ML18093A891
| ML18093A891 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 03/08/2018 |
| From: | Wolf Creek |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML18093A810 | List:
|
| References | |
| WO 18-0011 | |
| Download: ML18093A891 (224) | |
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. 29 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. 29 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. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Section Page
5.4.5 MAIN STEAM LINE ISOLATION SYSTEM 5.4-31 5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM 5.4-31 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM 5.4-31
5.4.7.1 Design Bases 5.4-31 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 5.4-60 5.4.14.4 Tests and Inspections 5.4-60
5.0-iv Rev. 29 WOLF CREEK TABLE OF CONTENTS (Continued)
Section Page
5.4.15 REFERENCES 5.4-60
5.0-v Rev. 29 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. 29 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. 29
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 T itle Drawing #*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. 29 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
- 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
- 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 CR EE K TABL E 5.1-1 SYST E M D E SIGN AND OP E RATING PARAM E T E RS Plant design life, years 40 Nominal operating pressure, psig 2,235 Total system volume, including 12,135
+/-100* pressurizer and surge line, ft 3 System liquid volume, including 11,393 pressurizer water at maximum guaranteed power, ft 3 Pressurizer 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°F Rev. 13 WOLF CR EE K 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
+(T avg = 570.7°F)(T avg = 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 WOLFCR EE K NOT ESTOFIGUR E 5.1-2ModeASteadyStateFullPowerOperationKey:BasisnumbersNSSS3579MWtforT hotMaintained@10%SGTubePlugging()numbersNSSS3579MWtfor15°FT hotReduction@10%SGTubePluggingLocationFluid Pressure (2)(psig)Temperature
(°F)Flow gpm (1)Volume (cu.ft.)1Reactor Coolant 2,236.2 (2,236.2)618.3 (601.4)110,871 (109,522)-2Reactor Coolant 2,235.0 (2,235.0)618.3 (601.4)110,875 (109,526)-3Reactor Coolant 2,189.5 (2,188.4)558.2 (539.7)99,310 (99,294)-4Reactor Coolant 2,186.4 (2,185.2)558.2 (539.7)99,315 (99,298)-5Reactor Coolant 2,286.9 (2,288.2)558.5 (540.0)99,200 (99,200)-6Reactor Coolant 2,283.6 (2,284.8)558.5 (540.0)99,205 (99,204)-10-15Reactor CoolantSeeLoop#1Specifications19-24Reactor CoolantSeeLoop#1Specifications28-33Reactor CoolantSeeLoop#1Specifications37Reactor Coolant 2,286.9 (2,288.2)558.5 (540.0)1.0 (1.0)-38Reactor Coolant 2,286.9 (2,288.2)558.5 (540.0)1.0 (1.0)-39Reactor Coolant 2,286.9 (2,288.2)558.5 (540.0)2.0 (2.0)-Rev.13 WOLFCR EE K NOT ESTOFIGUR E5.1-2(Sheet2)ModeASteadyStateFullPowerOperationLocationFluidPressure (2)(psig)Temperature (F)Flow gpm (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-coolant46N 23.01200-47Reactor2,235.0<652.70-coolant48N 23.01200-49N 23.01200-50N 23.0120-45051Pres-3.0120-1,350 surizer relieftank
water52Steam/H 22,235.05590-53Reactor3.01200-coolant54Reactor501700-coolant(1)Attheconditionsspecified.(2)Pressuresreflectnonrecoverablelossesonly(E levationPsarenotincluded)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 safety 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. 29 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
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 50 F 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
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
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, the pressurizer and steam generator manways, which are flanged, and encapsulation clamps at the capped flange on CRDM penetrations 10, 13, 17, 20, 22, 24, 25, 27, 28, 29. In addition, encapsulation clamps are authorized to be installed on any of the remaining CRDM 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. 29 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.
