thermal

sleeve is installed on the pressurizer spray line nozzle.

All piping connections with auxiliary systems are above the horizontal centerline of the reactor coolant piping, with the exception of:

• Lines with a 3/8-inch (liquid service), 3/4-inch (steam service), or less flow restricting orifice qualify as Safety Class 2.

5.4-27 Rev. 19 WOLF CREEK

a. Residual heat removal pump suction lines, which are 45

degrees down from the horizontal centerline. This

enables the water level in the RCS to be lowered in the

reactor coolant pipe while continuing to operate the residual heat removal system, should this be required

for maintenance.

b. Loop drain lines and the connection for temporary level

measurement of water in the RCS during refueling and

maintenance operation as shown on Figure 5.1-1, Sheet 1.

c. The differential pressure taps for flow measurement,

which are downstream from the steam generators of the

first 90-degree elbow as shown on Figure 5.1-1, Sheet 1.

d. The pressurizer surge line, which is attached at the

horizontal centerline is shown on Figure 5.1-1, Sheet 2.

e. Two of the three scoops in each resistance temperature

detector hot leg connection.

f. The hot leg sample connections, the loop 3 thermowell, and the loop 4 boron injection tank injection

connection, all located on the horizontal center-line.

Penetrations into the coolant flow path are limited to the following:

a. The spray line inlet connections extend into the cold

leg piping in the form of a scoop so that the velocity

head of the reactor coolant loop flow adds to the spray

driving force.

b. The reactor coolant sample system taps protrude into the main stream to obtain a representative sample of the

reactor coolant.

c. The hot leg connections to the resistance temperature

detectors have scoops which extend into the reactor

coolant to collect a representative temperature sample

for the individual hot leg resistance temperature

detector.

d. The wide range temperature detectors are located in

resistance temperature detector wells that extend into

both the hot and cold legs of the reactor coolant pipes.

One hot leg and one cold leg temperature reading are provided from each coolant loop to use for protection. Narrow range, thermowell-mounted Resistance Temperature Detectors (RTDs) are provided for each coolant loop. In the hot

legs, sampling scoops are used because the flow is stratified. That is, the

fluid temperature is not uniform over a cross section of the hot leg.

5.4-28 Rev. 14 WOLF CREEK One dual element RTD is mounted in a thermowell in each of the three sampling

scoops associated with each hot leg. The scoops extend into the flow stream at

locations 120° apart in the cross sectional plane. Each scoop has five

orifices which sample the hot leg flow along the leading edge of the scoop.

Outlet ports are provided in the scoops to direct the sampled fluid past the

sensing element of the RTDs. One of each of the RTD's dual elements is used

while the other is an installed spare. Three readings from each hot leg are

averaged to provide a hot leg reading for that loop.

One dual element RTD is mounted in a thermowell associated with each cold leg.

One RTD element is used while the other is an installed spare.

The thermowells are pressure boundary parts which completely enclose the RTD.

They have been shop hydrotested to 1.25 times the RCS design pressure. The

external design pressure and temperature are the RCS design temperature and

pressure. The RTD is not part of the pressure boundary. The scoop,

thermowell, and thermowell/scoop assembly have been analyzed to the ASME Boiler

and Pressure Vessel Code,Section III, Class 1. The effects of seismic and

flow-induced loads were considered in the design.

Signals from the temperature detectors are used to compute the reactor coolant T (temperature of the hot leg, T HOT minus the temperature of the cold leg, TCOLD) and an average reactor coolant temperature (T AVG). The T AVG for each loop is indicated on the main control board.

5.4.3.3 Design Evaluation Piping load and stress evaluation for normal operating loads, seismic loads,

blowdown loads, and combined normal, blowdown, and seismic loads is discussed

in Section 3.9(N).

5.4.3.3.1 Material Corrosion/Erosion Evaluation

The water chemistry is selected to minimize corrosion. A periodic analysis of

the coolant chemical composition is performed to verify that the reactor

coolant quality meets the specifications (see Section 5.2.3).

5.4-29 Rev. 9 WOLF CREEK Periodic analysis of the coolant chemical composition is performed to monitor

the adherence of the system to desired reactor coolant water quality listed in

Table 5.2-5. Maintenance of the water quality to minimize corrosion is

accomplished, using the chemical and volume control system and sampling system which are described in Chapter 9.0.

Components in the Reactor Coolant System were designed to provide access to permit inservice inspection inaccordance with the ASME Code,Section XI.

Pursuant to this, all pressure containing welds out to the second valve that delineates the RCS boundary are accessible for examination and are fitted with

removable insulation.

5.4.3.3.2 Sensitized Stainless Steel

Sensitized stainless steel is discussed in Section 5.2.3.

5.4.3.3.3 Contaminant Control

Contamination of stainless steel and Inconel by copper, low melting temperature

alloys, mercury, and lead is prohibited. Thread lubricants are approved in

accordance with applicable procedures. Prior to application of thermal

insulation, the austenitic stainless steel surfaces are cleaned and analyzed to

halogen limits as defined by Westinghouse Process Specifications.

5.4.3.4 Tests and Inspections The RCS piping quality assurance program is given in Table 5.4-6.

Volumetric examination is performed throughout 100 percent of the wall volume of each pipe and fitting in accordance with the applicable requirements of

Section III of the ASME Code for all pipe 27-1/2 inches and larger. All

unacceptable defects are eliminated in accordance with the requirements of the

same section of the code.

A liquid penetrant examination is performed on both the entire outside and

inside surfaces of each finished fitting, in accordance with the criteria of

the ASME Code,Section III. Acceptance standards are in accordance with the

applicable requirements of the ASME Code,Section III.

The pressurizer surge line conforms to SA-376, Grade 304, 304N, or 316 with supplementary requirements S2 (transverse tension tests) and S6 (ultrasonic

test). The S2 requirement applies to each length of pipe. The S6 requirement

applies to 100 percent of the piping wall volume.

5.4-30 Rev. 12 WOLF CREEK The end of pipe sections, branch ends, and fittings are machined back to

provide a smooth weld transition adjacent to the weld path.

5.4.4 MAIN STEAM LINE FLOW RESTRICTOR

5.4.4.1 Design Basis The outlet nozzle of the steam generator is provided with a flow restrictor

designed to limit steam flow in the unlikely event of a break in the main steam

line. A large increase in steam flow will create a backpressure which limits further increase in flow. The flow restrictor performs the following

functions: rapid rise in containment pressure is prevented, the rate of heat

removal from the reactor coolant is such as to keep the cooldown rate within

acceptable limits, thrust forces on the main steam line piping are reduced, and

stresses on internal steam generator components, particularly the tube sheet

and tubes, are limited. The restrictor is configured to minimize the

unrecovered pressure loss across the restrictor during normal operation.

5.4.4.2 Design Description The flow restrictor consists of seven Inconel (ASME SB-163) venturi inserts

which are installed in holes in an integral low alloy steel forging. The

inserts are arranged with one venturi at the centerline of the outlet nozzle and the other six equally spaced around it. After insertion into the low alloy

steel forging holes, the Inconel venturi inserts are welded to the Inconel

cladding on the inner surface of the forging.

5.4.4.3 Design Evaluation The flow restriction design has been analyzed to assure its structural

adequacy. The equivalent throat diameter of the steam generator outlet is 16

inches, and the resultant pressure drop through the restrictor at 100-percent steam flow is approximately 3.4 psig. This was based on a design flow rate of

3.79E6 lb/hr. Materials of construction and manufacturing of the flow

restrictor are in accordance with Section III of the ASME Code.

5.4.4.4 Tests and Inspections Since the restrictor is not a part of the steam system boundary, no tests and

inspection beyond those during fabrication are anticipated.

5.4.5 MAIN STEAM LINE ISOLATION SYSTEM The main steam line isolation system is discussed in Section 10.3.

5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM This section is not applicable to WCGS.

5.4.7 RESIDUAL HEAT REMOVAL SYSTEM 5.4.7.1 Design Bases The residual heat removal system (RHRS) functions to remove heat from the RCS when RCS pressure and temperature are below approximately 425 psig and 350°F, respectively. Heat is transferred from the RHRS to the component cooling water system.

5.4-31 Rev. 26 WOLF CREEK The design of the RHRS includes two motor-operated isolation valves that are closed during normal operations. They are provided with both a "prevent-open"

interlock and "RHRS-Iso-Valve-Open" alarm which are designed to prevent

possible exposure of the RHRS to normal RCS operating pressure.

The isolation valves are opened for residual heat removal during a plant cooldown after the RCS temperature is reduced to approximately 350F and RCS pressure is less than approximately 360 psig in accordance with plant procedures. During a plant startup, the inlet isolation valves are shut after drawing a bubble in the pressurizer and prior to increasing RCS pressure above approximately 425 psig (alarm setpoint).

Portions of the RHRS also serve as portions of the ECCS during the injection

and recirculation phases of a LOCA (see Section 6.3).

The RHRS also is used to transfer refueling water between the refueling cavity

and the refueling water storage tank at the beginning and end of the refueling

operations. The RHRS is designed to be isolated from the RCS whenever the RCS

pressure exceeds the RHRS design pressure.

5.4.7.2 Design Description 5.4.7.2.1 Functional Design

RHRS design parameters are listed in Table 5.4-7. Nuclear plants employing the same RHRS design as the WCGS unit are given in Section 1.3.

During normal approaches to cold shutdown, the RHRS is placed in operation

approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown when the temperature and pressure

of the RCS are approximately 350°F and 360 psig, respectively. Only one train of RHR is placed into operation initially to reduce the RCS temperature from 350F to 225F when the other train of RHR is utilized. This sequence is necessary to safeguard a train of RHR for ECCS requirements when shutdown.

This sequence and temperature restriction is due to limiting the temperature of RCS fluid allowed in the RHR pump suction piping. The temperature of RCS fluid allowed in at least one train of RHR suction piping is conservatively kept by plant procedures below the saturation temperature for the static head pressure of the RWST to avoid vaporization should the train be realigned to the RWST for shutdown LOCA mitigation. Assuming both trains of RHR operating in accordance with this sequence with a maximum service water temperature of 90F, plant cooldown is completed in 17.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> following reactor shutdown (RCS temp

<140F). This cooldown rate is based on throttling RHR flow, as necessary, to maintain a maximum 120F component cooling water to the shell side of the RHR heat exchangers and to limit the RCS cooldown rate to a maximum of 50F/hr. The heat load handled by the RHRS during the cooldown transient includes residual and decay heat from the core and reactor coolant pump heat. The

design heat load is based on the decay heat fraction that exists at 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> using the ANSI/ANS-5.1-1979 Decay heat standard, following reactor shutdown

from an extended run at full power.

5.4-32 Rev. 26 WOLF CREEK Assuming that only one heat exchanger and pump are in service and that the heat exchanger is supplied with component cooling water at design flow and

temperature, the RHRS is capable of reducing the temperature of the reactor

coolant from 350°F to 200°F within 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> after shutdown.

The RHRS is isolated from the RCS on the suction side by two motor-operated

valves in series on each suction line. Each motor-operated valve is

interlocked to prevent its opening if RCS pressure is greater than

approximately 360 psig. During plant startup, operator action is required to

close the RHRS suction-isolation valves. An alarm will actuate on the Main

Control Board if RHRS isolation valves are not fully closed in conjunction with

RCS high pressure. The alarm setpoint pressure will be within the range of

open permissive setpoint pressure, and RHR system design pressure minus RHR

pump head pressure. P (open permissive setpoint) < P (alarm setpoint) < [P

(RHR system design pressure - P (pump discharge head)]. This interlock and alarm function is described in more detail in Sections 5.4.7.2.5 and 7.6.2.

The RHRS is isolated from the RCS on the discharge side by two check valves in

each return line. Also provided on the discharge side is a normally open,

motor-operated valve downstream of each RHRS heat exchanger. (These check

valves and motor-operated valves are not considered part of the RHRS. They are

shown as part of the ECCS, see Figures 5.1-1, 5.4-7, and 6.3-1.)

Each inlet line to the RHRS is equipped with a pressure relief valve designed

to relieve the combined flow of all the charging pumps at the relief valve set

pressure. These relief valves also protect the RHRS system from inadvertent

overpressurization during plant cooldown or startup. Each discharge line from the RHRS to the RCS is equipped with a pressure relief valve designed to

relieve the maximum possible backleakage through the valves isolating the RHRS

from the RCS.

