ML17157B679

Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 5, Reactor Coolant System and Connected Systems

ML17157B679
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Site:	Duane Arnold
Issue date:	05/22/2017
From:	NextEra Energy Duane Arnold
To:	Office of Nuclear Reactor Regulation
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ML17157B650	List: ML17157B649 ML17157B674 ML17157B675 ML17157B677 ML17157B678 ML17157B679 ML17157B680 ML17157B681 ML17157B682 ML17157B683 ML17157B684 ML17157B685 ML17157B686 ML17157B687 ML17157B688 ML17157B689 ML17157B690 ML17157B691 ML17157B692 NG-17-0086, Transmittal of Revision 24 of the DAEC Updated Final Safety Analysis Report and the Current DAEC Technical Specifications Bases NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 1, Introduction and General Description of Plant NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 10, Steam and Power Conversion NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 11, Radioactive Waste Management NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 12, Radiation Protection NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 13, Conduct of Operations NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 14, Initial Test Program NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 15, Accident Analyses NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 16, Technical Specifications NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 17, Quality Assurance NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 3, Design of Structures, Components, Equipment, and Systems NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 4, Reactor NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 5, Reactor Coolant System and Connected Systems NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 6, Engineered Safety Features NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 7, Instrumentation and Controls NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 8, Electric Power NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 9, Auxiliary Systems NG-17-0111, Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Table of Contents NG-17-0111, Redacted - Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 2, Site Characteristics
References
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UFSAR/DAEC - 1 5.1-1 Revision 13 - 5/97 CHAPTER 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.1

SUMMARY

DESCRIPTION

This chapter describes those systems and components that form the major portions of the nuclear system process barrier. These systems and components contain or transport the fluids coming from or going to the reactor core.

Section 5.3 describes the reactor vessel and the various fittings with which other systems are connected to the vessel. The major safety considerations for the reactor vessel are concerned with the ability of the vessel to function as a radioactive material barrier. Various combinations of loading are considered in the vessel design. The vessel meets the requirements of various applicable codes and criteria. To reduce the probability of the fracture of any component or piping in the reactor coolant pressure

boundary that could initiate a loss-of-coolant accident (LOCA), provisions to prevent

brittle fracture are applied over the entire boundary.

The reactor recirculation system pumps coolant through the core. The adjustment

of the core coolant flow rate changes reactor power output, thus providing a means of following plant load demand without adjusting control rods. The recirculation system is designed with sufficient fluid and pump inertia so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The arrangement of the recirculation system is designed so that a piping failure cannot compromise the integrity of the floodable inner volume of the reactor vessel.

The nuclear system pressure relief system is designed to protect the nuclear system process barrier from damage due to overpressure. To accomplish overpressure

protection, six pressure-operated relief valves are provided to discharge steam from the nuclear system to the primary containment. The nuclear system pressure relief system also acts to automatically depressureize the nuclear system in the event of a LOCA in which the high-pressure coolant injection (HPCI) system fails to deliver rated flow. The depressurization of the nuclear system in this situation allows low-pressure emergency core cooling systems to supply enough cooling water to adequately cool the fuel. Only some of the pressure relief valves used for overpressure protection are arranged to effect automatic depressurization.

The main steam line flow restrictors are ve nture-type flow devices. One restrictor is installed in each main steam line close to the reactor vessel but downstream from the pressure relief and safety valves. The restrictors are designed to limit the loss of coolant resulting from a main steam line break outside the primary containment.

UFSAR/DAEC - 1 5.1-2 Revision 17 - 10/03 Two main steam line isolation valves are installed on each main steam line. One valve on each line is inside the primary containment, the other outside. These vales act automatically to close off the nuclear system process barrier in the event a pipe break occurs downstream of the valves. This action limits the loss of coolant and the release of radioactive materials from the nuclear system. In the event that a main steam line break occurs inside the primary containment, the closure of the isolation valve outside the containment acts to seal the primary containment itself.

The reactor core isolation cooling (RCIC) system includes a turbine-pump driven by reactor vessel steam. Under certain conditions, the system automatically starts in time to prevent conditions requiring the operation of any of the emergency core cooling systems. The system provides the ability to cool the core during a reactor isolation in

which feedwater flow is not available.

The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can cool the nuclear system under a variety of situations. During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows the removal of decay heat whenever the main heat sink (main condenser) is not available. One operational mode of the RHR system is low-pressure

coolant injection (LPCI). LPCI operation is an engineered safeguard for use during a LOCA; this operation is described in Section 6.3. Another mode of RHR system operation allows the removal of heat from the primary containment following a LOCA (Section 6.2.2).

The reactor water cleanup (RWCU) system functions to maintain the required purity of reactor coolant by circulating coolant through a system of filters and demineralizers.

Section 5.2.5 discusses the detection of leakage through the reactor coolant pressure boundary. Limits on nuclear system leakage inside the primary containment are established so that appropriate action can be taken before the nuclear system process

barrier is threatened by a crack large enough to propagate rapidly.

Figure 5.1-1, Sheets 1 and 2, are piping and instrumentation diagrams of the reactor coolant system.

UFSAR/DAEC - 1 5.2-1 Revision 22 - 5/13

5.2 INTEGRITY

OF REACTOR COOLANT PRESSURE BOUNDARY

The classifications of components and systems that comprise the reactor coolant pressure boundary are given in Section 3.2. ASME Boiler and Pressure Vessel (B&PV) Code compliance

is also given in Section 3.2.

The fracture or notch toughness properties and the operating temperature of ferritic materials of the reactor coolant pressure boundary are controlled to ensure adequate toughness when the system is pressurized to more than 20% of the design pressure. Such assurance is provided by maintaining a material service temperature at least 60°F above the nil-ductility transition (NDT) temperature. Further interpretations and requirements are as follows:

1. Charpy V-notch tests are performed to demonstrate that the material meets the minimum impact test temperature. Test specimens are prepared and tested in

accordance with the general provisions of N331 and N332 of Section III of the ASME Code. The test temperature is 60°F below the minimum service temperature at which 20% of design pressure can be applied for each pipeline or pressure component.

2. Piping and equipment having a nominal wall thickness of 0.5 in. or less are not tested provided that the material is normalized or has been fabricated to fine-grain-melting practice or is made of austenitic stainless steel.

3. Impact testing is required on components or piping within the boundary having a service temperature of 250°F or less.

4. Impact testing is not required on components or piping within the boundary whose rupture could not result in a loss of coolant exceeding the capability of normal makeup systems to maintain adequate core cooling for the duration of a

reactor shutdown and orderly cooldown.