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. 29 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
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 CR EE K TABL E 5.2-1 APPLICABL E COD E ADD E NDA FOR R E ACTOR COOLANT SYST E M COMPON E NTS Reactor vessel ASM E III, 1971 E dition through Winter 1972 Steam generator ASM E III, 1971 E dition through Summer 1973 Pressurizer ASM E III, 1974 E dition CRDM housing ASM E III, 1974 E dition through Winter 1974 CRDM head adapter ASM E III, 1971 E dition 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 E dition Valves Pressurizer safety ASM E III, 1974 E dition through Summer 1975 Motor operated ASM E III, 1974 E dition through Summer 1975 Manual (3 inch and ASM E III, 1974 E dition through Summer 1975 larger)
Control ASM E III, 1974 E dition through Summer 1975
- The 1974 E dition 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
ASM E 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 CR EE K TABL E 5.2-4 R E ACTOR V E SS E L INT E RNALS FOR E M E RG E NCY COR E COOLING SYST E MS Forgings 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 CR EE K TABL E 5.2-5 R E COMM E ND E D R E ACTOR COOLANT WAT E R CH E MISTRY LIMITS (g)E lectrical conductivity Determined by the concentration of boric acid and alkali present.
E xpected range is 1 to 40 mhos/cm at 25°C.
Solution pH Determined by the concentration of boric acid and alkali present.
E xpected 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 NOT E S: (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 CR EE K 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 2 O.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/KgH 2 O 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.
E stablishing 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 EE K TABL E 5.2-6 D E SIGN COMPARISON WITH R E GULATORY GUID E 1.45, DAT E D MAY 1973, TITL E D R E ACTOR COOLANT PR E SSUR E BOUNDARY L E AKAG E D E T E CTION SYST E MS Regulatory Guide 1.45 Position WCGS C. R E GULATORY 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 (S heet 2) Regulato r y Gu i de 1.45 Po si t i on WCG S (2) a irb o r ne pa r t i culate r ad i oact i v i ty mon i to ri ng. Rad i oact i v i ty mon i to ri ng, The th ir d method may b e s elected f r om the conta i nment coole r conden s ate mon i to ri ng, follow i ng: and conta i nment atmo s phe r e hum i d i ty mon i to ri ng. a. mon i to ri ng of conden s ate flow r ate f r om a ir coole rs , b. mon i to ri ng of a irb o r ne ga s eou s r ad i o- act i v i ty. Hum i d i ty, tempe r atu r e, o r p r e ss u r e mon i to ri ng of the conta i nment atmo s phe r e s hould b e con si de r ed a s ala r m s o r i nd ir ect i nd i cat i on of leakage to the conta i nment.4. P r ov isi on s s hould b e made to mon i to r s y s tem s 4. Compl i e s. Refe r to S ect i on s connected to the RCPB fo r si gn s of i nte rs y s tem 5.2.5.2.1, 9.3.3, and 11.5.
leakage. Method s s hould i nclude r ad i oact i v i ty mon i to ri ng and i nd i cato rs to s how a b no r mal wate r level s o r flow i n the affected a r ea. 5. The s en si t i v i ty and r e s pon s e t i me of each 5. Compl i e s , a s de s c rib ed i n S ect i on leakage detect i on s y s tem i n r egulato r y po si t i on 5.2.5.2.3 and a s s hown on F i gu r e 5.2-2. 3. a b ove employed fo r un i dent i f i ed leakage s hould b e adequate to detect a leakage r ate, o r i t s equ i valent, of one gpm i n le ss than one hou
- r. 6. The leakage detect i on s y s tem s s hould b e
- 6. Compl i e s. The a irb o r ne pa r t i culate capa b le of pe r fo r m i ng the ir funct i on s follow i ng r ad i oact i v i ty s y s tem is de si gned to s e is m i c event s that do not r equ ir e plant s hutdown.