The RHRS is provided for WCGS which is a single nuclear power unit.

The RHRS is designed to be fully operable from the control room for normal

operation. Manual operations required of the operator are: opening the

suction isolation valves, positioning the flow control valves downstream of the

RHRS heat exchangers, and starting the residual heat removal pumps. By nature of its redundant two-train design, the RHRS is designed to accept major component single failures with the only effect being an extension in the

required cooldown time. For two low probability electrical system single

failures, i.e., failure in the suction isolation valve interlock circuitry or

diesel generator failure in conjunction with loss of offsite power, operator

action outside the control room is required to open the suction isolation

valves. Manual actions are discussed in further detail in Sections 5.4.7.2.7

and 5.4.7.2.8. The motor-operated valves in the RHRS are not subject to

flooding. Spurious operation of a single motor-operated valve can be accepted

without loss of function, as a result of the redundant two-train design.

5.4-33 Rev. 13 WOLF CREEK Missile protection, protection against dynamic effects associated with the

postulated rupture of piping, and seismic design are discussed in Sections 3.5,

3.6, 3.7(B), and 3.7(N) respectively.

5.4.7.2.2 Piping and Instrumentation Diagrams

The RHRS, as shown in Figures 5.4-7 (piping and instrumentation diagram) and

5.4-8 (process flow diagram), consists of two residual heat exchangers, two

residual heat removal pumps, and the associated piping, valves, and

instrumentation necessary for operational control. The inlet lines to the RHRS

are connected to the hot legs of two reactor coolant loops, while the return

lines are connected to the cold leg of each of the reactor coolant loops.

These return lines are also the ECCS low head injection lines (see Figure 6.3-

1). The RHRS suction lines are isolated from the RCS by two motor-operated valves

in series located inside the containment. Each discharge line is isolated from

the RCS by two check valves in series located inside the containment and by a

normally open motor-operated valve located outside the containment. (The check

valves and the motor-operated valve on each discharge line are shown as part of

the ECCS, see Figures 5.1-1, 5.4-7, and 6.3-1.)

During RHRS operation, reactor coolant flows from the RCS to the residual heat

removal pumps, through the tube side of the residual heat exchangers, and back

to the RCS. The heat is transferred to the component cooling water circulating

through the shell side of the residual heat exchangers.

Coincident with operation of the RHRS, a portion of the reactor coolant flow

may be diverted from downstream of the residual heat exchangers to the chemical

and volume control system (CVCS) low pressure letdown line for cleanup and/or

pressure control. By regulating the diverted flowrate and the charging flow,

the RCS pressure may be controlled. Pressure regulation is necessary to

maintain the pressure range dictated by the fracture prevention criteria

requirement of the reactor vessel, by the number 1 seal differential pressure,

and by net positive suction head requirements of the reactor coolant pumps.

The RCS cooldown rate is manually controlled by regulating the reactor coolant flow through the tube side of the RHR heat exchangers. The flow control valve

in the bypass line around each RHR heat exchanger automatically maintains a

constant return flow to the RCS. Instrumentation is provided to monitor system

pressure, temperature, and total flow.

5.4-34 Rev. 13 WOLF CREEK The RHRS may be used for filling the refueling cavity before refueling. After

refueling operations, water is pumped back to the refueling water storage tank

until the water level is brought down to two feet above the flange of the reactor vessel. The remainder of the water is removed via a drain connection

at the bottom of the refueling canal.

When the RHRS is in operation, the water chemistry is the same as that of the

reactor coolant. Provision is made for the nuclear sampling system to extract samples from the flow of reactor coolant downstream of the residual heat

exchangers. A local sampling point is also provided on each residual heat

removal train between the pump and heat exchanger.

The RHRS functions in conjunction with the high head portion of the ECCS to

provide direct injection of borated water from the refueling water storage tank

into the RCS cold legs during the injection phase following a LOCA. During

normal operation, the RHRS is aligned to inject borated water upon receipt of a

safety injection signal.

In its capacity as the low head portion of the ECCS, the RHRS also provides long-term recirculation capability for core cooling following the injection

phase of a LOCA. This function is accomplished by aligning the RHRS to take

fluid from the containment sump, cool it by circulation through the residual

heat exchangers, and supply it to the core directly as well as via the

centrifugal charging pumps and safety injection pumps.

The use of the RHRS as part of the ECCS is more completely described in Section

6.3.

The RHR pumps, in order to perform their ECCS function, are interlocked to

start automatically on receipt of a safety injection signal (see Section 6.3).

The RHR suction isolation valves are also interlocked to prevent their being

opened unless the isolation valves in the following lines are closed:

a. Recirculation lines from the residual heat exchanger

outlets to the suctions of the safety injection pumps

and centrifugal charging pumps

b. RHR pump suction lines from the refueling water storage

tank

c. RHR pump suction lines from the containment sump

5.4-35 Rev. 13 WOLF CREEK The motor-operated valves in the RHR miniflow bypass lines are interlocked to

open when the RHR pump discharge flow is less than approximately 816 gpm at

300°F (783 gpm at 68°F) and close when the flow exceeds approximately 1650 gpm

at 300°F (1582 gpm at 68°F).

5.4.7.2.3 Equipment and Component Descriptions

The materials used to fabricate RHRS components are in accordance with the

applicable code requirements. All parts of the components in contact with

borated water are fabricated or clad with austenitic stainless steel or

equivalent corrosion-resistant material. Component parameters are given in

Table 5.4-8.

Residual Heat Removal Pumps Two pumps are installed in the RHRS. The pumps are sized to deliver reactor

coolant flow through the RHR heat exchangers to meet the plant cooldown

requirements. The availability of two separate RHR trains assures that cooling capacity is only partially lost should one pump become inoperative.

The RHR pumps are protected from overheating and loss of discharge flow by

miniflow bypass lines. A valve located in each miniflow line is regulated by a

signal from the flow transmitters located in each pump discharge header. The control valves open when the residual pump discharge flow is less than

approximately 816 gpm at 300°F (783 gpm at 68°F) and close when the flow

exceeds approximately 1650 gpm at 300°F (1582 gpm at 68°F).

A pressure sensor in each pump discharge header provides a signal for an

indicator in the control room. A high pressure alarm is also actuated by the

pressure sensor.

The two pumps are vertical, centrifugal units with mechanical seals on the

shafts. All pump surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material.

The RHR pumps also function as the low head safety injection pumps in the ECCS

(see Section 6.3 for further information and for the residual heat removal pump

performance curves).

Residual Heat Exchangers Two residual heat exchangers are installed in the system. The heat exchanger

design is based on heat load and temperature differences between reactor

coolant and component cooling water

5.4-36 Rev. 26 WOLF CREEK existing 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after reactor shutdown when the temperature difference

between the two systems is small.

The availability of two heat exchangers in separate and independent residual heat removal trains assures that the heat removal capacity of the system is

only partially lost if one train becomes inoperative.

The residual heat exchangers are of the shell and U-tube type. Reactor coolant

circulates through the tubes, while component cooling water circulates through the shell. The tubes are welded to the tube sheet to prevent leakage of

reactor coolant.

The residual heat exchangers also function as part of the ECCS (see Section

6.3).

Residual Heat Removal System Valves Valves that perform a modulating function are equipped with graphite packing.

Manual and motor-operated valves have backseats to facilitate repacking and to limit stem leakage when the valves are open. Leakage connections are provided

where required by valve size and fluid conditions.

Encapsulation The RHR suction lines from the containment recirculation sumps are each

provided with a single motor-operated gate valve outside the containment. This

valve, including its operator, is encapsulated in a pressure vessel which is leaktight at containment design pressure. The piping from the sump to the

valve is also encapsulated in a concentric guard pipe which is leaktight. A

leaktight seal is provided such that the ambient inside the pressure vessel and

outside the process line and enclosed within the guard pipe is not directly

connected with the containment sump or containment atmosphere. Component

parameters for the encapsulation tank are given in Table 5.4-8.

The valve provides a barrier outside the containment to prevent loss of sump

water should a leak develop in the recirculation loop. Should a leak develop

in the valve body or in the pipe between the valve and the sump, the sump fluid is contained by the leaktight seal and/or by the guard pipe.

With this system, no single failure of either an active or a passive component

will prevent the recirculation phase or adversely affect the integrity of the

containment.

5.4-37 Rev. 26 WOLF CREEK 5.4.7.2.4 System Operation

Reactor Startup

Generally, while at cold shutdown condition, decay heat from the reactor core

is being removed by the RHRS. The number of pumps and heat exchangers in

service depends upon the heat load at the time.

At initiation of the plant startup, the RCS is completely filled, and the

pressurizer heaters are energized. The RHRS is operating and is connected to

the CVCS via the low pressure letdown line for purification and/or to control

reactor coolant pressure. During this time, the RHRS acts as an alternate

letdown path. The manual valves downstream of the residual heat exchangers

leading to the letdown line of the CVCS are opened. The control valve in the

line from the RHRS to the letdown line of the CVCS is then manually adjusted in

the control room to permit letdown flow.

After the reactor coolant pumps are started, pressure control via the RHRS and the low pressure letdown line is continued until the pressurizer steam bubble is formed. Indication of steam bubble formation is provided in the control

room by the damping out of the RCS pressure fluctuations and by pressurizer

level indication. The RHRS is then isolated from the RCS, the residual heat removal pumps are stopped, and the system pressure is controlled by normal letdown and the pressurizer spray and pressurizer heaters.

Power Generation and Hot Standby Operation

During power generation and hot standby operation, the RHRS is not in service

but is aligned for operation as part of the ECCS.

Normal Reactor Cooldown Reactor cooldown is defined as the operation which brings the reactor from no-

load temperature and pressure to cold conditions.

The initial phase of reactor cooldown is accomplished by transferring heat from

the RCS to the steam generators then to the steam and power conversion system.

The heat is removed by dumping steam to the condenser (turbine bypass system),

or to the atmosphere (atmospheric relief valves).

When the reactor coolant temperature and pressure are reduced to approximately

350°F and 360 psig, approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown, the second

phase of cooldown starts and the RHRS may be placed in operation. The steam and power conversion system may continue to be used to cool the steam generators and establish refueling or maintenance conditions in a more expedient time frame.

5.4-38 Rev. 13 WOLF CREEK Startup of the RHRS includes a warmup period of one train of RHR at 350F followed by the other train of RHR at 225F. During the warmup time reactor coolant flow through the heat exchanger is limited to minimize thermal shock.

The rate of heat removal from the reactor coolant is manually controlled by regulating the coolant flow through the residual heat exchangers. By adjusting

the control valves downstream of the residual heat exchangers, the mixed mean

temperature of the return flows is controlled. Coincident with the manual

adjustment, each heat exchanger bypass valve is automatically regulated to give the required total flow. The reactor cooldown rate is limited by RCS equipment

cooling rates based on allowable stress limits, as well as the operating

temperature limits of the component cooling water system and steam dump

cooldown/atmospheric relief valve position. To maintain reactor cooldown rates

as the reactor coolant temperature decreases, the reactor coolant flow through

the residual heat exchangers is increased by adjusting the control valve in

each heat exchanger's tube side outlet line and/or opening the steam dump

cooldown/atmospheric relief valves further.

As cooldown continues, the pressurizer is filled with water, and the RCS is operated in the water solid condition.

At this stage, pressure control is accomplished by regulating the charging flow

rate and the rate of letdown from the RHRS to the CVCS.

After the reactor coolant pressure is reduced and the temperature is 140°F or

lower, the RCS may be opened for refueling or maintenance.

Refueling One of the two residual heat removal pumps may be utilized during refueling to

pump borated water from the refueling water storage tank to the refueling

cavity. During this operation, the RHRS isolation valve in the suction line from the RCS is closed, and the suction isolation valve form the refueling

water storage tank is opened.

After the water level reaches the normal refueling level, the RHRS suction

isolation valve for the RCS is opened, the refueling water storage tank supply

valve is closed, and residual heat removal is resumed if needed for RCS

cooling.

5.4-39 Rev. 26 WOLF CREEK During refueling, the RHRS is maintained in service with the number of pumps and heat exchangers in operation required by the heat load.