5. Field welds and shop welds in material 0.5 in. thick or less are normalized unless the welding procedure has been qualified by impact testing in accordance with item 1 above.

6. These criteria apply to piping and equipment of the reactor coolant pressure boundary and do not apply to related components such as anchors, anchor bolts, hangers, suppressors, and restraints.

5.2.1 COMPLIANCE

WITH CODES AND CODE CASES

5.2.1.1 Compliance with 10 CFR 50.55a UFSAR/DAEC - 1 5.2-2 Revision 22 - 5/13 Inservice inspection of Class 1 components is performed in accordance with the Inservice Inspection Plan. Inservice testing of Class 1 pumps and valves is performed in accordance with the Inservice Testing Program.

5.2.2 OVERPRESSURIZATION

PROTECTION

5.2.2.1 Design Bases

To design the pressure protection for the nuclear boiler system, extensive analytical computer models, representing all essential dynamic characteristics of the system, are used..

These models include the hydrodynamics of the flow loop, the reactor kinetics, the thermal

characteristics of the fuel and its transfer of heat to the coolant, and all the principal controller features such as feedwater flow, recirculation flow, reactor water level, pressure, and load demand. These are represented with all their principal nonlinear features in models that have evolved through extensive experience and favorable comparison of analysis with actual BWR

test data.

Included in this model are components of the reactor vessel overpressure protection system. Dual safety/relief valves and spring safety valves are simulated in a nonlinear representation. The model thereby allows full investigation of the various valve characteristics:

response time, valve capacity, and actuation setpoint. Typical capacity characteristics as modeled are represented in Figures 5.2-1 and 5.2-2 for both the safety/relief valve and the spring safety valve types. The associated bypass valve, turbine control valve, and main steam isolation valve characteristics are also represented fully in the model.

Safety/relief valve setpoints and minimum design capacities are selected, based on operational transients. The safety/relief valve nominal setpoints and design capacities as modeled are given in Table 5.2-1.

The high-pressure setpoint of the spring safety valves is tied directly to the design overpressure limit allowed by the code. The spring safety valve nominal setpoint is 1240 psig, which is less than the 1250 psig vessel design pressure.

The design task is to establish the minimum high-pressure safety valve capacity to satisfy

the design criteria. In the case of the dual-purpose safety/relief valves, the valves qualify as

safety valves at setpoints coincident with the relief setpoints.

5.2.2.2 Design Evaluation

See Appendix 5B.

5.2.2.2.1 Power Uprate Overpressure Protection Evaluation

The closure of all main steam isolation valves with flux scram is evaluated as part of the reload licensing analyses for each operating cycle to determine the adequacy of the nuclear UFSAR/DAEC - 1 5.2-3 Revision 22 - 5/13 system overpressure protection system. This was chosen as the limiting isolation event. The code safety and the safety/relief valve set points were as indicated in Table 5.2-1. All safety/relief valves were assumed to be in service. The summary of the results of the analysis is

presented in Section 15.1.2.3.2.

Generic studies show that a maximum pressure increase of 20 psi would result for a main steam isolation valve closure event with a single safety/relief valve failing to open. Therefore, for a single safety/relief valve failure the maximum pressure at the bottom of the vessel would still have margin to the ASME vessel code limit.

5.2.2.3 Piping and Instrumentation Diagrams

See Figure 5.1-1.

5.2.2.4 Equipment and Component Data

5.2.2.4.1 Safety Valves

There are two Dresser Maxiflow safety valves located on the main steam lines within the

drywell between the reactor vessel and the first isolation valve. They are spring loaded, flat

seated, reaction type. The inlet connections ar e 6-in., 1500-lb special-facing flanges. The outlet connections are 8-in., 150-lb raised-face flanges per ANSI B16.5. The set pressure and capacity

are given in Table 5.2-1.

5.2.2.4.2 Safety/Relief Valves

There are six Target Rock safety/relief valves, all of which are located on the main steam

lines within the drywell between the reactor vessel and the first isolation valve.

The inlet connections for the Target Rock safety/relief valves are 6-in., 1500-lb special-

facing flanges. The outlet connections are 10-in., 300-lb raised-face flanges per ANSI B16.5.

The safety/relief valves are designed, constructed, and marked as described in Section 5.4.13.

Each safety/relief valve consists of three main sections. The pilot valve section is a relatively small, self-actuated relief valve, integral with the main valve, which provides pressure sensing and main valve control functions. The main element of this pilot valve is a precision-machined spring bellows, the expansion of which accurately controls the main valve. It is actuated by externally supplied nitrogen pressure to a diaphragm. The main valve section is a

hydraulically operated, reverse-seating globe valve which, when actuated by the pilot valve, provides the pressure relief function by opening to discharge nuclear system steam to the

suppression pool.

A typical sequence of operation for overpressure relief self-actuation can be described as

follows (refer to Figures 5.2-9 and 5.2-10):

UFSAR/DAEC - 1 5.2-4 Revision 22 - 5/13 1. In the closed position (Figure 5.2-9), the bellows is mechanically extended a slight amount by the preload spacer to provide a preload force on the pilot disk.

This seats the pilot valve tightly and prevents reverse leakage by low system pressures or high backpressures. The main valve disk is tightly seated by the combined forces exerted by the main valve preload spring and the system internal pressure acting over the area of the main valve disk. In the closed position, the static pressures will be equal in the valve body and in the chamber over the main valve piston. This pressure equalization is made possible by leakage through the

piston orifice.

2. As system pressure increases, the preload force on the pilot disk is reduced to zero as the bellows is extended farther and the disk is held closed by the internal

pressure acting over the pilot valve seat area. This hydraulic seating force, which is significantly greater than the initial preload, increases with increasing system pressure and discourages leakage or "simmering" at pressures near the valve set

pressure.

3. As system pressure further increases, bellows expansion reduces the abutment gap between the stem and the disk yoke. When the stem abuts against the yoke, further pressure increase reduces the net pilot seating force to zero and lifts the first-stage pilot valve from its seat.

4. Once the pilot valve starts to open, the hydraulic seating force is eliminated, resulting in a net increase in the force tending to open the pilot valve. This

increase in net force produces the "popping" action during pilot valve opening (Figure 5.2-10).

5. The opening of the first-stage pilot valve admits fluid to the operating piston of the second-stage valve, causing it also to open.