r ema i n funct i onal when s u bj ected to the The a irb o r ne pa r t i culate r ad i oact i v i ty mon i to ri ng SS E. Refe r to S ect i on s 11.5.2.3.2.2 and s y s tem s hould r ema i n funct i onal when s u bj ected to 11.5.2.3.2.3. The r ema i n i ng leakage the SS E. detect i on s y s tem s can r ea s ona b ly b e Rev. 20 WOLF CREEK TABLE 5.2-6 (S heet 3) Regulato r y Gu i de 1.45 Po si t i on WCG S e x pected to r ema i n funct i onal follow i ng s e is m i c event s of le ss e r s eve ri ty than the SS E. Howeve r , no s pec i al qual i f i ca- t i on p r og r am is u s ed to a ss u r e ope r a bi l-i ty unde r s uch cond i t i on s. 7. Ind i cato rs and ala r m s fo r each leakage 7. Compl i e s , a s de s c rib ed i n S ect i on s detect i on s y s tem s hould b e p r ov i ded i n the ma i n 5.2.5.2.3 and 5.2.5.5.
cont r ol r oom. P r ocedu r e s fo r conve r t i ng va ri ou s i nd i cat i on s to a common leakage equ i valent s hould b e ava i la b le to the ope r ato rs. The cal ibr at i on of the i nd i cato rs s hould account fo r needed i ndependent va ri a b le s. 8. The leakage detect i on s y s tem s s hould b e
- 8. Compl i e s. Refe r to S ect i on 5.2.5.4.
equ i pped w i th p r ov isi on s to r ead i ly pe r m i t te s t i ng fo r ope r a bi l i ty and cal ibr at i on du ri ng plant ope r at i on. 9. The techn i cal s pec i f i cat i on s s hould include 9. Compl i e s. Refe r to Techn i cal S pec i f i cat i on s. the l i m i t i ng cond i t i on s fo r i dent i f ied and The Conta i nment Atmo s phe r e Pa r t i culate un i dent i f i ed leakage and add r e ss the ava i la bi l i ty Rad i oact i v i ty Mon i to r , Conta i nment S ump of va ri ou s type s of i n s t r ument s to a ss u re adequate Level and Flow Mon i to ri ng S y s tem, and cove r age at all t i me s. the Conta i nment A ir Coole r Conden s ate Mon i to ri ng S y s tem a r e s pec i f i ed i n the L i m i t i ng Cond i t i on s fo r ope r at i on to mon i to r and detect leakage f r om the r eacto r coolant p r e ss u r e b ounda r y. Rev. 20 WOLF CR EE K Table 5.2-7 Bounding Lithium-Boron-Cycle Time for Coordinated pH 7.1-7.2 Primary Coolant Chemistry Burnup, GWd/MTU Cycle Time, efpd Boron, Ppm Lithium, ppm 0 0 1924 3.50 0.922 23.1 1551 3.50 2.583 64.8 1597 3.50 4.244 106.4 1572 3.50 5.906 148.1 1484 3.50 7.567 189.8 1358 3.50 9.228 231.4 1216 3.50 10.889 273.1 1041 3.11 12.551 314.8 879 2.61 14.212 356.4 683 2.05 15.873 398.1 513 1.59 17.534 439.8 345 1.17 19.196 481.4 181 0.78 20.857 523.1 24 0.43 21.400 536.8 10 0.40 Rev. 16
,------:
0 .,.... I v co WOLF CREEK 3'11"+3'11" .,.... 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--8-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 Iron Copper Nickel Cobalt-aluminum (0.15 percent Co)
Cobalt-aluminum (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) Cs 137 U 238 (n,f) Cs 137 In 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 Fe 54 (n,P) Mn 54 reaction is described below. The measurement technique for the other dosimeters, which are sensitive to different portions of the neutron
energy spectrum, is similar.