Following refueling, the RHR pumps are used to drain the refueling cavity down to two feet above the top of the reactor vessel flange by pumping water from

the RCS to the refueling water storage tank. The vessel head is then replaced

and the normal RHRS flowpath re-established. The remainder of the water is

removed from the refueling canal via a drain connection in the bottom of the

canal.

5.4.7.2.5 Control

Each inlet line to the RHRS is equipped with a pressure relief valve

conservatively sized to relieve the combined flow of all the charging pumps at the relief valve set pressure; however, maximum flow through the valves is expected to be the flow of one centrifugal charging pump at its maximum

delivery rate. These relief valves also protect the system from inadvertent

overpressurization during plant cooldown or startup. Each valve has a relief

flow capacity of 986 gpm at a set pressure of 450 psig.

Each discharge line from the RHRS to the RCS is equipped with a pressure relief

valve to relieve any backleakage through the valves separating the RHRS from

the RCS. Each valve has a relief flow capacity of 20 gpm at a set pressure of

600 psig. These relief valves are located in the RHRS (see Figure 5.4-7).

The fluid discharged by the suction side relief valves is collected in the

pressurizer relief tank. The fluid discharged by the discharge side relief

valves is collected in the recycle holdup tank of the boron recycle system.

The design of the RHRS includes two motor-operated gate isolation valves in series on each inlet line between the high pressure RCS and the lower pressure

RHRS. They are closed during normal operations, and are provided with both a

"prevent-open" interlock and "RHRS-Iso-Valve-Open" alarm which are designed to

prevent possible exposure of the RHRS to normal RCS operating pressure.

The isolation valves on one train of RHR are opened for residual heat removal during a plant cooldown after the RCS temperature is reduced to below 350F and at 225F the other train valves are opened. The isolation valves are separately and independently interlocked with pressure signals to prevent their being opened whenever the RCS pressure is greater than approximately 360 psig.

During a plant startup, the inlet isolation valves are shut after drawing a

bubble in the pressurizer and prior to increasing RCS pressure above approximately 425 psig (alarm setpoint). Each inlet isolation valve will

provide alarm indication on the main control board if the valve remains open

above the alarm setpoint.

5.4-40 Rev. 26 WOLF CREEK The use of two independently powered, motor-operated valves in each of the two inlet lines, along with two independent pressure interlock signals for each

function, assures a design which meets applicable single failure criteria. Not

only more than one single failure but also different failure mechanisms must be

postulated to defeat the function of preventing possible exposure of the RHRS to normal RCS operating pressure. These protective interlock designs and

alarms, in combination with plant operating procedures and alarms, provide

diverse means of accomplishing the protective function. For further

information on the instrumentation and control features, see Section 7.6.2.

The RHR inlet isolation valves are provided with red-green position indicator

lights on the main control board.

Isolation of the low pressure RHRS from the high pressure RCS is provided on

the discharge side by two check valves in series. These check valves are located in the ECCS and RCS, and their testing is described in Section 6.3.4.2.

5.4.7.2.6 Applicable Codes and Classifications

The entire RHRS is designed as Safety Class 2, with the exception of the

suction isolation valves, which are Safety Class 1. Class 1 discharge valves are discussed in Section 6.3. Component codes and classifications are given in

Section 3.2.

5.4.7.2.7 System Reliability Considerations

General Design Criterion 34 requires that a system to remove residual heat be

provided. The safety function of this required system is to transfer fission

product decay heat and other residual heat from the core at a rate sufficient

to prevent fuel or pressure boundary design limits from being exceeded. Safety

grade systems are provided in the plant design, both nuclear steam supply system (NSSS) scope and balance-of-plant (BOP) scope, to perform this function. The NSSS scope safety grade systems which perform this function for

all plant conditions except a LOCA are: the RCS and steam generators, which

operate in conjunction with the auxiliary feedwater system and the steam

generator safety and Atmospheric Relief Valves; and the RHRS, which operates in

conjunction with the component cooling water and service water systems. The

BOP scope safety grade systems which perform this function for all plant

conditions, except a LOCA, are: the auxiliary feedwater system; the steam

generator safety and Atmospheric Relief Valves, which operate in conjunction

with the RCS and the steam generators; and the component cooling water and

service water systems, which operate in conjunction with the RHRS. For LOCA

conditions, the safety grade system which performs

5.4-41 Rev. 13 WOLF CREEK the function of removing residual heat from the reactor core is the ECCS, which

operates in conjunction with the component cooling water system and the

essential service water system.

The auxiliary feedwater system, along with the steam generator safety and

Atmospheric Relief Valves, provides a completely separate, independent, and diverse means of performing the safety function of removing residual heat, which is normally performed by the RHRS when RCS temperature is less than

350°F.

The auxiliary feedwater system is capable of performing this function for an extended period of time following plant shutdown.

The RHRS is provided with two residual heat removal pumps and heat exchangers

arranged in two separate, independent flow paths. To assure reliability, each

residual heat removal pump is connected to a different vital bus. Each train

is isolated from the RCS on the suction side by two motor-operated valves in

series with each valve receiving power via a separate motor control center and

from a different vital bus. Each suction isolation valve is also provided with

"open-prevent" interlock and "RHRS-Iso-Valve-Open" alarm to prevent exposure of

the RHRS to the normal operating pressure of the RCS (see Section 5.4.7.2.5).

RHRS operation for normal conditions and for major failures is accomplished

completely from the control room. The redundancy in the RHRS design provides

the system with the capability to maintain its cooling function even with major

single failure, such as failure of a residual heat removal pump, valve, or heat

exchanger without impact on the redundant train's continued heat removal.

Although such major system failures are within the system design basis, there

are other less significant failures which can prevent opening of the residual

heat removal suction isolation valves from the control room. Since these

failures are of a minor nature, improbable to occur, and easily corrected

outside the control room, with ample time to do so, they have been

realistically excluded from the engineering design basis. Such failures are

not likely to occur during the limited time period in which they can have any

effect (i.e., when opening the suction isolation valves to initiate residual heat removal operation). However, even if they should occur, they have no adverse safety impact and can be readily corrected. In such a situation, the

auxiliary feedwater system and the steam generator Atmospheric Relief Valves can be used to perform the safety function of removing residual heat and, in fact, can be used to continue the plant cooldown below 350°F, until the RHRS is made available.

5.4-42 Rev. 11 WOLF CREEK One example of this type of a failure is the interlock circuitry which is

designed to prevent exposure of the RHRS to the normal operating pressure of

the RCS (see Section 5.4.7.2.5). In the event of such a failure, RHRS

operation can be initiated by defeating the failure interlock through corrective action at the solid state protection system cabinet or at the

individual affected motor control centers.

The other type of failure which can prevent opening the residual heat removal

suction isolation valves from the control room is a failure of an electrical

power train. Such a failure is extremely unlikely to occur during the few

minutes out of a year's operating time during which it can have any

consequence. If such an unlikely event should occur, several alternatives are

available. The most realistic approach would be to obtain restoration of

offsite power, which can be expected to occur in less than 1/2 hour. Other alternatives are to restore the emergency diesel generator to operation or to bring in an alternative power source.

The only impact of either of the above types of failures is some delay in

initiating residual heat removal operation, while action is taken to open the

residual heat removal suction isolation valves. This delay has no adverse

safety impact because of the capability of the auxiliary feedwater system and

steam generator atmospheric relief valves to continue to remove residual heat, and, in fact, to continue plant cooldown.

A failure mode and effects analysis of the RHRS for normal plant cooldown is

provided as Table 5.4-9.

5.4.7.2.8 Manual Actions

The RHRS is designed to be fully operable from the control room for normal

operation. Manual operations required of the operator are: opening the

suction isolation valves, positioning the flow control valves downstream of the

RHRS heat exchangers, and starting the residual heat removal pumps.

Manual actions required outside the control room, under conditions of single

failure, are discussed in Section 5.4.7.2.7.

5.4.7.3 Performance Evaluation The performance of the RHRS in reducing reactor coolant temperature is

evaluated through the use of heat balance calculations on the RCS, and the

component cooling water system at stepwise intervals following the initiation of RHR operation. Heat removal through the RHR and component cooling water

heat exchangers is calculated at each interval by use of standard water-to-

water heat

5.4-43 Rev. 13 WOLF CREEK exchanger performance correlations. The resultant fluid temperatures for the

RHRS and component cooling water system are calculated and used as input to the

next interval's heat balance calculation.

Assumptions utilized in the series of the heat balance calculations describing

plant RHR cooldown are as follows:

a. RHR operation is initiated 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown. b. RHR operation begins at a reactor coolant temperature of

350°F.

c. Thermal equilibrium is maintained throughout the RCS during the cooldown.

d. Component cooling water heat exchanger outlet temperature during cooldown is limited to a maximum of 120°F. e. Expected cooldown rates of 50°F per hour are not

exceeded.

f. Service water temperature is 90°F.

g. RCS heat input from one reactor coolant pump is maintained until RCS temperature reaches 160°F.

h. Auxiliary CCW heat loads are (x 10 6 Btu/hr) 1 (350 to 225F) 2 (225 to 140F) Auxiliary CCW heat loads Train RHR 1-Train RHR 4 hrs. after shutdown 15.5 15.5 20 hrs. after shutdown 15.5 15.5 Cooldown curves calculated using this method are provided for the case when using both trains of residual heat removal cooldown (Figure 5.4-9) and for the case of a single train residual heat removal cooldown (Figure 5.4-10).

5.4.7.4 Preoperational Testing

Preoperational testing of the RHRS is addressed in Chapter 14.0.

5.4.8 REACTOR WATER CLEANUP SYSTEM

This section is not applicable to WCGS.

5.4.9 MAIN STEAM LINE AND FEED WATER PIPING

Discussion pertaining to the main steam line and feedwater piping are contained

in the following sections:

a. Main Steam Line Piping - Section 10.3.

b. Main Feedwater Piping - Section 10.4.7.

c. Auxiliary Feedwater Piping - Section 10.4.9.

d. Inservice Inspection of a, b, and c - Section 6.6.

5.4-44 Rev. 26 WOLF CREEK 5.4.10 PRESSURIZER

5.4.10.1 Design Bases

The pressurizer provides a point in the RCS where liquid and vapor are

maintained in equilibrium under saturated conditions for control of pressure of

the RCS during steady state operations and transients.

The volume of the pressurizer is equal to, or greater than, the minimum volume

of steam, water, or total of the two which satisfies all of the following

requirements:

a. The combined saturated water volume and steam expansion

volume is sufficient to provide the desired pressure

response to system volume changes.

b. The water volume is sufficient to prevent the heaters from being uncovered during a step load increase of 10 percent at full power.

c. The steam volume is large enough to accommodate the

surge resulting from a 50-percent reduction of full load

with automatic reactor control and a 40-percent steam

dump without the water level reaching the high level

reactor trip point.

d. The steam volume is large enough to prevent water relief

through the safety valves following a loss of load with

the high water level initiating a reactor trip, without

reactor control or steam dump.

e. The pressurizer does not empty following reactor trip and turbine trip.

f. The emergency core cooling does not activate because of

a reactor trip and turbine trip.

The surge line is sized to minimize, to an acceptable value, the pressure drop

between the RCS and the safety valves with maximum discharge flow from the

safety valves.

The surge line and the thermal sleeves are designed to withstand the thermal

stresses resulting from volume surges of water of different temperatures, which

occur during operation.

5.4-45 Rev. 0 WOLF CREEK 5.4.10.2 Design Description

5.4.10.2.1 Pressurizer and Surge Line

The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads constructed of carbon steel, with austenitic stainless steel

cladding on all internal surfaces exposed to the reactor coolant. Stainless

steel is used on all surfaces in contact with the reactor coolant.

The general configuration of the pressurizer is shown in Figure 5.4-11. The

design data of the pressurizer are given in Table 5.4-10. Codes and material

requirements are provided in Section 5.2.

The pressurizer surge line connects the pressurizer to one reactor hot leg,

thus enabling continuous coolant volume pressure adjustments between the RCS and the pressurizer.

The surge line nozzle and removable electric heaters are located in the bottom

of the pressurizer. The heaters are removable for maintenance or replacement.

The pressurizer surge line nozzle diameter is given in Table 5.4-10, and the

pressurizer surge line diameter is shown in Figure 5.1-1, Sheet 2.