6. The opening of the second-stage pilot valve vents the chamber over the main valve piston to the downstream side of the valve. This venting action creates a differential pressure across the main valve piston almost equal to the system pressure and in a direction tending to open the valve. The main valve piston is sized so that the resulting opening force is greater than the combined preload and hydraulic seating force. Therefore, opening the pilot opens the main valve.

7. As in the case of the pilot valve, once the main valve disk starts to open, the hydraulic seating force is reduced, causing a significant increase in opening force

and the characteristic full-opening or "popping" action.

8. When the pressure has been reduced sufficiently to permit the pilot valve to close, the leakage of system fluid past the main valve piston repressurizes the chamber over the piston, eliminates the hydraulic opening force, and permits the preload

spring to close the valve. Once closed, the additional hydraulic seating force due UFSAR/DAEC - 1 5.2-5 Revision 22 - 5/13 to system pressure acting on the main valve disk seats the main valve tightly and prevents leakage.

The nitrogen-powered diaphragm-operated valve also displaces the second-stage piston, which in turn controls the main valve as shown in Figures 5.2-9 and 5.2-10. Using this system, the relief valve can be remotely opened by supplying pressure on the diaphragm of this actuator.

The relief valves are installed so that each valve discharge is piped through its own uniform diameter discharge line to a point below the minimum water level in the primary containment suppression pool to permit the steam to condense in the pool. Water in the line

above suppression pool water level would cause excessive pressure at the relief valve discharge when the valve again opened. For this reason, a vacuum relief valve is provided on each relief valve discharge line to prevent drawing water up into the line from steam condensation following the termination of relief valve operation.

Four of the six relief valves are used for automatic depressurization and are equipped with a nitrogen accumulator and check valve arrangement. These accumulators are provided to

ensure that the valves can be held open following the failure of the nitrogen supply to the accumulators, and they are sized to contain sufficient nitrogen for a minimum of five valve

operations over a 100-day period following a design-basis LOCA. See Section 6.3.2.2.2. The two non-automatic depressurization system relief valves are also each connected to one of the automatic depressurization system nitrogen accumulators such that all six relief valves have a Seismic Category I Safety Class 2 nitrogen supply. The two non-automatic depressurization system relief valves are so configured to operate automatically in the low-low set mode (Section

5.4.13.2).

The automatic depressurization feature of the nuclear system pressure relief system serves as a backup to the HPCI system under LOCA conditions. If the HPCI system does not operate and one of the LPCI or core spray pumps is running, the nuclear system is depressurized sufficiently to permit the LPCI and core spray systems to operate to protect the fuel barrier.

Depressurization is accomplished through automatic opening of some of the relief valves to vent steam to the suppression pool. For small-line breaks when the HPCI system fails, the nuclear system is depressurized in sufficient time to allow the core spray or LPCI systems to provide core cooling to prevent any fuel cladding melting. For large breaks, the vessel depressurizes rapidly through the break without assistance. The signal for the relief valves to open and remain open is based on simultaneous signals from (1) reactor vessel low water level, and (2) one core spray or LPCI pump running, after a 2 minute timer expires.

A manual depressurization of the nuclear system can be effected in the event the main condenser is not available as a heat sink after reactor shutdown. The steam generated by core decay heat is discharged to the suppression pool. The relief valves are operated by remote manual controls from the main control room to control nuclear system pressure.

The number, set pressures, and capacities of the relief valves and safety valves are shown

in Table 5.2-1.

UFSAR/DAEC - 1 5.2-6 Revision 22 - 5/13 5.2.2.5 Mounting of Pressure Relief Devices The inlet and connections are described in Section 5.2.2.4.1 for the Dresser safety valves

and in Section 5.2.2.4.2 for the Target Rock safety/relief valves.

5.2.2.6 Applicable Codes and Classification

The spring safety and the safety/relief valves have been designed, constructed, and marked in accordance with ASME Code, Section III, 1968 Edition, Article 9 (with 1969 Summer Addenda for the spring safety valves and with 1968 Winter Addenda for the safety/relief valves) for the following operating conditions:

1. Fluid: steam with less than 1% moisture.

2. Pressure: 0 to 1020 psig.

3. Ambient temperature: 135°F normal, 150°F maximum.

5.2.2.7 Material Specification

Material specifications are discussed in Section 5.4.13.

5.2.2.8 Process Instrumentation

See Figure 5.1-1.

5.2.2.9 System Reliability

As stated in Appendix 5B, various combinations of proper valve operation provide adequate vessel overpressure protection subsequent to the severe main steam isolation valve closure transient assuming a scram initiated by high neutron flux or high vessel pressure. Table 5.2-2 summarizes the safety valve scram system availability that has been calculated on the basis of the combination of valves required to provide a minimum of a 25-psi margin below the ASME Code limit of 1375 psig. The availability of flux scram is greater than 0.99999, while with pressure scram it is 0.9993 for an interval between tests of 2 yr when the system has six

safety/relief valves and two spring safety valves.

A failure-to-open rate of 1.1 failures per million operating hours was assigned to the dual-purpose safety/relief valves, and a failure-to-open rate of 0.01 failure per million operating hours was assigned to the spring safety valves. The downtime, or period that the valve would be unavailable for service if it failed, was determined to be dominated by the period between testing.

The effects of these differences in downtime were included in the availability calculations.

UFSAR/DAEC - 1 5.2-7 Revision 22 - 5/13 General Electric availability goals applied to the DAEC over-pressure protection system require that a minimum availability of 0.99999 be provided for the flux scram condition as well as capability for success with scram initiation emanating from pressure. These goals have been

applied to the results of this analysis, and sin ce the availability of all cases exceeds these goals, the probability of successful pressure protection is ensured.

5.2.2.10 Testing and Inspection

The base castings of each valve have been 100% radiographed in accordance with ASTM

Standards E71, E94, E142, E186, and E280.

All pressure-containing bolting has been magnetic particle examined in accordance with

ASTM E138.

Capacity certification tests have been conducted in accordance with Article 9,Section III

of the ASME Code. Valves were tested before installation and are bench checked periodically

during plant shutdown for the proper setpoint in accordance with the ASME Code and Technical Specification requirements.

5.2.3 REACTOR

COOLANT PRESSURE BOUNDARY MATERIALS

5.2.3.1 Material Specifications

A review of reactor coolant system pressure boundary piping was completed in 1978 to determine if ASME Class 1 and 2 pressure boundary piping, safe ends, and fitting material, including weld metal, met the material selection, testing, and processing guidelines set forth in

NUREG-0313, Revision 1, "Technical Report on Materi al Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping." The detailed results of the review are contained in

References 2 and 3.