The Mn 54 product of the Fe 54 (n,P) Mn 54 reaction 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 54 may be performed to ensure freedom from interfering activities. This separation is
simple and very effective, yielding sources of very pure Mn 54 activity. 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 Mn 54 disintegration 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 54 activity in the iron flux monitors may be expressed as: D = N A f E F(1-eJ)ed o i(E)(E)j-t-tj=1 nwhere:
D = induced Mn 54 activity (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)Mn 54 reaction (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, J j = 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) = =
--E TH-E TH SS S E TH EE E 0where:- = effective spectrum average reaction cross-section for neutrons above energy, E TH-E TH = average neutron flux above energy, E TH S (E) = multigroup Fe 54 (n,P)Mn 54 reaction cross-sections compatible with the DOT energy group structure S (E) = multigroup energy spectra at the detector location obtained from the DOT analysis E TH = threshold energy for damage correlation Thus,D = N A F (1-e) e o i--E TH J-J-dj=1 nor, solving for the threshold flux:
-E TH o i-J-t Jj=1 n-t d = D N A f F(1 - e eThe total fluence above energy ETH is given by: E TH-E TH J Jj=1 n = Fwhere F J Jj=1 n 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 54 the 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 U 238 fission detectors with their 30 year half-life product (Cs 137).No burnup correction was made to the measured activities, since burnout of the Mn 54 product is not significant until the thermal flux level is about 10 14 n/cm 2-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 ,Z c)and the flux at the location of peak exposure on the pressure vessel inner diameter is: v-max = (E,R v v-max ,Z v-max) 5.3-11 Rev. 1 WOLF CREEK The lead factor then becomes: LF = cv-max Similar 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 (DORT code), 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. 31 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, niobium, and cobalt-aluminum.
Cadmium shielded fast fission reactions include 238 U and 237 Np 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. 31 WOLF CREEK Material Reaction of
Interest Neutron Energy Response(a)
Product Half-Life
Dosimeter
Capsule Position(b)
Gradient Chain(c)
Copper 63 Cu(n,)60 Co 4.53-11 MeV 5.271 yr 2-Cd No Titanium 46 Ti(n,p) 46Sc 3.70-9.43 MeV 83.79 d 2-Cd No Iron 54 Fe(n,p) 54Mn 2.27-7.54 MeV 312.3 d 1-B & 2-Cd Yes Nickel 58 Ni(n,p) 58Co 1.98-7.51 MeV 70.82 d 2-Cd Yes 238 U (d , e) 238 U(n,f) 137 Cs 1.44-6.69 MeV 30.07 yr 3-Cd No Niobium 93 Nb(n,n 1)93 m Nb 0.95-5.79 MeV 16.13 y 3-Cd No 237 Np (d ,e) 237 Np(n,f) 137 Cs 0.68-5.61 MeV 30.07 yr 3-Cd No Cobalt-Al 59 Co(n,) 60 Co Thermal 5.271 yr 1-B & 2-Cd Yes Notes: a) Energies between which 90% of activity is produced (235 U fission spectrum).
b) B denotes bare and Cd denotes cadmium shielded c) Determined with additional radiochemical analysis
d) For the fission monitors 95 Zr (64.02 d) and 103 Ru (39.26 d) activities are also reported e) Fission monitors have been discontinued and are replaced by niobium.
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. 31 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 (RT NDT).PredictedRT NDT 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 RT NDT 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 RT NDT determined from the surveillance program is greater than the predicted RT NDT. 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 CR EE K TABL E 5.3-1 R E ACTOR V E SS E L 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
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
adapter tube Yes Rev. 0 WOLF CR EE K TABL E 5.3-1 (Sheet 2)
RT* UT*
PT*
MT*
Seal ledge Yes Head lift lugs Yes
Core pad welds Yes
PT - Dye Penetrant
MT - Magnetic Particle NOT E: 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 CR EE K TABL E 5.3-2 R E ACTOR V E SS E L D E SIGN PARAM E T E RS Design/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 CR EE K TABL E 5.3-3 R E ACTOR V E SS E L MAT E RIAL PROP E RTI E S Avg. Upper Shelf MAT E RIAL Cu P TNDT RTNDT NMWD
- MWD*COMPON E NT COD E NO. SP E C. 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 E 3.16 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 5.3-6 Deleted 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 NOTES 1. 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 TABL E 5.3-11 R E ACTOR V E SS E L MAT E RIAL SURV E ILLANC E PROGRAM - WITHDRAWAL SCH E DUL E CAPSUL E V E SS E L L E AD NUMB E R LOCATION FACTOR WITHDRAWAL TIM E U 58.5° 4.25 1.07 E FPY (b) Y 241° 3.93 4.79 E FPY (b) V 61° 4.02 9.78 E FPY (b) X 238.5° 4.30 13.83 E FPY (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.