A thermal sleeve is provided in the surge line nozzle to minimize thermal

stresses. A retaining screen is located above the nozzle to prevent foreign

matter from entering the RCS. Baffles in the lower section of the pressurizer

prevent an insurge of cold water from flowing directly to the steam/ water interface and assist in mixing.

Spray line nozzles, relief and safety valve connections are located in the top

head of the pressurizer vessel. Spray flow is modulated by automatically

controlled air-operated valves. The spray valves also can be operated manually

by a switch in the control room.

A small continuous spray flow is provided through a manual bypass valve around

the power-operated spray valves to assure that the boron concentration in the

pressurizer is not dissimilar from that in the reactor coolant and to prevent excessive cooling of the spray piping.

During an outsurge of water from the pressurizer, flashing of water to steam

and generation of steam by automatic actuation of the heaters keep the pressure

above the minimum allowable limit.

5.4-46 Rev. 14 WOLF CREEK During an insurge from the RCS, the spray system, which is fed from two cold

legs, condenses steam in the vessel to prevent the pressurizer pressure from

reaching the setpoint of the power-operated relief valves for normal design

transients. Heaters are energized on high water level during insurge to heat the subcooled surge water that enters the pressurizer from the reactor coolant

loop.

Material specifications are provided in Table 5.2-2 for the pressurizer,

pressurizer relief tank, and the surge line. Design transients for the

components of the RCS are discussed in Section 3.9(N).1. Additional details on

the pressurizer design cycle analysis are given in Section 3.9(N).1.

5.4.10.2.2 Pressurizer Instrumentation

Refer to Chapter 7.0 for details of the instrumentation associated with

pressurizer pressure, level, and temperature.

Temperatures in the spray lines from the cold legs of two loops are measured

and indicated. Alarms from these signals are actuated to warn the operator of

low spray water temperature or indicate insufficient flow in the spray lines.

Temperatures in the pressurizer safety and relief valve discharge lines are

measured and indicated. An increase in a discharge line temperature is an

indication of leakage or relief through the associated valve.

5.4.10.3 Design Evaluation 5.4.10.3.1 System Pressure

Whenever a steam volume is present within the pressurizer, the RCS pressure is governed by conditions in the pressurizer.

A design basis safety limit is that RCS pressure does not exceed the maximum

transient value allowed under the ASME Code,Section III.

Evaluation of plant conditions of operation, which follow, indicate that this

safety limit is not reached.

During startup and shutdown, the rate of temperature change in the RCS is

controlled by the operator. Heatup rate is controlled by energy input from the reactor coolant pumps and by the pressurizer electrical heating capacity. This heatup rate takes into account the continuous spray flow provided to the

pressurizer. When the

5.4-47 Rev. 13 WOLF CREEK reactor core is in cold shutdown, the pressurizer heaters are de-energized

except when establishing or maintaining a pressure bubble.

When the pressurizer is filled with water, i.e., during initial system heatup, and near the end of the second phase of plant cooldown, RCS pressure is

maintained by the letdown flow rate via the RHRS.

5.4.10.3.2 Pressurizer Performance

The normal operating water volume at full load conditions is given in Table

5.4-10.

5.4.10.3.3 Pressure Setpoints

The RCS design and operating pressure, together with the safety, power relief, and pressurizer spray valves setpoints and the protection system pressure

setpoints, are listed in Table 5.4-11. The design pressure allows for

operating transient pressure changes. The selected design margin considers

core thermal lag, coolant transport times and pressure drops, instrumentation

and control response characteristics, and system relief valve characteristics.

5.4.10.3.4 Pressurizer Spray

Two separate, automatically controlled spray valves with remote manual

overrides are used to initiate pressurizer spray. In parallel with each spray

valves is a manual throttle valve which permits a small continuous flow through

both spray lines to reduce thermal stresses and thermal shock when the spray

valves open and to help maintain uniform water chemistry and temperature in the

pressurizer. Temperature sensors with low alarms are provided in each spray line to alert the operator to insufficient bypass flow. The layout of the common spray line piping routed to the pressurizer forms a water seal which

prevents the steam buildup back to the control valves. The spray rate is

selected to prevent the pressurizer pressure from reaching the operating

setpoint of the power relief valves during a step reduction in power level of

10 percent of full load.

The pressurizer spray lines and valves are large enough to provide the required

spray flow rate under the driving force of the differential pressure between

the surge line connection in the hot leg and the spray line connection in the

cold leg. The spray line inlet connections extend into the cold leg piping in

the form of a scoop in order to utilize the velocity head of the reactor

coolant loop flow to add to the spray driving force. The spray valves and

5.4-48 Rev. 0 WOLF CREEK spray line connections are arranged so that the spray will operate when one

reactor coolant pump is not operating. The line may also be used to assist in

equalizing the boron concentration between the reactor coolant loops and the

pressurizer.

A flow path from the CVCS to the pressurizer spray line is also provided. This

path provides auxiliary spray to the vapor space of the pressurizer during

cooldown when the reactor coolant pumps are not operating. The thermal sleeves

on the pressurizer spray connection and the spray piping are designed to

withstand the thermal stresses resulting from the introduction of cold spray

water.

5.4.10.4 Tests and Inspections The pressurizer is designed and constructed in accordance with the ASME Code,

Section III.

To implement the requirements of the ASME Code,Section XI the following welds

are designed and constructed to present a smooth transition surface between the

parent metal and the weld metal. The weld surface is ground smooth for

ultrasonic inspection.

a. Support skirt to the pressurizer lower head

b. Surge nozzle to the lower head

c. Nozzles safe ends to the surge, safety, relief, and spray lines *

d. Nozzle to safe end attachment welds *

e. All girth and longitudinal full penetration welds

f. Manway attachment welds

The liner within the safe end nozzle region extends beyond the weld region to

maintain a uniform geometry for ultrasonic inspection.

Peripheral support rings are furnished for the removable insulation modules.

The pressurizer quality assurance program is given in Table 5.4-12.

• In order to mitigate primary water stress corrosion cracking concerns with the originally installed Alloy 600 (82/182) dissimilar metal welds, full structural weld overlays made of ERNiCrFe-7A (Alloy 52M/UNS N06054) have been installed to cover portions of the Pressurizer nozzles (Surge, Safety, Relief, and Spray), nozzle weld butter layers, dissimilar metal welds between the butter and the safe end, safe ends, safe end to stainless steel pipe welds, and connecting stainless steel piping.

5.4-49 Rev. 21 WOLF CREEK 5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM

5.4.11.1 Design Bases

The pressurizer relief discharge system collects, cools, and directs for

processing the steam and water discharged from safety and relief valves in the

containment. The system consists of the pressurizer relief tank, the safety and relief valve discharge piping, the relief tank internal spray header and

associated piping, the tank nitrogen supply, the vent to containment, and the

drain to the waste processing system.

The system design is based on the requirement to absorb a discharge of steam

equivalent to 110 percent of the full power pressurizer steam volume. The

steam volume requirement is approximately that which would be experienced if

the plant were to suffer a complete loss of load accompanied by a turbine trip

but without the resulting reactor trip. A delayed reactor trip is considered

in the design of the system.

The minimum volume of water in the pressurizer relief tank is determined by the

energy content of the steam to be condensed and cooled, by the assumed initial

temperature of the water, and by the desired final temperature of the water

volume. The initial water temperature is assumed to be 120°F, which

corresponds to the design maximum expected containment temperature for normal

conditions. Provision is made to permit cooling the tank should the water

temperature rise above 120°F during plant operation. The design final

temperature is 200°F, which allows the content of the tank to be drained

directly to the waste processing system without cooling.

A safety-related flowpath downstream of the excess letdown heat exchanger is

provided to direct a cooled flow to the PRT. This flow path may be used if the

normal and excess letdown paths are unavailable or if it is desired to contain

the reactor coolant inside the containment. Another flowpath is provided for the controlled release of fluid from the PRT to the containment normal sump.

The vessel saddle supports and anchor bolt arrangement are designed to

withstand the loadings resulting from a combination of nozzle loadings acting

simultaneously with the vessel seismic and static loadings.

5.4.11.2 System Description The piping and instrumentation diagram for the pressurizer relief discharge

system is given in Figure 5.1-1, Sheet 2.

5.4-50 Rev. 0 WOLF CREEK Codes and materials of the pressurizer relief tank and associated piping are

given in Section 5.2. Design data for the tank are given in Table 5.4-13.

The steam and water discharged from the various safety and relief valves inside the containment is routed to the pressurizer relief tank if the discharged

fluid is of reactor grade quality. Table 5.4-14 provides an itemized list of

valves discharging to the tank, together with references to the corresponding

piping and instrumentation diagrams.

The tank normally contains water and a predominantly nitrogen atmosphere. In

order to obtain effective condensing and cooling of the discharged steam, the

tank is installed horizontally with the steam discharged through a sparger pipe

located near the tank bottom and under the water level. The sparger holes are

designed to ensure a resultant steam velocity close to sonic. The water in the tank may be discharged to allow increased capacity for RC letdown via the excess letdown path. In this mode, the water is cooled before it enters the

tank.

The tank is also equipped with an internal spray and a drain which are used to

cool the water following a discharge. Cold water is drawn from the reactor

makeup water system, or the contents of the tank are circulated through the

reactor coolant drain tank heat exchanger of the waste processing system and

back into the spray header.

The nitrogen gas blanket is used to control the atmosphere in the tank and to

allow room for the expansion of the original water plus the condensed steam

discharge. The tank gas volume is calculated, using a final pressure based on

an arbitrary design pressure of 100 psig. The design discharge raises the

worst case initial conditions to 50 psig, a pressure low enough to prevent fatigue of the rupture discs. Provision is made to permit the gas in the tank to be periodically analyzed to monitor the concentration of hydrogen and/or

oxygen.

The contents of the tank can be drained to the waste holdup tank in the waste

processing system or the recycle holdup tank in the boron recycle system via

the reactor coolant drain tank pumps in the waste processing system. Under

emergency conditions, the tank contents can be drained to the containment

normal sump.

5.4.11.2.1 Pressurizer Relief Tank

The general configuration of the pressurizer relief tank is shown in Figure

5.4-12. The tank is a horizontal, cylindrical vessel with elliptical dished

heads. The vessel is constructed of

5.4-51 Rev. 0 WOLF CREEK austenitic stainless steel, and is overpressure protected in accordance with

the ASME Code,Section VIII, Division 1, by means of two safety heads with

stainless steel rupture discs. The PRT saddle supports are designed to

withstand the loadings resulting from a combination of nozzle loadings acting simultaneously with the vessel seismic and static loadings.

A flange nozzle is provided on the tank for the pressurizer discharge line

connection to the sparger pipe. The tank is also equipped with an internal

spray connected to a cold water inlet and with a bottom drain, which are used

to cool the tank following a discharge.

5.4.11.3 Design Evaluation The pressurizer relief discharge system does not constitute part of the reactor

coolant pressure boundary per 10 CFR 50, Section 50.2, since all of its

components are downstream of the RCS safety and relief valves. Thus, General Design Criteria 14 and 15 are not applicable. Furthermore, complete failure of

the auxiliary systems serving the pressurizer relief tank will not impair the

capability for safe plant shutdown.

The design of the system piping layout and piping restraints is consistent with

the hazards protection requirements indicated in Appendix 3.B. The safety and

relief valve discharge piping is restrained so that the integrity and

operability of the valves are maintained in the event of a rupture. Regulatory

Guide 1.67 is not applicable, since the system is not an open discharge system.

The pressurizer relief discharge system is capable of handling the design discharge of steam without exceeding the design pressure and temperature of the

pressurizer relief tank.

The volume of water in the pressurizer relief tank is capable of absorbing the

heat from the assumed discharge, maintaining the water temperature below 200°F.

If a discharge exceeding the design basis should occur, the relief device on

the tank would pass the discharge through the tank to the containment.

The rupture discs on the relief tank have a relief capacity equal to or greater

than the combined capacity of the pressurizer safety valves. The tank design

pressure is twice the calculated pressure resulting from the design basis

safety valve discharge described in Section 5.4.11.1. The tank and rupture

discs holders are also designed for full vacuum to prevent tank collapse if the

contents cool following a discharge without nitrogen being added.

5.4-52 Rev. 1 WOLF CREEK The discharge piping from the pressurizer safety and relief valves to the

relief tank is sufficiently large to prevent backpressure at the safety valves

from exceeding 20 percent of the setpoint pressure at full flow.