In general, the results of the NUREG-0313 conformance review were as follows:

1. Conforming material. All stainless steel safe ends and stainless steel safe-end extensions are conforming material. All contain less than 0.035% carbon and

were solution annealed. Inconel welds join the stainless steel safe ends to the nozzles. Class 1 pressure boundary piping except that identified below in items 2 and 3 are conforming, and all Class 2 piping is conforming.

2. Partial nonconformance but not service sensitive. The following systems are nonconforming and nonservice sensitive in accordance with the guidelines of

NUREG-0313, Revision 1.

a. Recirculation system except the bypass pipe.

b. RHR stainless steel transition spools to the recirculation system.

UFSAR/DAEC - 1 5.2-8 Revision 22 - 5/13 c. Liquid level control (reactor vessel).

d. Instrumentation piping (reactor vessel).

Stainless steel pipe and fittings in the above systems contain greater than 0.035%

carbon, and the welds have not been solution annealed; therefore, they are nonconforming. All pipe and fittings have been solution annealed. The selection of welds for augmented inservice inspection on item "a" and "b" systems will be those most susceptible for intergranular stress-assisted corrosion cracking based on the stress rule index number.

3. Partial nonconformance and service sensitive. The following do not conform to the criteria as stated in NUREG-0313, Revision 1, and are considered to be

service sensitive:

a. Recirculation system bypass.

b. Core spray spools that connect carbon steel pipe to stainless steel safe-end extensions at the reactor pressure vessel nozzles.

c. CRD hydraulic return spool that connects carbon steel pipe to the reactor pressure vessel nozzle.

d. RWCU systems.

The stainless steel pipe and fittings in the above systems contain greater than

0.035% carbon, and the welds have not been solution annealed. All pipe and fittings have been solution annealed. Augmented inservice inspection has been done on the above systems in accordance with the guidelines of NUREG-0313, Revision 1.

The only components within the DAEC reactor coolant pressure boundary fabricated outside the United States were the RHR and core spray pumps by Byron Jackson-Canada (Canadian-B.J.). The pumps were purchased from Byron Jackson-United States (U.S.-B.J.) and

designed within the United States. The fabricati on was done by Canadian-B.J. to fabrication and quality control instructions and procedures issued by U.S.-B.J. Canadian-B.J. was fully qualified to fabricate RHR and core spray pumps with adequate machining, handling, and welding equipment. Canadian-B.J. had qualified fabrication and quality control organizations. U.S.-B.J.

was responsible for ensuring and documenting the required quality level. RHR and core spray pumps for other nuclear power plants have been fabricated by Canadian-B.J.

UFSAR/DAEC - 1 5.2-9 Revision 22 - 5/13 5.2.3.2 Compatibility with Reactor Coolant The recirculation system piping, valves, and pump casings are covered with thermal insulation having an average maximum heat-transfer transfer rate of 65 Btu/hr-ft 2 with the system at rated operating conditions. Most of the insulation is of the fiberglass type with a metal jacket and is prefabricated into components for field installation. Removable insulation is provided at various locations to allow periodic inspection of the insulated equipment.

5.2.3.3 Fabrication and Processing of Ferritic Materials

The fracture or notch toughness properties and the operating temperature of ferritic materials in systems that form the reactor coolant and primary containment pressure boundaries are controlled to ensure adequate toughness when the system is pressurized to more than 20% of the design pressure. Such assurance is provided by maintaining a material service temperature of at least 60°F above the NDT temperature for the reactor coolant pressure boundary and 30°F above the NDT temperature for the primary containment boundary. Where reactor coolant pressure boundary piping penetrates the containment, the fracture toughness temperature requirements of the reactor coolant pressure boundary materials apply. Materials to be impact tested shall be tested by the Charpy V-notch method in accordance with ASME Code,Section III.

Other requirements are as follows:

1. Reactor coolant pressure boundary. Impact testing is not required on materials having a minimum service temperature of 250°F when pressurized at more than

20% of design pressure.

Impact tests are not required for bolting, including nuts whose nominal bolt size is 1-in. in diameter or less; bars whose cross-sectional area does not exceed 1 square inch; materials whose section thickness is less than 0.5 in.; piping, valves, and pumps whose nominal inlet pipe is 6 in. in diameter and less, regardless of thickness; austenitic stainless steels; and nonferrous materials.

Charpy V-notch specimens are in accordance with ASTM A-370, Figure 11, Type A; the specimens are also tested in accordance with A-370.

Impact testing is not required on components or piping within the pressure

boundary whose rupture could not result in a loss of coolant exceeding the capability of normal makeup systems to maintain adequate core cooling for the

duration of a reactor shutdown and orderly cooldown.

Impact test criteria do not apply to non-pressure-retaining components such as

anchors, anchor bolts, hangers, suppressors, and restraints.

2. Extension of Containment Pressure Boundary

The containment boundary extends to and includes the first stop or stop check UFSAR/DAEC - 1 5.2-10 Revision 22 - 5/13 valve outside containment. Impact testing is not required for materials where the nominal pipe size is 4 in. or less (6 in. or less after July 1, 1971) or where the

section thickness is 0.5 in. or less.

The design specification states the test temperature at which the material shall meet the impact test values listed in Tables A.1, A.2, and A.8 of ASME Code,Section III.

5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel All sensitized austenitic stainless steel has been replaced on the DAEC pressure vessel, except for the jet pump riser brace pads and recirculation inlet thermal sleeve attachment buildups. These exceptions are fabricated from weld metal with controlled ferrite content.

Austenitic stainless steel used in other component parts of the reactor coolant pressure boundary including relief and safety valves is fully annealed to preclude sensitization.

Stainless steel with deliberate additions of nitrogen for enhancing the material strength has not been used.

All high points on nonflowing parts of the reactor coolant system have been vented to prevent gas entrapment.

None of the component materials of the reactor coolant pressure boundary or emergency core cooling system (ECCS), except as noted above, and none of the component materials of the systems required for reactor shutdown are furnace sensitized and, therefore, they are not

susceptible to intergranular attack.

For a few reactor internals that are not water quenched, the following procedure was

used.

For the acceptable qualification of a process other than water quenching, thermocouples were used on test coupons to verify the cooling rate from 1800 to 800°F. The test coupons or demonstration samples are of the maximum thickness of the processed material. The demonstration samples were examined metallographically and accepted on the basis of conformance to well-documented solution-heat-treated microstructures.