NOT E: 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
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-
ft 2-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, tubes that are unsupported by an anti-vibration bar (AVB) and contrary to design requirements, or tubes that are subject to significant flow peaking due to non-uniform insertion of the AVBs, were evaluated to determine if they are subject to possible fatigue failure during the lifetime of the steam generators. The analysis methodology is the same as the methodology used to satisfy the analysis requirements of NRC Bulletin 88-
- 02. The analysis is described in WCAP-17990-P, "Wolf Creek U-Bend Vibration and Fatigue Assessment." Seventeen tubes were identified in the analysis that may be subject to fatigue failure based on the pinned and non-occuluded case.
These 17 tubes were all plugged (removed from service) during Refuel 20. All other tubes were shown to be acceptable for a 60 year operating lifetime of Wolf Creek (40 years, plus period of extended operation).
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. 29 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
- 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
- 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, T COLD) 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 350 F 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 350 F to 225 F 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 90 F, 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
<140 F). This cooldown rate is based on throttling RHR flow, as necessary, to maintain a maximum 120 F component cooling water to the shell side of the RHR heat exchangers and to limit the RCS cooldown rate to a maximum of 50 F/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
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
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 350 F followed by the other train of RHR at 225 F. 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 350 F and at 225 F 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 225 F) 2 (225 to 140 F) 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
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 S IGN PARAMETER S Un i t de si gn p r e ss u r e, p si g 2,4 8 5 Un i t de si gn tempe r atu r e, F 6 50 (a) Un i t ove r all he ight, ft 2 6.93 S eal wate r i n j ect i on, gpm 8 S eal wate r r etu rn, gpm 3 Cool i ng wate r flow, gpm 3 66 Ma xi mum cont i nuou s cool i ng wate r i nlet tempe r atu r e 105 Pump Capac ity, gpm 100, 6 00 Developed head, ft 2 88 NP S H r equ ired, ft F i gu r e 5.4-2 S uct i on tempe r atu re, F 55 8.2 Pump d is cha r ge nozzle, i n si de d i amete r , i n. 27-1/2 Pump s uct i on nozzle, i n si de d i amete r , i n. 31 S peed, r pm 1,1 8 5 Wate r volume (ca si ng), ft 3 7 8.6 *We i ght total (i nclud ing 204,035 (w i th b olt s) pump ca si ng, moto r, and 205, 6 9 6 (w i th s tud s) moto r s uppo r t s), d r y, l b Moto r Type D ri p p r oof, s qu irr el cage i nduct i on, wate r/a ir cooled Powe r, hp 7,000 V oltage, V olt s 13,200 Pha se 3 F requency, Hz 6 0 In s ulat i on cla ss Cla ss F, the r mala s t i c epo x y i n s ulat i on (a) De si gn tempe r atu r e of p r e ss u r e-r eta i n i ng pa r t s of the pump a ss em b ly e x po s ed to the r eacto r coolant and i n j ect i on wate r on the h i gh p r e ss u r e si de of the cont r olled leakage s eal is a ss umed to b e the tempe r atu r e dete r m i ned fo r the pa r t s fo r a p ri ma r y loop tempe r atu r e of 6 50°F. *Total pump we i ght s b etween value s s hown a r e b ounded b y e xis t i ng analy s e s. Rev. 17 WOLF CREEK TABLE 5.4-1 (S heet 2) S ta r t i ng Cu rrent 1,750 amp @ 13,200 V olt s Input, hot r eacto r coolant 253 + 5 amp Input, cold r eacto r coolant 33 6 + 7 amp Pump moment of i ne r t i a, ma xi mum (l b-ft2) Flywheel 6 4,000 Shaft 745 Impelle r 1,9 8 0 Roto r co re 27,700 Runne r 6 75 Coupl ing 190 Rev. 0 WOLF CR EE K TABL E 5.4-2 R E ACTOR 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 CR EE K TABL E 5.4-3 ST E AM G E N E RATOR D E SIGN 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 6 Nominal 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 CR EE K TABL E 5.4-4 ST E AM G E N E RATOR QUALITY ASSURANC E PROGRAM (a) (a) (a) (a) (a)