5.4.11.4 Instrumentation Requirements The pressurizer relief tank pressure transmitter provides an indication of

pressure relief tank pressure. An alarm is provided to indicate high tank

pressure.

The pressurizer relief tank level transmitter supplies a signal for an

indicator with high and low level alarms. The temperature of the water in the

pressurizer relief tank is indicated, and an alarm actuated by high temperature

informs the operator that cooling of the tank contents is required.

5.4.11.5 Tests and Inspections The system components and piping are subject to nondestructive and hydrostatic

testing during construction, in accordance with Section VIII, Division 1 of the

ASME Code and ANSI B31.1, respectively.

During plant operation, periodic visual inspections and preventive maintenance

are conducted on the system components according to normal industrial practice.

5.4.12 VALVES

5.4.12.1 Design Bases As noted in Section 5.2, all valves out to and including the second valve

normally closed or capable of automatic or remote closure, larger than 3/4

inch, are ANS Safety Class 1, and ASME III, Code Class 1 valves. All 3/4-inch or smaller valves in lines connected to the RCS are Class 2, since the

interface with the Class l piping is provided with suitable orificing for such

valves. Design data for the RCS valves are given in Table 5.4-15.

For a check valve to qualify as part of the RCS, it must be located inside the

containment system. When the second of two normally open check valves is

considered part of the RCS (as defined in Section 5.1), means are provided to

periodically assess back-flow leakage of the first valve when closed.

To ensure that the valves will meet the design objectives, the materials of construction minimize corrosion/erosion and ensure compatibility with the environment. Leakage is minimized to the extent practicable by design.

5.4-53 Rev. 0 WOLF CREEK 5.4.12.2 Design Description

All manual and motor-operated valves of the RCS which are larger than 2 inches are provided with graphite packing. Throttling control valves are provided

with graphite packing. Leakage to the atmosphere is essentially zero for these

valves.

Gate valves at the engineered safety features interface are wedge design and are essentially straight through. The wedges are flex-wedge or solid. Gate

valves have backseats. Globe valves are "T" and "Y" styles. Check valves are

swing type for sizes 2-1/2 inches and larger. All check valves which contain

radioactive fluid are stainless steel, and do not have body penetrations other

than the inlet, outlet, and bonnet. The check hinge is serviced through the

bonnet. All operating parts are contained within the check valve body. The

disc has limited rotation to provide a change of seating surface and alignment

after each check valve opening.

5.4.12.3 Design Evaluation The design requirements for Class 1 valves, as discussed in Section 5.2, limit

stresses to levels which ensure the structural integrity of the valves. In

addition, the testing programs described in Section 3.9(N) demonstrate the ability of the valves to operate, as required, during anticipated and

postulated plant conditions.

Reactor coolant chemistry parameters are specified in the design specifications

to assure the compatibility of valve construction materials with the reactor

coolant. To ensure that the reactor coolant continues to meet these

parameters, the chemical composition of the coolant is analyzed periodically.

The above requirements and procedures, coupled with the previously described

design features for minimizing leakage, ensure that the valves perform their intended functions, as required during plant operation.

5.4.12.4 Tests and Inspections The tests and inspections discussed in Section 3.9(B).6 are performed to ensure the operability of the active valves.

There are no full-penetration welds within the valve body walls. Valves are

accessible for disassembly and internal visual

5.4-54 Rev. 13 WOLF CREEK inspection, to the extent practical. Plant layout configurations determine the

degree of inspectability. The valve nondestructive examination program is

given in Table 5.4-16. Inservice inspection is discussed in Section 5.2.4.

5.4.13 SAFETY AND RELIEF VALVES

5.4.13.1 Design Bases The combined capacity of the pressurizer safety valves can accommodate the

maximum pressurizer surge resulting from complete loss of load, without reactor

trip or any operator action and by the opening of the steam generator safety valves when steam pressure reaches the steam side safety setting.

The pressurizer power-operated relief valves are designed to limit pressurizer

pressure to a value below the fixed high pressure reactor trip setpoint. They

are designed to fail to the closed position on loss of power.

5.4.13.2 Design Description The pressurizer safety valves are of the pop type. The valves are spring

loaded, open by direct fluid pressure action, and have backpressure

compensation features.

The pipe connecting each pressurizer nozzle to its safety valve is shaped in

the form of a loop seal. Condensate resulting from normal heat losses

accumulates in the loop. The water prevents any leakage of hydrogen gas or

steam through the safety valve seats. If the pressurizer pressure exceeds the

set pressure of the safety valves, they start lifting, and the water from the

seal discharges during the actuation period.

The pressurizer power-operated relief valves are solenoid actuated valves which

respond to a signal from a pressure sensing system or to manual control.

Motor-operated valves are provided to isolate the power-operated relief valves if excessive leakage develops or if the PORV fails to close.

Temperatures in the pressurizer safety and relief valve discharge lines are

measured and indicated. An increase in a discharge line temperature is an

indication of leakage or relief through the associated valve.

Liquid flow rates assumed in the analysis are based on the homogeneous

equilibrium saturated flow model which gives the most conservative relief rate.

Accident analysis demonstrates that water relief through the pressurizer valves

occurs only during the

5.4-55 Rev. 0 WOLF CREEK feedline rupture event. The results of the WCGS feedline rupture analysis show

that there is no water relief through the pressurizer valves at any time during

the event.

The power-operated relief valves provide the safety-related means for reactor

coolant system depressurization to achieve cold shutdown.

Design parameters for the pressurizer safety and power relief valves are given in Table 5.4-17.

5.4.13.3 Design Evaluation

The pressurizer safety valves prevent RCS pressure from exceeding 110 percent

of system design pressure, in compliance with the ASME Code,Section III.

The pressurizer power relief valves prevent actuation of the fixed reactor high

pressure trip for design transients up to and including the design step load

decreases with steam dump. The relief valves also limit undesirable opening of

the spring loaded safety valves.

5.4.13.4 Tests and Inspections Safety and relief valves are subjected to hydrostatic tests, seat leakage

tests, operational tests, and inspections, as required. For safety valves that

are required to function during a faulted condition, additional tests are performed. These tests are described in Section 3.9(N). There are no full

penetration welds within the valve body walls. Valves are accessible for

disassembly and internal visual inspection.

Each pressurizer power-operated relief valve is demonstrated operable every 18 months by performing a channel calibration of the actuation instrumentation.

5.4.14 COMPONENT SUPPORTS

5.4.14.1 Design Bases

Component supports allow essentially unrestrained lateral thermal movement of

the loop during plant operation except for a minor thermal restriction at the

steam generator upper lateral supports as the system approaches operating temperature, and provide restraint to the loops and components during accident

and seismic conditions. The loading combinations and design stress limits are

discussed in Section 3.9(N).1.4. Support design is in accordance with the ASME

Code,Section III, Subsection NF. The design maintains the integrity of the

RCS boundary for normal, seismic, and accident conditions and satisfies the

requirements of the piping code. Results of piping and supports stress

evaluation are presented in Section 3.9(N).

5.4-56 Rev. 13 WOLF CREEK 5.4.14.2 Description

The support structures are welded structural steel sections. Linear type

structures (tension and compression struts, columns, and beams) are used in all

cases, except for the reactor vessel supports, which are plate-type structures.

Attachments to the supported equipment are nonintegral types that are bolted to

or bear against the components. The supports-to-concrete attachments are

either anchor bolts or embedded fabricated assemblies.

The supports permit essentially unrestrained thermal growth of the supported systems but restrain vertical, lateral, and rotational movement resulting from seismic and pipe break loadings. This is accomplished using spherical bushings

in the columns for vertical support and girders, bumper pedestals, and tie-rods

for lateral support.

To compensate for manufacturing and construction tolerances, adjustment in the

support structures is provided to ensure proper erection alignment and fit-up.

This is accomplished by shimming or grouting at the supports-to-concrete

interface and by shimming at the supports-to-equipment interface.

The supports for the various components are described in the following

paragraphs.

5.4.14.2.1 Reactor Pressure Vessel

Supports for the reactor vessel (Figure 5.4-13) are individual air cooled rectangular box structures beneath the vessel nozzles bolted to the primary

shield wall concrete. Each box structure consists of a horizontal top plate

that receives loads from the reactor vessel shoe, a horizontal bottom plate

which transfers the loads to the primary shield wall concrete, and connecting

vertical plates which bear against an embedded support. The supports are air

cooled to maintain the supporting concrete temperature within acceptable

levels.

5.4.14.2.2 Steam Generator

As shown in Figure 5.4-14, the steam generator supports consist of the

following elements:

a. Vertical support Four individual columns provide vertical support for

each steam generator. These are bolted at the top to

the steam generator and at the bottom to the concrete

structure. Spherical ball bushings at the top and

5.4-57 Rev. 11 WOLF CREEK bottom of each column allow unrestrained lateral

movement of the steam generator during heatup and

cooldown. The column base design permits both

horizontal and vertical adjustment of the steam generator for erection and adjustment of the system.

b. Lower lateral support

Lateral support is provided at the generator tube sheet

by fabricated steel girders and struts. These are

bolted to the compartment walls and include bumpers that

bear against the steam generator but permit unrestrained

movement of the steam generator during changes in system

temperature.

Stresses in the beams caused by wall displacement during

compartment pressurization are considered in the design.

c. Upper lateral support

The upper lateral support of the steam generator is provided by a ring band at the operating deck. One-way acting compression struts restrain sudden seismic or blowdown induced motion, but permit essentially unrestrained thermal movement of the steam generator. Movement perpendicular to the thermal growth direction of the steam generator is prevented by struts.

5.4.14.2.3 Reactor Coolant Pump

Three individual columns, similar to those used for the steam generator,

provide the vertical support for each pump. Lateral support for seismic and

blowdown loading is provided by three lateral tension tie bars. The pump

supports are shown in Figure 5.4-15.

5.4.14.2.4 Pressurizer

The supports for the pressurizer, as shown in Figures 5.4-16 and 5.4-17,

consist of:

a. A steel ring between the pressurizer skirt and the supporting concrete slab. The ring serves as a leveling

and adjusting member for the pressurizer, and may also

be used as a template for positioning the concrete

anchor bolts.

5.4-58 Rev. 11 WOLF CREEK

b. The upper lateral support consists of struts

cantilevered off the compartment walls that bear against

the "seismic lugs" provided on the pressurizer.

5.4.14.2.5 Pipe Restraints

a. Crossover leg

Restraint at each elbow of the reactor coolant pipe

between the pump and the steam generator (crossover leg)

was provided in the original design to prevent excessive

stresses on the system resulting from postulated breaks

in this pipe. The support includes pipe bumpers with

straps and steel thrust blocks, as shown in Figure 5.4-18, and concrete. Also, a whip restraint strut, as shown in Figure 5.4-19, was originally provided to

prevent whipping of the crossover leg pipe following a

postulated break at the steam generator outlet

nozzle. This restraint was attached to the secondary

shield wall and extended horizontally to the vertical

run of the crossover leg pipe.

Using leak-before-break technology, as allowed by

revised GDC-4 (see USAR Section 3.6), the crossover leg

whip restraints have been deactivated. The shims have

been removed from between the saddle blocks and backup

structures at the elbow restraints, and for the vertical run restraints, the tie rods and pipe clamp assemblies have been removed.

b. Hot leg

A restraint located near the 50-degree elbow in the

hot leg was provided in the original design to prevent excessive

displacement of the hot leg following a postulated guillotine break

at the steam generator inlet nozzle. This restraint consists of

structural steel members which transmit loads to the

concrete structure. This restraint is shown in Figure

5.4-20. Using leak-before-break technology as allowed by revised

GDC-4, the hot leg elbow whip restraint has been deactivated. The

shims between the pipe saddle and the backup structure have been

removed.

c. Hot leg and cold leg lateral restraints

A restraint on each reactor coolant system hot leg and

cold leg is located near the reactor vessel safe-end to

reactor coolant system piping weld with the reactor

vessel primary shield wall to prevent excessive

displacement of either the hot leg or the cold leg

following a postulated guillotine break at the reactor

vessel safe-end to piping weld. These restraints are

shown in Figure 5.4-21.