Filler metals, including consumable inserts, for austenitic stainless steel welds and weld overlays were selected and controlled to produce welds that contain a measurable amount of ferrite. Magnetic methods were used to test for ferrite in each completed production weld.

Welders and welding procedures were qualified in accordance with ASME Code,Section IX, and in the case of some reactor internals, qualifications were done per engineering-approved alternatives to Section IX (Section 3.3.4).

Welding processes are limited to 110,000 J/in., and the interpass temperature is limited to

350°F to avoid local sensitization of stainless steel.

UFSAR/DAEC - 1 5.2-11 Revision 22 - 5/13 Reference 4 prescribes practices and requirements for the manual and automatic welding of austenitic stainless steel piping using heat sink techniques during welding. Heat sink welding is defined as the practice of water cooling a weld joint during metal deposition, as described in

the specification. It is applicable for both shop and field welds.

5.2.3.5 Intergranular Stress Corrosion Cracking

During the 1985 refueling outage, a comprehensive program addressing intergranular

stress corrosion cracking (IGSCC) in the reactor coolant recirculation system was implemented.

The program included induction heating stress improvement (IHSI) of welds in the recirculation system large diameter piping (10 in. or greater). As a result of ultrasonic inspections performed before and after IHSI, 11 code reportable indications were found in the recirculation system welds. Ten welds had repor table IGSCC-like indications. One weld had an indication not associated with IGSCC. The 11 welds were repaired by full structural weld overlays.5 IGSCC is controlled by a hydrogen water chemistry (HWC) system, described in Section

9.3.5, which injects hydrogen into the feedwater. The hydrogen is carried into the reactor, where

it reduces the concentration of dissolved oxygen in the reactor coolant. To enhance the effectiveness and efficiency of HWC in mitigating IGSCC in the reactor vessel internals, noble metal is injected as described in Section 9.3.7.

To satisfy the requirements of NRC Generic Letter 88-01, an augmented IGSCC examination program is in effect for austenitic stainless piping welds.

5.2.3.5.1 Mechanical Stress Improvement Process (MSIP)

During RFO 22 (Fall 2010), RRE-F002, RRG-F002, and RRH-F002 nozzle to safe-end welds underwent the Mechanical Stress Improvement Process. The recirculation inlet piping was compressed near the nozzle to safe end weld, removing the tensile stresses and creating favorable compressive stresses at the weldment. This process was performed on N2E, N2G and N2H. MSIP is a patented design process that mitigates cracks caused by IGSCC and prevents new cracks from forming.

5.2.4 INSERVICE

INSPECTION AND TESTING OF REACTOR COOLANT PRESSURE BOUNDARY 5.2.4.1 Introduction

A preservice inspection of Nuclear Class 1 components was conducted to ensure freedom from defects greater than code allowance; in addition, this served as a reference base for future inspections. Prior to operation, the reactor coolant system as described in Article IS-120 of UFSAR/DAEC - 1 5.2-12 Revision 22 - 5/13 Section XI of the ASME Code was inspected to ensure that the system was free of gross defects.

In addition, the facility was designed such that gross defects should not occur throughout the life of the plant. The preservice inspection program was based on the 1971 Section XI of the ASME Code for inservice inspection. This inspection plan was designed to reveal problem areas (should they occur) before a leak in the coolant system could develop. The program was

established to provide reasonable assurance that no LOCA would occur at the DAEC as a result

of leakage or breach of pressure-containing components and piping of the reactor coolant system, portions of the emergency core cooling systems, and portions of the auxiliary systems-associated with the reactor coolant system.

The engineering and design effort associated with the DAEC predates the availability of

the ASME Inspection Code. However, this code, including subsequent Addenda through the Winter 1972 Addendum, dated December 31, 1972, was used as a guide in the preparation of theinitial DAEC inservice inspection plan for Nuclear Class 1 components, and maximum access has been provided within the limits of drywell design.

The inspection interval for the examination program is 10 years. The extent of Nuclear Class 1 examinations at periods of 3-1/3 years a nd intervals of 10 years is tabulated in the DAEC Inservice Inspection Program. The extent of Nuclear Class 2 examinations during the first 10-yr interval and during the service lifetime of the plant is as indicated in Section 6.6. The actual individual inspections are generally performed during refueling outages and are adjusted to the load factor of the unit to minimize outage time directly required for inspection.

The examination program for Nuclear Class 1 components includes those portions of the pressure-containing components up to and including the outermost containment isolation valve that could isolate the primary systems in the event of a LOCA. The examination program assumes that examinations can be performed without the necessity of unloading the reactor core solely for the purpose of conducting examinations.

The first 10-yr program interval and the first 40-month inspection period began February 1, 1975. The second 40-month inspection period began June 1, 1978. The second inspection period was actually 49 months long because it was extended to cover a 9-month outage for replacement of recirculation system inlet nozzle safe-ends. The third 40-month inspection period began July 1, 1982, and it, and the 10-year program, ended on October 31, 1985.

The DAEC Inservice Inspection Program for the second and third inspection periods conformed to the requirements of ASME Code Section XI, 1974 Edition, with Addenda through Summer 1975.

UFSAR/DAEC - 1 5.2-13 Revision 22 - 5/13 The DAEC Inservice Inspection Program for the second 10-yr interval addressed the requirements of ASME Code,Section XI, 1980 Edition, with Addenda through Winter 1981, subject to limitations and modifications as stated in 10CFR50.55a(b)(2). This second 10-yr interval began November 1, 1985, and was divided into three inspection periods: (Note the second ten year interval was extended 1 year as permitted by IWA 2430(d) of the ASME Section XI, 1989 Edition and the revised rulemaking of 10CFR50.55a(g)(6)(A)(3)(v).

Period 1 November 1, 1985-March 1, 1989 Period 2 March 1, 1989-July 1, 1992 Period 3 July 1, 1992-November 1, 1996

The DAEC Inservice Inspection Program for the third 10-yr interval addresses the requirements of ASME Code,Section XI, 1989 Edition, subject to limitations and modifications as stated in 10CFR50.55a(b)(2). This third 10-yr interval began November 1, 1996 and ended on November 1, 2006. Results of inservice inspections and exceptions to the ASME Code are summarized in References 10 through 26.

The DAEC Inservice Inspection Program for the fourth 10-year interval addresses the requirements of the 2001 Edition through 2003 Addenda of the American Society of Mechanical Engineers (ASME), subject to the limitations and modifications of 10 CFR 50.55a(b)(2). This fourth 10-year interval began on November 1, 2006. Results of inspections and exceptions to the ASME Code are summarized in References 25 and 26.