RT UT PT MT E T Tube 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 CR EE K TABL E 5.4-4 (Sheet 2)
(a) (a) (a) (a) (a)
RT UT PT MT E T Instrument 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
E T - E ddy Current (b) Flat surfaces only (c) Weld deposit (d) Base material only Rev. 0 WOLFCR EE K TABL E 5.4-5 R EACTORCOOLANTPIPINGD ESIGNPARAM E T E RSReactorinletpiping,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,ft 3 1,225ReactorCoolantLoopPipingDesign/operatingpressure,psig2,485/2,235Designtemperature,F650PressurizerSurgeLineDesignpressure,psig2,485 Designtemperature,F680PressurizerSafetyValveInletLineDesignpressure,psig2,485 Designtemperature,F680Pressurizer(Power-Operated)ReliefValveInletLineDesignpressure,psig2,485 Designtemperature,F680Rev.0 WOLF CR EE K TABL E 5.4-6 R E ACTOR 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)
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 CR EE K TABL E 5.4-9 (Sheet 1 of 5)
FAILUR E MOD E S AND E FF E CTS ANALYSIS - R E SIDUAL H E AT R E MOVAL SYST E M ACTIV E COMPON E NTS - PLANT COOLDOWN OP E RATION Component Failure Mode E ffect 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 CR EE K TABL E 5.4-9 (Sheet 2 of 5)
Component Failure Mode E ffect 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 E CCS. Pumps analogous) "A" of RHRS. Fault reduces close position monitor are tested as
redundancy of RHR coolant light for group monitoring part of the E CCS 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 E CCS 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 E CCS oper-ation. CB switch set to "Auto" Rev. 16 WOLF CR EE K TABL E 5.4-9 (Sheet 3 of 5)
Component Failure Mode E ffect 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 E CCS 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 CR EE K TABL E 5.4-9 (Sheet 4 of 5)
Component Failure Mode E ffect 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.
E CCS 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 E CCS 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
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 CR EE K TABL E 5.4-9 (Sheet 5 of 5)
Component Failure Mode E ffect 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 E CCS 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 E CCS 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
E CCS - E mergency core cooling system RC - Reactor coolant
RHRS - Residual heat removal system
RWST - Refueling water storage tank
Rev.
0 WOLF CR EE K TABL E 5.4-10 PR E SSURIZ E R D E SIGN 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 CR EE K 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 CR EE K TABL E 5.4-12 PR E SSURIZ E R QUALITY ASSURANC E PROGRAM (a) (a) (a) (a)
RT UT PT MT Heads 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 E T (E ddy Current)(c) MT or PT Rev. 0 WOLF CR EE K TABL E 5.4-13 PR E SSURIZ E R R E LI E F TANK D E SIGN 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 CR EE K TABL E 5.4-14 R E LI E F VALV E DISCHARG E TO TH E PR E SSURIZ E R R E LI E F TANK Reactor 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 CR EE K TABL E 5.4-15 R E ACTOR COOLANT SYST E M VALV E D E SIGN PARAM E T E RS Design/normal operating pressure, psig 2,485/2,235 Preoperational plant hydrotest, psig 3,107
Design temperature, F 650 Rev. 0 WOLF CR EE K TABL E 5.4-16 R E ACTOR COOLANT SYST E M VALV E S NOND E STRUCTIV E E XAMINATION PROGRAM (a) (a) (a)
RT UT PT Boundary 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) E ither RT or UT Rev. 0 WOLF CR EE K TABL E 5.4-17 PR E SSURIZ E R VALV E S D E SIGN PARAM E T E RS 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
E xpected during discharge, psig 500 E nvironmental 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 350 F to 225 F. At 225 F 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
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 350 F to 225 F
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 120 140 160 180 200 220 240 260 280 300 320 340 360 38012344.555.566.577.588.599.59.71010.410.911.411.912.412.913.413.914.414.915.415.916.416.917.417.9Time 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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