5.4-59 Rev. 13

WOLF CREEK 5.4.14.3 Design Evaluation

Detailed evaluation ensures the design adequacy and structural integrity of the

reactor coolant loop and the primary equipment supports system. This detailed

evaluation is made by comparing the analytical results with established criteria for acceptability. Structural analyses are performed to demonstrate

design adequacy for safety and reliability of the plant in case of a large or

small seismic disturbance and/or LOCA conditions. Loads which the system is

expected to encounter often during its lifetime (thermal, weight, and pressure)

are applied, and stresses are compared to allowable values as described in

Section 3.9(N).1.4.

The safe shutdown earthquake and design basis LOCA, resulting in a rapid

depressurization of the the system, are required design conditions for public

health and safety. The methods used for the analysis of the safe shutdown earthquake and LOCA conditions are given in Sections 3.9(N).1.4.

5.4.14.4 Tests and Inspections Nondestructive examinations are performed in accordance with the procedures of

the ASME Code,Section V, except as modified by the ASME Code,Section III,

Subsection NF.

5.4.15 REFERENCES

1. "Reactor Coolant Pump Integrity in LOCA," WCAP-8163,

September, 1973.

2. Eggleston, F. T., "Safety-Related Research and Development

for Westinghouse Pressurized Water Reactor, Program Summaries

- Winter 1977 - Summer 1978," WCAP-8768, Revision 2, October,

1978.

3. DeRosa, P., et al., "Evaluation of Steam Generator Tube, Tube

Sheet, and Divider Plate Under Combined LOCA Plus SSE

Conditions," WCAP-7832, January, 1974.

4. "Structural Analysis of the Reactor Coolant Loop for the Standard Nuclear Unit Power Plant System, Volume 2, Analysis of the Primary Equipment Supports," WCAP 9728 Rev. 3, January, 1993.

5. Letter 07-00401, dated July 19, 2007, from USNRC to WCNOC, Authorization of Relief Request 13R-05, alternatives to Structural Weld Overlay Requirements.

5.4-60 Rev. 21 WOLF CREEK TABLE 5.4-1 REACTOR COOLANT PUMP DE SIGN PARAMETER S Unit design pressure, psig 2,485 Unit design temperature, F 650 (a) Unit overall height, ft 2 6.93 Seal water injection, gpm 8 Seal water return, gpm 3 Cooling water flow, gpm 3 66 Maximum continuous cooling water inlet tempe rature 105 Pump Capacity, gpm 100, 600 Developed head, ft 2 88 NPSH required, ft Figure 5.4-2 Suction temperature, F 558.2 Pump discharge nozzle, inside diameter, in. 27-1/2 Pump suction nozzle, inside diameter, in. 31 Speed, rpm 1,185 Water volume (ca sing), ft3 78.6 *Weight total (

including 204,035 (w ith bolts) pump ca sing, motor, and 205, 696 (with studs) motor supports), dry, lb Motor Type Drip proof, squirrel cage induction, water/air cooled Power, hp 7,000 Voltage, Volts 13,200 Phase 3 Frequency, Hz 60 Insulation class Class F, thermalastic epoxy insulation (a) Design temperature of pressure-retaining parts of the pump assembly exposed to the reactor coolant and injection water on the h igh pressure side of the cont rolled leakage seal is assumed to be the tempe rature determined for the parts for a primary loop tempe rature of 650°F. *Total pump we ights between value s shown are bounded by existing analyses. Rev. 17 WOLF CREEK TABLE 5.4-1 (

Sheet 2) Starting Current 1,750 amp @ 13,200 Volts Input, hot reactor coolant 253 + 5 amp Input, cold reactor coolant 33 6 + 7 amp Pump moment of inertia, maximum (lb-ft2) Flywheel 64,000 Shaft 745 Impeller 1,980 Rotor core 27,700 Runner 675 Coupling 190 Rev. 0 WOLF CREEK TABL E 5.4-2 R EACTOR COOLANT PUMP QUALITY ASSURANC E PROGRAM RT* UT*

PT*

MT*

Castings Yes Yes Forgings Main shaft Yes Yes Main studs Yes Yes

Flywheel (rolled plate) Yes Weldments Circumferential Yes Yes

Instrument connections Yes

• RT - Radiographic UT - Ultrasonic

PT - Dye penetrant

MT - Magnetic particle Rev. 0 WOLF CREEK TABL E 5.4-3 ST EAM GENERATOR DESIGN DATA Design pressure, reactor coolant side, psig 2,485 Design pressure, steam side, psig 1,185

Design pressure, primary to secondary, psi 1,600 Design temperature, reactor coolant side, F 650 Design temperature, steam side, F 600

Design temperature, primary to secondary, F 650 Total heat transfer surface area, ft 2 55,000 Maximum moisture carryover, wt percent 0.25 Overall height, ft-in. 67-8

Number of U-tubes 5,626

U-tube nominal diameter, in. 0.688 Tube wall nominal thickness, in. 0.040

Number of manways 4

Inside diameter of manways, in. 16

Number of handholes 6 Design fouling factor, ft 2-hr-F/Btu 0.00005 Steam flow (per unit), lb/hr 3.785 x 10 6Nominal primary side water volume, ft 3 No load 962 Full load 962 Nominal secondary side water volume, ft 3 No load 3,559.6 Full load 2,212.3 Rev. 0 WOLF CREEK TABL E 5.4-4 ST EAM GENERATOR QUALITY ASSURANC E PROGRAM (a) (a) (a) (a) (a)

RT UT PT MT ETTube Sheet Forging Yes Yes (b)

Cladding Yes Yes Channel Head (if fabricated)

(c) (d)

Fabrication Yes Yes Yes Cladding Yes

Secondary Shell and Head

Plates Yes Tubes Yes Yes Nozzles (Forgings) Yes Yes

Weldments

Shell, longitudinal Yes Yes

Shell, circumferential Yes Yes

Cladding (channel head-tube sheet joint clad-

ding restoration) Yes Primary nozzles to fab head Yes Yes Manways to fab head Yes Yes

Steam and feedwater nozzle to shell Yes Yes Support brackets Yes

Tube to tube sheet Yes Rev. 0 WOLF CREEK TABL E 5.4-4 (Sheet 2)

(a) (a) (a) (a) (a)

RT UT PT MT ETInstrument connections (primary and secondary) Yes Temporary attachments after removal Yes After hydrostatic test (all major presssure

boundary welds and

complete cast channel

head - where accessible) Yes Nozzle safe ends (if weld deposit) Yes Yes (a) RT - Radiographic UT - Ultrasonic

PT - Dye penetrant

MT - Magnetic particle

ET - Eddy Current (b) Flat surfaces only

(c) Weld deposit

(d) Base material only Rev. 0 WOLFCREEKTABLE5.4-5REACTORCOOLANTPIPINGD ESIGNPARAM ETERSReactorinletpiping,insidediameter,in.27-1/2Reactorinletpiping,nominalwallthickness,in.2.32 Reactoroutletpiping,insidediameter,in.29 Reactoroutletpiping,nominalwallthickness,in.2.45Coolantpumpsuctionpiping,insidediameter,in.31Coolantpumpsuctionpiping,nominalwallthickness,in.2.60Pressurizersurgelinepiping,nominalpipesize,in.14 Pressurizersurgelinepiping,nominalwallthickness,in.1.406Nominalwatervolume,allfourloopsincludingsurgeline,ft31,225ReactorCoolantLoopPipingDesign/operatingpressure,psig2,485/2,235Designtemperature,F650PressurizerSurgeLineDesignpressure,psig2,485 Designtemperature,F680PressurizerSafetyValveInletLineDesignpressure,psig2,485 Designtemperature,F680Pressurizer(Power-Operated)ReliefValveInletLineDesignpressure,psig2,485 Designtemperature,F680Rev.0 WOLF CREEK TABL E 5.4-6 R EACTOR COOLANT PIPING QUALITY ASSURANC E PROGRAM RT* UT*

PT*

Fittings and Pipe (Castings) Yes Yes Fittings and Pipe (Forgings) Yes Yes

Weldments Circumferential Yes Yes Nozzle to runpipe Yes Yes (except no RT for nozzles

less than 6 inches)

Instrument connections Yes

Castings Yes Yes (after finishing)

Forgings Yes Yes (after finishing)

• RT - Radiographic UT - Ultrasonic

PT - Dye Penetrant Rev. 0 WOLFCREEKTABLE5.4-7DESIGNPARAMETERSFORRESIDUALHEATREMOVALSYSTEMOPERATIONResidualheatremovalsystemstartup,hoursafter~4reactorshutdownReactorcoolantsysteminitialpressure,psig~360Reactorcoolantsysteminitialtemperature,F~350Componentcoolingwaterdesigntemperature,F105 Cooldowntime,hoursafterinitiationofresidual<20heatremovalsystemoperationReactorcoolantsystemtemperatureatendof140cooldown,FDecayheatgenerationat20hoursafterreactor75.2x10 6shutdown,Btu/hrRev.14 WOLF CREEK TABLE 5.4-8 RESIDUAL HEAT REMOVAL SYSTEM COMPONENT DATA Residual Heat Removal Pumps Number 2 Design pressure, psig 600

Design temperature, F 400

Design flow, gpm 3,800

Design head, ft 350 NPSH required at 3,800 gpm, ft 17

Power, hp 500 Residual Heat Exchangers

Number 2 Design heat removal capacity, Btu/hr 39.0 x lO 6 Estimated UA, Btu/hr F LMTD 2.3 x 10 6 Tube Side Shell Side Design pressure, psig 600 150 Design temperature, F 400 200 Design flow, lb/hr 1.9 x 10 6 3.8 x 10 6 Inlet temperature, F 140 105 Outlet temperature, F 119.4 115.2 Material Austenitic Carbon stainless steel

steel Fluid Reactor Component coolant cooling

water RHR Isolation Valve Encapsulation Tank (TEJ01A & B)

Manufacturer Richmond Eng.

Quantity 2

Height ft-in. 12-6

Diameter ft-in. 5-6

Design Pressure, psig 75

Design Temperature, F 400

Material Austenitic stainless steel

Codes and Standards ASME Section III, Class 2

Seismic Category I Rev. 0 WOLF CREEK TABL E 5.4-9 (Sheet 1 of 5)

FAILUR E MODES AND EFFECTS ANALYSIS - R ESIDUAL HEAT REMOVAL SYST EM ACTIV E COMPONENTS - PLANT COOLDOWN OP ERATION Component Failure Mode Effect on System Operation*

Failure Detection Method**

Remarks

1. Motor-operated a. Fails to open Failure blocks reactor coolant Valve position indication 1. Valve is electri

- gate valve 8701A on demand (open flow from hot leg of RC loop 1 (closed to open position cally interlocke d (8701B analogous) manual mode CB through train "A" of RHRS. change) at CB; RC loop 1 with the contain

- switch selec- Fault reduces redundancy of hot leg pressure indica- ment sump isola-tion) RHR coolant trains provided. tion (PI-405) at CB; RHR tion valves 8811 A No effect on safety for system train "A" discharge flow and 8812A, with

operation. Plant cooldown indication (FI-618) and RHR to charging

requirements will be met by low flow alarm at CB; and pump suction lin e reactor coolant flow from hot RHR pump discharge pres- isolation valve

leg of RC loop 4 flowing sure indication (PI-614) 8804A and with

through train "B" of RHRS. at CB. a "prevent-open"

However, time required to pressure inter-

reduce RCS temperature will lock (PB-405A) o f be extended. RC loop 1 hot

leg. The valve

cannot be opened

remotely from th e CB if one of the

indicated isola-

tion valves is

open or if RC

loop pressure

exceeds 360 psig

. 2. If both trains o f RHRS are unavail

- able for plant

cooldown due to

multiple compo-

nent failures,

the auxiliary

feedwater system

and SG atmospher ic relief

• See list at end of table for definition of acronyms and abbreviations used.

• • As part of plant operation; periodic tests, surveillance inspections, and instrument calibrations are made to monitor

equipment and performance. Failures may be detected during such monitoring of equipment, in addition to detection

methods noted.

Rev. 13 WOLF CREEK TABL E 5.4-9 (Sheet 2 of 5)

Component Failure Mode Effect on System Operation*

Failure Detection Method**

Remarks valves can be used to perform

the safety func-

tion of removing

residual heat.

2. Motor-operated Same failure Same effect on system operation Same methods of detection Same remarks as gate valve modes as those as that stated for item 1. as those stated for item 1. those stated for

8702A (8702B stated for item 1, except

analogous) item 1. for pressure

interlock (PB-

403A) control.