When it is impossible or impractical to meet certain requirements of ASME Code,Section XI, requests for relief from the requirements are made pursuant to 10 CFR 50.55a(g)(5)(iii).

Visual inspection for leaks will be made periodically on ASME Section XI, Class 1, 2 and 3 systems. The specified inspection program encompasses the major areas of the vessel and piping systems within the ASME Section XI boundaries. The inspection period is based on the observed rate of growth of defects from fatigue studies sponsored by the NRC and is delineated by Section XI of the ASME Code. These studies show that it requires thousands of stress cycles at stresses beyond those expected to occur in a reactor system to propagate a crack. The test frequency established is at intervals such that, in comparison to study results, only a small number of stress cycles will occur at values below limits. On this basis, it is considered that the

test frequencies are adequate.

UFSAR/DAEC - 1 5.2-14 Revision 22 - 5/13 The type of examinations planned for each component depends on location, accessibility, and type of expected defect. Direct visual examination is proposed wherever possible since it is fast and reliable. Surface examinations are planned where practical and where added sensitivity

is required. Ultrasonic testing or radiography will be used where defects can occur in concealed surfaces. The type of examination will comply with ASME Section XI requirements for the particular item.

Records and documentation of all information and inspection results are retained by the DAEC for the active lifetime of the plant. The r ecords provide the basis for the evaluation of the preservice examination and facilitate its comparison with results from subsequent inspections.

5.2.4.2 Program Purpose and Objectives

The inservice inspection program for the DAEC complies with the principles and intent

of the ASME Inservice Inspection Code to the extent that current design and radiation levels permit. The program is established to provide reasonable assurance that no LOCA occurs at the

DAEC as a result of leakage or rupture of pressure-containing components and piping of the reactor coolant system, portions of the emergency core cooling systems, and portions of the auxiliary systems associated with the reactor coolant system.

The required ensurance is provided by conducting the following:

1. A preservice examination of all components and piping within the scope of Section XI (July 1, 1971 edition) of the ASME Code against which future examination determinations can be compared.

2. Systematic volumetric, visual, and surface examinations of systems and components during refueling outages to confirm that the structural integrity of these systems and components has not changed from their preoperational

condition or that any observed changed conditions are acceptable for continued

plant operation.

3. System pressure tests and leakage inspections for Nuclear Class 1 components on a periodic basis.

4. An Inservice Testing Program for pumps and valves as described in Section 3.9.6.

5. Feedwater Nozzle inspections and Control Rod Drive Return Line Nozzle inspections are discussed in the DAEC augmented examination program.

UFSAR/DAEC - 1 5.2-15 Revision 22 - 5/13 5.2.4.3 Examination Techniques 5.2.4.3.1 Nondestructive Examination

The examination procedures used for preservice and inservice inspection employ

ultrasonic, surface, and visual techniques. All examinations are conducted in accordance with the applicable edition of the ASME Code,Section XI.

The major emphasis of Section XI is on volumetric examination, which may be accomplished by either ultrasonic or radiographic techniques. Because of the buildup of background radiation from plant operation, the ultrasonic technique is considered the most practical method for volumetric examination. This type of examination may be done rapidly and in certain instances remotely, the components examined may be filled with water, and access to the work area while examinations are being conducted is not restricted.

Ultrasonic testing is utilized at the DAEC for volumetric examination. If interpretation of ultrasonic results warrant, radiographic techniques may also be applied. To meet the ASME Code, certain components and supports receive surface examinations utilizing dye penetrate or magnetic particle techniques. Systems and components also receive visual examinations prior to other techniques being employed.

Visual examinations provide a report of the general condition of the part, component, or surface examined, including such conditions as scratches, wear, cracks, corrosion, erosion, or

evidence of leakage.

The method used in the examination of each component is delineated in the DAEC

Fourth 10-Year Inservice Inspection Plan. Presently known instances where radiation levels, plant design, and/or materials make it impractical to adhere to the ASME Code are discussed in

the Inservice Inspection Plan and Section 5.2.4.5.

5.2.4.3.2 Pressure Tests for Nuclear Class 1 Components

Components within the reactor coolant pressure boundary are pressure tested before

startup following each reactor refueling outage and near the end of each inspection interval in accordance with the Inservice Inspection Plan. During the pressure test, components are inspected for leakage without the removal of insulation.

5.2.4.4 Nondestructive Testing (NDT) Operator Qualification

The nondestructive examinations are performed by personnel qualified in accordance with the guidelines of ASME Section XI (IWA-2300) which endorses SNT-TC-1A. Examiners are certified in accordance with the contractor's written practice which conforms to the

guidelines of SNT-TC-lA.

UFSAR/DAEC - 1 5.2-16 Revision 22 - 5/13 5.2.4.5 Class 1 System Boundaries and Accessibility The Nuclear Class 1 systems and their associated boundaries that are inspected during the operating lifetime of the plant are delineated below. Primary consideration is given to the reactor coolant system, portions of the auxiliary systems associated with the reactor coolant system, and portions of the emergency core cooling systems.

5.2.4.5.1 Reactor Coolant System Boundary

The reactor coolant system contains primar y reactor coolant at operating pressure during normal reactor operations and is considered to include the reactor pressure vessel, the recirculation system, the reactor coolant system safety and relief valves, and the main steam and feedwater piping systems extending out to and including the first containment isolation valve outside containment.

5.2.4.5.2 Reactor Coolant Associated Auxiliary Systems

Associated reactor auxiliary systems in which reactor coolant is diverted from the reactor coolant system either continuously or intermittently in support of normal reactor operation are the RWCU and RCIC systems out to and including the first containment isolation valve outside the primary containment.

5.2.4.5.3 Emergency Core Cooling Systems

Emergency core cooling system boundaries include the RHR, core spray, and HPCI systems connected to the reactor coolant system and extend out to and include the first containment isolation valve outside the primary containment.

5.2.4.5.4 Nuclear Class 1 Examination Exclusions

According to Subarticle IWB-1220 in Section XI of the ASME Code, certain small components and piping welds may be excluded on the premise that the amount of fluid lost in the event of a failure can be replenished by the normal makeup systems. The makeup systems can maintain inventory in the case of a water- or steam-line break in a line having an inside diameter of approximately 1 and 2 in., respectively. Visual examination of these welds will be conducted while performing the code-required pressure tests.

When it is impossible or impractical to meet certain code requirements, requests for relief are made pursuant to 10 CFR 50.55a(g)(5)(iii).