3. RHR pump 1, Fails to Failure results in loss of Open pump switchgear The RHRS shares APRH (RHR deliver work- reactor coolant flow from hot circuit breaker indication components with

pump 2 ing fluid. leg of RC loop 1 through train at CB; circuit breaker the ECCS. Pumps analogous) "A" of RHRS. Fault reduces close position monitor are tested as

redundancy of RHR coolant light for group monitoring part of the ECCS trains provided. No effect on of components at CB; testing program

safety for system operation. common breaker trip alarm (see Section

Plant cooldown requirements at CB; RC loop 1 hot leg 6.3.4). Pump

will be met by reactor coolant pressure indication (PI-405) failure may also

flow from hot leg or RC loop 4 at CB; RHR train "A" dis- be detected

flowing through train "B" of charge flow indication during ECCS test-RHRS. However, time required (FI-618) and low flow alarm ing.

to reduce RCS temperature will at CB; and pump discharge

be extended. pressure indication (PI-614)

at CB.

4. Motor-operated a. Fails to open Failure blocks miniflow line Valve position indication Valve is auto-gate valve FCV- on demand (open to suction of RHR pump "A" (closed to open position matically con-

610 (FCV-611 manual mode CB during cooldown operation of change) at CB. trolled to open

analogous) switch selec- checking boron concentration when pump dis-

tion). level of coolant in train "A" charge is less

of RHRS. Circulation through than ~816 gpm an d miniflow line is not available. close when the If the operator does not secure discharge exceed s RHR pump "A" before cavitation ~1650 gpm. The occurs, failure will reduce the valve protects redundancy of RHR coolant trains. the pump from No effect on safety for system dead-heading operation.

during ECCS oper-ation. CB switch set to "Auto" Rev. 16 WOLF CREEK TABL E 5.4-9 (Sheet 3 of 5)

Component Failure Mode Effect on System Operation*

Failure Detection Method**

Remarks position for automatic contro l of valve posi-

tioning.

b. Fails to close Failure allows for a portion Valve position indication on demand of RHR heat exchanger "A" dis- (open to closed position

("Auto" mode charge flow to be bypassed to change) and RHRS train "A"

CB switch suction of RHR pump "A." RHRS discharge flow indication

selection). train "A" is degraded for the (FI-618) at CB.

regulation of coolant tempera-

ture by RHR heat exchanger "A."

No effect on safety for system

operation. Cooldown of RCS with-

in established specification

cooldown rate may be accomplished

through operator action of

throttling flow control valve

HCV-606 and controlling cooldown

with redundant RHRS train "B".

5. Air diaphragm- a. Fails to open Failure prevents coolant dis- RHR pump "A" discharge Valve is designe d operated butter- on demand charged from RHR pump "A" from flow temperature and RHRS to fail "closed" fly valve FCV- ("Auto" mode bypassing RHR heat exchanger train "A" discharge to RCS and is electri-

618 (FCV-619 CB switch "A" resulting in mixed mean cold leg flow temperature cally wired so

analogous) selection) temperature of coolant flow to recording (TR-612) at CB; that electrical

RCS being low. RHRS train "A" and RHRS train "A" dis- solenoid of the

is degraded for the regulation charge to RCS cold leg air diaphragm

of controlling temperature of flow indication (FI-618) operator is

coolant. No effect on safety at CB. energized to ope n for system operation. Cooldown the valve. Valv e of RCS within established is normally

specification rate may be "closed" to alig n accomplished through operator RHRS for ECCS action of throttling flow con- operation during

trol valve HCV-606 and plant power oper

- controlling cooldown with ation and load

redundant RHRS train "B." follow.

b. Fails to close Failure allows coolant dis- Same methods of detec-on demand charged from RHR pump "A" to tion as those stated

("Auto" mode bypass RHR heat exchanger "A", for item 5.a.

CB switch resulting in mixed mean tem-

selection). perature of coolant flow to RCS

being high. RHRS train "A" is

degraded for the regulation of Rev.

0 WOLF CREEK TABL E 5.4-9 (Sheet 4 of 5)

Component Failure Mode Effect on System Operation*

Failure Detection Method**

Remarks controlling temperature of coolant. No effect on safety

for system operation. Cooldown

of RCS within established

specification rate may be accom-

plished through operator action

of throttling flow control valve

HCV-606 and controlling cool-

down with redundant RHRS train

"B." However, cooldown time will

be extended.

6. Air diaphragm- a. Fails to close Failure prevents control of Same methods of detection Valve is designe d operated butter- on demand for coolant discharge flow from as those stated for item 5. to fail "open."

fly valve flow reduction. RHR heat exchanger "A," resul- In addition, monitor light and Valve is nor-

HCV-606 ting in loss of mixed mean tem- and alarm (valve closed) for mally "open" to

(HCV-607 perature coolant flow adjust- group monitoring of components align RHRS for

analogous) ment to RCS. No effect on at CB.

ECCS operation safety for system operation. during plant

Cooldown of RCS within estab- power operation

lished specification rate may and load follow.

be accomplished by operator

action of controlling cooldown

with redundant RHRS train "B."

b. Fails to open Same effect on system operation Same methods of detection on demand for as that stated for item 6.a. as those stated for

increased flow. item 6.a.

7. Manual globe Fails closed. Failure blocks flow from train CVCS letdown flow indi- Valve is normall y valve V001 "A" of RHRS to CVCS letdown cation (FI-132) at CB. "closed" to alig n (V002 analo- heat exchanger. Fault prevents RHRS for ECCS gous) (during the initial phase of operation during plant cooldown) the adjustment plant power oper

- of boron concentration level of ation and load

coolant in lines of RHRS train follow.

"A" so that it equals the con-

centration level in the RCS, using

the RHR cleanup line to CVCS.

No effect on safety for system

operation. Operator can balance

boron concentration levels by

cracking open flow control

valve HCV-606 to permit flow

to cold leg of loop 1 of RCS

in order to balance levels

using normal CVCS letdown flow.

Rev.

0 WOLF CREEK TABL E 5.4-9 (Sheet 5 of 5)

Component Failure Mode Effect on System Operation*

Failure Detection Method**

Remarks

8. Air diaphragm Fails to open Failure blocks flow from trains Valve position indication 1. Same remark as operated globe on demand "A" and "B" of RHRS to CVCS (degree of openings) at that stated abov e valve HCV-128 letdown heat exchanger. Fault CB and CVCS letdown flow for item 7.

prevents use of RHR cleanup indication (FI-132) at

line to CVCS for balancing CB. 2. Valve is a com-

boron concentration levels of ponent of the

RHR trains "A" and "B" with RCS CVCS that per-

during initial cooldown opera- forms an RHR

tion and later in plant cooldown function during

for letdown flow. No effect on plant cooldown

safety for system operation. operation.

Operator can balance boron con-

centration levels with similar

actions, using pertinent flow

control valve HCV-606 (HCV-607),

as stated for item 7. Normal

CVCS letdown flow can be used

for purification if RHRS cleanup

line is not available.

9. Motor-operated Fails to close Failure reduces the redundancy Valve position indication Valve is a compo

- gate valve on demand. of isolation valves provided to (open to closed position nent of the ECCS 8812A isolate RHRS train "A" from change) at CB and valve that performs a (8812B RWST. No effect on safety for (closed) monitor light RHR function

analogous) system operation. Check valve and alarm at CB. during plant

8958A in series with motor cooldown. Valve

operated valve provides the is normally

primary isolation against the "open" to align

bypass of RCS coolant flow from RHRS for ECCS the suction of RHR pump "A" to operation during

- RWST. plant power oper

- ation and load

follow.

List of acronyms and abbreviations

Auto - Automatic CB - Control board

CVCS - Chemical and volume control system

ECCS - Emergency core cooling system RC - Reactor coolant

RCS - Reactor coolant system

RHR - Residual heat removal

RHRS - Residual heat removal system

RWST - Refueling water storage tank

SG - Steam generator

Rev.

0 WOLF CREEK TABL E 5.4-10 PR ESSURIZER DESIGN DATA Design pressure, psig 2,485 Design temperature, F 680

Surge line nozzle diameter, in. 14

Heatup rate of pressurizer using heaters

only, F/hr 55 Internal volume, ft 3 1,800 Normal conditions at 100% rated load Steam volume, ft 3 720 Water volume, ft 3 1,080 Rev. 0 WOLF CREEK TABLE 5.4-11 REACTOR COOLANT SYSTEM DESIGN PRESSURE SETTINGS Psig Hydrostatic test pressure 3,107 Design pressure 2,485

Safety valves (begin to open) 2,460 High pressure reactor trip 2,385 High pressure alarm 2,310

Power-operated relief valves 2,335*

Pressurizer spray valves (full open) 2,310 Pressurizer spray valves (begin to open) 2,260

Proportional heaters (begin to operate) 2,250

Operating pressure 2,235

Proportional heater (full operation) 2,220 Backup heaters on 2,210 Low pressure alarm 2,210

Pressurizer power-operated relief and iso-

lation valve interlock - auto closure 2,185

Low pressure reactor trip 1,940

• At 2,335 psig, a pressure signal initiates actuation (opening) of these valves. Remote manual control is also provided.

Rev. 16 WOLF CREEK TABL E 5.4-12 PR ESSURIZER QUALITY ASSURANC E PROGRAM (a) (a) (a) (a)

RT UT PT MTHeads Plates Yes Cladding Yes Shell Plates Yes Cladding Yes Heaters (b)

Tubing Yes Yes

Centering of element Yes

(c) (c)

Nozzle (Forgings) Yes Yes Yes Weldments

Shell, longitudinal Yes Yes Shell, circumferential Yes Yes

Cladding Yes

Nozzle safe end Yes Yes

Instrument connection Yes

Support skirt, longi- Yes Yes

tudinal seam

Support skirt to lower Yes Yes

head Temporary attachments Yes

(after removal)

All external pressure Yes boundary welds after

shop hydrostatic test (a) RT - Radiographic UT - Ultrasonic

PT - Dye Penetrant

MT - Magnetic Particle

(b) Or a UT and ET (Eddy Current)

(c) MT or PT Rev. 0 WOLF CREEK TABL E 5.4-13 PR ESSURIZER RELIEF TANK DESIGN DATA Design pressure, psig 100 Normal operating pressure, psig 3

Final operating pressure, psig 50

Rupture disc release pressure, psig

Nominal 91

Range 86 to 100 Normal water volume, ft 3 1,350 Normal gas volume, ft 3 450 Design temperature, F 340 Initial operating water temperature, F 120

Final operating water temperature, F 200 Total rupture disc relief 1.6 x 10 6 capacity at 100 psig, lb/hr Cooling time required following maximum

discharge approximately, hr

Spray feed and bleed l

Utilizing RCDT heat exchanger 8 Rev. 0 WOLF CREEK TABL E 5.4-14 RELIEF VALVE DISCHARG E TO THE PRESSURIZER RELIEF TANKReactor Coolant System 3 Pressurizer safety valves Figure 5.1-1, Sheet 2

2 Pressurizer power-operated Figure 5.1-1, Sheet 2

relief valves

Residual Heat Removal System

2 Residual heat removal pump Figure 5.4-7

suction lines from the reactor coolant system hot legs

Chemical and Volume Control System

1 Seal water return line Figure 9.3-8, Sheet 1

1 Letdown line Figure 9.3-8, Sheet 1 Rev. 0 WOLF CREEK TABL E 5.4-15 R EACTOR COOLANT SYST EM VALVE DESIGN PARAM ETERSDesign/normal operating pressure, psig 2,485/2,235 Preoperational plant hydrotest, psig 3,107

Design temperature, F 650 Rev. 0 WOLF CREEK TABL E 5.4-16 R EACTOR COOLANT SYST EM VALVES NONDESTRUCTIVE EXAMINATION PROGRAM (a) (a) (a)

RT UT PTBoundary Valves, Pressurizer Relief and Safety Valves

Castings (larger than 4 inches) Yes Yes (b)

(2 inches to 4 inches) Yes Yes Forgings (larger than 4 inches) (c) (c) Yes (2 inches to 4 inches) Yes (a) RT - Radiographic UT - Ultrasonic