UFSAR/DAEC - 1 5.2-17 Revision 22 - 5/13 5.2.4.5.5 Nuclear Class 1 Component Accessibility

Areas of the reactor vessel outside diameter above the sacrificial shield, including the closure head, are accessible for volumetric and visual examinations by removing insulation panels. Removable plugs in the sacrificial shield and removable panels in the insulation area are also provided in the core region of the vessel, the bottom head, and around each nozzle (see Figure 5.2-11). These removable plugs and panels provide access to examine the nozzle-to-nozzle welds, nozzle-to-piping welds, portions of vessel welds in the core and bottom head regions, and the support skirt weld. In addition to the removable plugs and panels provided, the

reactor vessel insulation is designed as a standoff structure spaced 5.5 to 6 in. from the reactor vessel, as shown in Figure 5.2-12. To minimize personnel exposure to high-radiation levels, this annulus could be used as access to the reactor vessel welds with suitable remotely operated, mechanized ultrasonic devices.

The piping welds subject to inspection in the systems are made accessible by removable

insulation.

Interior surfaces and components below the reactor core are not made accessible by normal refueling operations. Portions of this region will be visually examined when maintenance operations provide access.

The 2-in. drain nozzle and line within the array of control rod hydraulic system housings are not accessible for volumetric examination; visual examination is performed.

The primary containment penetrations contain some piping welds that, in general, are not accessible for volumetric examination. Visual examination from outside the containment for evidence of leakage is performed in accordan ce with the Inservice Inspection Plan.

Visual examination of recirculation pump internal surfaces is performed when a pump or valve is disassembled for maintenance in accordance with the Inservice Inspection Plan.

5.2.4.5.6 Nuclear Class 1 Pressure-Containing Components and Piping

The Nuclear Class 1 pressure-containing com ponents and piping that are considered for inservice inspection and examination include the reactor pressure vessel and its appurtenances, primary pressure piping, pumps, and valves.

Components and appurtenances that are subjected to nondestructive examination in and

around the reactor pressure vessel include the following:

1. Reactor pressure vessel shell welds.

2. Closure head welds and flange ligaments.

UFSAR/DAEC - 1 5.2-18 Revision 22 - 5/13 3. Reactor vessel nozzle and penetration welds.

4. Closure studs and nuts.

5. Integrally welded vessel support welds.

6. Reactor vessel flange ligaments.

Welds in pressure-retaining piping, as indicated in Section 5.2.4.5 (subject to exclusions in Sections 5.2.4.5.4 and 5.2.4.5.5) will be examined. The piping is listed below and is schematically represented in Figure 5.2-13:

1. Main steam lines.

2. Reactor feedwater lines.

3. Reactor recirculation lines.

4. RHR system lines.

5. Core spray system lines.

6. HPCI system lines.

7. RCIC system lines.

8. Standby liquid control system lines.

9. Two-inch instrument lines below normal water level and 2-in. liquid control core P line.

10. Two-inch drain line.

5.2.4.6 Detail of Access Provisions and Examination Schedules

The access provisions and examination schedules are discussed below according to code categories. This information is condensed and presented in the DAEC Inservice Inspection Program.

UFSAR/DAEC - 1 5.2-19 Revision 22 - 5/13 1. Reactor Vessel and Closure Head

a. Longitudinal and Circumferential Welds in the Core Region

The design of the sacrificial shield and of the standoff insulation has

provided an annulus of 5.5 to 6 in. between the vessel and the insulation.

Access to welds in the core region has also been provided by installing removable panels in the insulation and removable plugs in the sacrificial

shield as shown in Figure 5.2-11. This access will be used when conditions warrant unloading the core and in the absence of remote examination equipment.

Examinations are conducted in accordance with the Inservice Inspection Plan.

b. Pressure-Containing Welds in Shell, Bottom Head, and Closure Head

Weld seams above the sacrificial shield on the vessel and on the closure head are accessible for manual ultrasonic examination by removing insulation panels. The remainder of the vessel shell seams are available for examination as described in this section. The bottom head-to-vessel weld in the plenum around the support skirt is accessible for manual ultrasonic testing examination by removing insulation panels with access through the sacrificial shield. The meridional weld inside the support skirt and outside the array of CRD mechanisms is accessible through manholes

within the support skirt.

Examinations are conducted in accordance with the Inservice Inspection Plan.

c. Vessel-to-Flange and Head-to-Flange Welds

Access is provided to these welds from the flange faces during refueling and through removable insulation panels around the closure head and the vessel. Examinations are conducted in accordance with the Inservice

Inspection Plan

d. Primary Nozzle-to-Vessel Welds and Nozzle Inside Radiused Sections

Access to the nozzle-to-vessel welds and nozzle blend radii is from the vessel outside diameter and is obtained through removable sections in the sacrificial shield and/or removable insulation panels. Manual ultrasonic techniques are planned during the earlier examination intervals. However, because of radiation levels, it may become necessary to adopt remotely operated equipment. The required access is available. Examinations are

conducted in accordance with the Inservice Inspection Plan.

UFSAR/DAEC - 1 5.2-20 Revision 22 - 5/13 e. Vessel Penetrations Including CRD Penetrations, CRD Housing Welds, and Incore Monitor Housing Penetrations.

Examinations are conducted in accordance with the Inservice Inspection Plan.

f. Primary Nozzle-to-Dissimilar Metal Piping Welds

Examinations are conducted in accordance with the Inservice Inspection Plan.

g. Closure Studs, Nuts, Washers, Bushings, and Ligaments Between Threaded Stud Holes

Examinations are conducted in accordance with the Inservice Inspection Plan.

h. Integrally Welded Vessel Supports

The vessel skirt-to-vessel weld is accessible through openings in the sacrificial shield and removable panels in the insulation. Examinations

are conducted in accordance with the Inservice Inspection Plan.

i. Interior Surfaces and Internals and Integrally Welded Internal Supports

The examinations for this category will be performed visually. The steam dryer and standpipe assembly are removed during refueling and will be examined under water during the refueling period.

Examinations are conducted in accordance with the Inservice Inspection

Plan.

2. Piping Pressure Boundaries

a. Dissimilar Metal Welds in Piping Systems (Other than on Vessel Nozzles)

Access to the piping welds is obtained through removable insulation.

Examinations are conducted in accordance with the Inservice Inspection

Plan.

b. Pressure-Retaining Bolting

Bolting within the piping systems is less than 2 in. in diameter, and thus only visual examination is required. Examinations are conducted in

accordance with the Inservice Inspection Plan.