PT - Dye Penetrant (b) Weld ends only

(c) Either RT or UT Rev. 0 WOLF CREEK TABL E 5.4-17 PR ESSURIZER VALVES DESIGN PARAM ETERS Pressurizer Safety Valves Number 3 Maximum relieving capacity, ASM E rate flow, 415,764 lb/hr Set pressure, psig 2,460 Design temperature, F 650

Fluid Saturated steam

Transient condition, F (Superheated steam) 680 Backpressure Normal, psig 3 to 5

Expected during discharge, psig 500 Environmental conditions Ambient temperature (F) 50 to 120 Relative humidity (%) 0 to 100 Pressurizer Power-Operated Relief Valves

Number 2 Design pressure, psig 2,485

Design temperature, F 650

Relieving capacity at 2,335 psig, per valve, 210,000 lb/hr

Fluid Saturated steam

Transient condition, F (Superheated steam) 680 Rev. 16 WOLF CREEK Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-1 REACTOR COOLANT CONTROLLED LEAKAGE PUMP 600 500 -.... (1) 400 ::r::: (f) c.. z -g 300 Ctl "'0 Ctl (1) ::r::: Ctl 0 200 1-100 0 WOLF CREEK 14113-5 Required Net Positive Suction Head 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 Flow (Thousands of GPM) Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-2 REACTOR COOLANT PUMP ESTIMATED PERFORMANCE CHARACTERISTIC WOLF CREEK Steam Nozzle ---------1,.,

with Flow Restrictor Swirl Vane Moisture Separators Feedwater Nozzle Transition Cone Tube Bundle Support Ring Tube Sheet Reactor Inlet Nozzle I I 14113-1 Positive Entrainment Steam Dryers Secondary Manway r-----Upper Shell 1 Feed water Ring with Inverted "J" Tubes Antivibration Bars Tube Support Plate Lower Shell I Flow Blockers Divider Plate Reactor Coolant Outlet Nozzle Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-3 WESTINGHOUSE MODEL F STEAM GENERATOR WOLF CREEK Perforated Plates on Secondary Separators Deckplate Relief Reduced Swirl Vane Orifice Offset Feedwater Removal of Resistance 14113-2 Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-lt WESTINGHOUSE MODEL F STEAM GENERATOR MECHANICAL MODIFICATION IMPROVEMENTS I --------------------------------------------------T WOLF CREEK Faadwatar Nozzle in Upper Sealed Thermal Sleeve 14113*3 Wet Layup Connection Upgraded Primary Separators J-Nozzle Type Faadwater Ring lncraasad Number of Antivibration Bars Quatrefoil Tuba Support Plate& Flow Distribution Baffle WOLF CREEK REV.13 UPDATED SAFETY ANALYSIS REPORT Figure 5.4-5 WESTINGHOUSE MODEL F STEAM GENERATOR DESIGN IMPROVEMENTS

' ---.. --.. ------------------------------------------------------------------------------------------------------------...1 Support Plate Section WOLF CREEK 14113-4 Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-6 QUATREFOIL BROACHED HOLES lliD'iJ£1JN(OWAfEII SlOIU.Gt r*""' 0 (SE! NOTI!S ON f'OLLOWINQ PAft!) Rev. 14 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-8 RESIDUAL HEAT REMOVAL SYSTEM PROCESS FLOW DIAGRAM WOLF CREEK NOTES TO FIGURE 5.4-8 MODES OF OPERATION MODE A - INITIATION OF RHR OPERATION When the reactor coolant temperature and pressure are

reduced to 350 F and 360 psig, approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after

reactor shutdown, the second phase of plant cooldown starts

with one train of RHR being placed in operation. Before starting the pump, the inlet isolation valves are opened, the heat exchanger flow control valve is set at minimum flow, and the outlet valve is verified open. The automatic miniflow valve is open and remains so until the pump flow exceeds the close setpoint at which time it closes. Should the pump flow drop below the open setpoint, the miniflow valves open automatically.

The other train of RHR is in the ECCS standby made of operation from 350F to 225F. At 225F this train is then allowed to operate in the shutdown cooling mode.

Startup of the RHRS includes a warmup period during which

time reactor coolant flow through the heat exchangers is

limited to minimize thermal shock on the RCS. The rate of

heat removal from the reactor coolant is controlled manually by regulating the reactor coolant flow through the residual

heat exchangers. The total flow is regulated automatically

by control valves in the heat exchanger bypass line to

maintain a constant total flow. The cooldown rate is

limited to 50 F/hr, based on equipment stress limits and a

120 F maximum component cooling water temperature.

MODE B - END CONDITIONS OF NORMAL COOLDOWN

This situation characterizes the RHRS operation at lower RCS temperatures. As the reactor coolant temperature decreases, the flow through the residual heat exchanger is increased until all of the flow is directed through the heat exchanger to obtain maximum cooling.

Note:

For the safeguards functions performed by the RHRS, refer to

Section 6.3, ECCS.

Rev. 26 WOLF CREEK NOTES TO FIGURE 5.4-8 (Sheet 2)

VALVE ALIGNMENT CHART

Valve No. Operational Mode A B 2 C C 3 O* C 10 O O 11 C* O 12 C C 13 C C 14 C C 15 O* C 16 P C 17 C* C 18 P O 19 O* O 20 C C 21 C C 22 C* O 23 C* O 24 O O 26 O O

O = Open

C = Closed

P = Partially Open

• Valve position for RHR train in ECCS standby mode 350F to 225F.

Rev. 26 WOLF CREEK NOTES TO FIGURE 5.4-8 (Sheet 3)

MODE A - INITIATION OF RHR OPERATION

Pressure Temperature Flow Location Fluid (psig) (F) (gpm)

(a) (lb/hr) 24 Reactor coolant 360 350 3,800 1.60 x 10 6 25 Reactor coolant 367 350 3,800 1.60 x 10 6 26 Reactor coolant 502 350 3,800 1.60 x 10 6 27 Reactor coolant 501 350 1,259 0.56 x 10 6 31 Reactor coolant 499 140 1,259 0.56 x 10 6 29 Reactor coolant 456 350 2,541 1.13 x 10 6 32 Reactor coolant 456 280 3,800 1.69 x 10 6 28 Reactor coolant 440 280 3,690 1.64 x 10 6 19 Loop 4 Reactor coolant 364 280 1,992 0.885 x 10 6 19 Loop 3 Reactor coolant 379 280 1,698 0.755 x 10 6 34* RHR Static Head Ambient 0 0

35* RHR Static Head Ambient 0 0 36* RHR Static Head Ambient 0 0 37* RHR Static Head Ambient 0 0 41* RHR Static Head Ambient 0 0 39* RHR Static Head Ambient 0 0 42* RHR Static Head Ambient 0 0 38* RHR Static Head Ambient 0 0 20 Loop 1* RHR Static Head Ambient 0 0 20 Loop 2* RHR Static Head Ambient 0 0 (a)At reference conditions 350 F and 360 psig

• RHR train in ECCS standby mode 350F to 225F

Rev. 27 WOLF CREEK NOTES TO FIGURE 5.4-8 (Sheet 4)

MODE B - END CONDITIONS OF A NORMAL COOLDOWN Pressure Temperature Flow Location Fluid (psig) (F) (gpm)

(a) (lb/hr) 24 Reactor coolant 0 140 3,800 1.87 x 10 6 25 " 7 140 3,800 1.87 x 10 6 26 " 156 140 3,800 1.87 x 10 6 27 " 149 140 3,800 1.87 x 10 6 31 " 129 120 3,800 1.87 x 10 6 20 " 93 120 0 0 32 " 93 120 3,800 1.87 x 10 6 28 " 75 120 3,800 1.87 x 10 6 19 " 2 120 1,900 0.935 x 10 6 34 " 0 140 3,800 1.87 x 10 6 35 " 7 140 3,800 1.87 x 10 6 36 " 156 140 3,800 1.87 x 10 6 37 " 149 140 3,800 1.87 x 10 6 41 " 129 120 3,800 1.87 x 10 6 39 " 93 120 0 0 42 " 93 120 3,800 1.87 x 10 6 38 " 75 120 3,800 1.87 x 10 6 20 " 2 120 1,900 0.935 x 10 6 (a)At reference conditions 140 F and 0 psig

Rev. 0 Wolf Creek NSSS Power 3579 MWt Normal Plant Cooldown - One Train from 350 - 225 °F then both Trains 120140160180 200220240 260 280300320 34036038012344.555.566.577.588.599.59.71010.410.911.411.912.412.913.413.914.414.915.415.916.416.917.417.9Time after Shutdown hrsRCS Temperatu90 F Lake55 F Lake Rev. 26 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-9 NORMAL RESIDUAL HEAT REMOVAL COOLDOWN

Wolf Creek NSSS Power 3579 MWt Plant Cooldown Single Train 4oo I 350 ------........

I ............

I u... 0 .._... t) 300 '-:::J ..... 0 '-I) n. E I) 250 I !-l "' I I I u I 0:: I 200 1-150 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 Time After Reactor Shutdown (hrs.) Rev. 7 WOLF CREEK UPDATED SAFETY ANALYSiS REPORT FiGURE 5.4-10 SINGLE RESIDUAL HEAT REMOVAl TRAIN COOLDOVVN HEATER SUPPORT PLATE "WOLF CREEK SPRAY NOZZLE SAFETY NOZZLE UPPER HEAD LIFTING TRUNNION SHELL LOWER HEAD INSTRUMENTATION NOZZLE ELECTRICAL HEATER SUPPORT SKIRT SURGE NOZZLE WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-11 PRESSURIZER Rev. 0 DISCHARGE LIME CONNECTION VESSEL SUPPORT WOLF CREEK SPRAY WATER INLET VENT CONNECTION I I I I I I I I I I r-1 \ ' ' 'T----' I '--l----SAFETY HEADS l-=--=g = J INTERNAL SPRAY DRAIN CONNECTION VESSEL SUPPORT Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-12 PRESSURIZER RELIEF TANK l PLAN VIEW G_ REACTOR SECTION RFACTOR VESSEL SUPPORT RFQ'D) -

SECTION B@ WOLF c Rev. 0 UPDATED SAFE REEK -1 TY ANALYSIS REPORT FIGURE 5.4-13 -REACTOR VESSEL SUPPORTS

-

r------------------------------------------------------------------------------------------------------------------------------------

--; ! I I : I I I I I VI LATERAL SUPPORT LATERAL SUPPORT l r "'/ I -WI DE FLANGE COLUMNS DiRECTtOH OF THERMAL EXPANSiON US AR FIG. 5. 4 -14 REV. 9 w*[brr NUCLEAR OPERATING CORPORATION I I l I I I STEAM GENERATOR SUPPORTS I I I _.A#bc@. .. I __ , I ----. --------------------------------------------------

---

---

*------I I CROSS-OVER LEG WOLl? CREEK LEG TIE RODS WIDE FLANGE COLUMNS WOLF CREEK Rev. 0 UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-15 REACTOR COOLANT PUMP SUPPORTS

_r--SUPPORT

.. ,. CONCRETE SLAB { ANCHOR BOLTS PLAN AT SUPPORT SKIRT WOLF CREEK ( PR<SSURIZU SUPPORT FRAMING I ; I I I Dl r* ;*1 I I I I I I I I I I --L.f-L I I ! SECTION@

11-I:::J SHIELD WALL r: *I I I I I u SKIRT BOLT ( TYP.l Rev. 0 ifOi.F OPDAT!D SAFETY ANALYSIS REPORT FIGURE 5.1.f-16 REACTOR BUILDING INTERNALS PRESSURIZER SUPPORTS PRESSURIZER SKIRT WOLF CREEK BEARING PLATE GROUT Rev. 0 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-17 PRESSURIZER SUPPORTS WOLF CREEK SADDLE BLOCK I SHIMS HAVE BEEN REMOVED Rev. 7 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-18 CROSSOVER LEG SUPPORTS TO R.C.

G_ HOT LE WOLF CREEK TO REACTOR VESSEL STEAM GENFRATOR Rev. 7 WOLF CREEK UPDATED SAFETY ANALYSIS REPORT FIGURE 5.4-19 CROSSOVER LEG VERTICAL RUN RESTRAINT (DELETED IN 5TH REFUELING OUTAGE)

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, I --1-z <( 0:: t{ I '-'-' 0:: (* LLI ---' C* I 1:: .. -----* _____ I ____ _