UFSAR/DAEC - 1 5.2-21 Revision 22 - 5/13 c. Pressure-Containing Welds in Piping Welds within the piping systems are accessible through removable insulation. Examinations are conducted in accordance with the Inservice

Inspection Plan.

d. Piping Supports and Hangers

Removable insulation provides access to supports and hangers in the piping systems. Examinations are conducted in accordance with the

Inservice Inspection Plan.

3. Pumps Pressure Boundary

a. Pressure-Containing Welds in Pump Casings

There are no pumps with pressure-containing welds.

b. Pump Casings

The two recirculation pumps are in this category. Examinations are

conducted in accordance with the Inservice Inspection Plan.

c. Dissimilar Metal Piping Welds

There are no dissimilar metal pressure boundary welds on the recirculation pumps.

d. Pressure-Retaining Bolting

Examinations are conducted in accordance with the Inservice Inspection

Plan.

e. Pressure-Retaining Bolting Under 2 In.

Examinations are conducted in accordance with the Inservice Inspection

Plan.

f. Pump Supports and Hangers

Examinations are conducted in accordance with the Inservice Inspection

Plan.

UFSAR/DAEC - 1 5.2-22 Revision 22 - 5/13 4. Valve Pressure Boundary

a. Valve Body Welds

There are no valves in this system with pressure-containing welds.

b. Valve Bodies

Examinations are conducted in accordance with the Inservice Inspection

Plan.

c. Valve-to-Safe-End (Dissimilar Metal) Welds

There are no valves in the system with dissimilar metal welds.

d. Pressure-Retaining Bolting Larger than 2 in.

There are no valves with bolting 2 in. or larger in the system.

e. Pressure-Retaining Bolting Under 2 in.

All valves in the system have bolts under 2 in. in diameter. Examinations

are conducted in accordance with the Inservice Inspection Plan.

f. Valve Supports and Hangers

There are no valves within the system with integrally welded supports.

Examinations of nonintegrally welded supports and hangers are conducted

in accordance with the Inservice Inspection Plan.

5.2.4.7 Nuclear Class 1 Preoperational Examinations

Before initial plant startup, a preoperational examination of Nuclear Class 1 components was performed to establish a preservice record against which future inservice inspection results can be compared to determine the integrity of various included items throughout their lifetime.

The preoperational examinations were performed on all welds and components within the specified boundaries of the reactor coolant system, the auxiliary system associated with the reactor coolant system, and the emergency core cooling system as defined in Sections 5.2.4.5.1, 5.2.4.5.2, and 5.2.4.5.3.

UFSAR/DAEC - 1 5.2-23 Revision 22 - 5/13 5.2.4.8 Inservice Inspection of Shock Suppressors (Snubbers)

All safety-related snubbers are subject to an augmented inservice inspection program which is described in the Technical Requirements Manual.

5.2.4.9 Documentation and Records

Documentation and records of examination procedures, schedules, and inspection reports concerned with preoperational and inservice inspection are compiled and maintained by the

DAEC throughout the life of the plant.

The minimum requirements for documentation by the DAEC are those referenced in ASME Code,Section XI, and include full documentation of all the preservice base examination data and inservice inspection records of tests performed. Comparative analysis reports form part of the documentary effort, in addition corrective action reports and repair procedures where required. Originals of all inservice inspection records are maintained in a central location.

5.2.5 DETECTION

OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY Reliable means are provided to detect leakage from the nuclear system barrier inside the drywell. Nuclear system leakage rate limits are established so that appropriate action can be taken before the integrity of the nuclear system process barrier is unduly compromised.

5.2.5.1 Safety Design Bases

The nuclear system leakage rate limits are set such that corrective action can be taken

before one of the following occurs:

1. A threat of significant compromise to the nuclear system process barrier.

2. A leakage rate in excess of the coolant makeup capability to the reactor vessel.

3. A leakage rate in excess of the removal capability of the drywell sump pumps.

The nuclear system leakage detection system employs diverse methods to indicate

leakage within the drywell.

5.2.5.2 Description

UFSAR/DAEC - 1 5.2-24 Revision 22 - 5/13 5.2.5.2.1 General

Reliable means are provided to detect leakage from the nuclear system barrier inside the drywell. Nuclear system leakage rate limits are established so that appropriate action can be taken before the integrity of the nuclear system process barrier is unduly compromised.

The DAEC design includes a nuclear system leak detection, isolation, processing, and makeup system. This system (made up of many normal station operational subsystems) provides for leakage control capability. This capability includes the following:

1. Identifying the reactor building (or reactor primary system) leakage sources.

2. Efficiently isolating and controlling the sources.

3. Effectively removing the residual leakage water (before and after isolation).

4. Conveniently replacing the leakage liquid and/or restoring the source system function.

These functions are accomplished under normal operation or postaccident conditions in a manner in which normal (10 CFR 20) or accident (10 CFR 50.67) offsite dose limits do not exceed established values and in a manner in which the core and the containment cooling continuity is not impaired or negated.

The leakage considered here is limited to that water or steam released from the nuclear system process barrier inside the primary containment. Leakage inside the drywell is treated separately from leakage elsewhere in the plant because the drywell contains a high concentration of nuclear system piping and is totally inaccessible during reactor operation.

If a leak occurs, the drywell will contain the released matter that will be present in the liquid, gaseous, and vapor phases. This will result in the collection of water in the sumps, a possible increase in drywell temperature, pressure, and relative humidity, an increase in the air-conditioning heat load, and an increase in the radioactivity of the drywell atmosphere. The closed limited volume of the drywell enhances the detection sensitivity.

5.2.5.2.2 Leakage Sources

Total leakage within the drywell is divided into two classifications--identified and unidentified--depending on whether the drywell equipment drain sump (identified) or the drywell floor drain sump (unidentified) receives the fluid:

UFSAR/DAEC - 1 5.2-25 Revision 22 - 5/13 Identifiable Leakage (Equipment Drain Sump)

Identifiable leakage into the equipment drain sump is composed of normal seal and valve packing leakage and does not represent a safety consideration so long as the leakage is small compared to the available reactor coolant makeup capacity.

Most valves and pumps in the nuclear system inside the drywell are equipped with double seals; leakage through the primary seal is piped to the equipment drain sump.

Leakage from the main steam relief and safety valves is identified by downstream temperature sensors that read out in the main control room. Relief valve discharge is directed to

the suppression pool.

Unidentifiable Leakage (Floor Drain)

The unidentifiable leakage is composed of all leakage from the reactor primary system

that is not defined as identifiable leakage. This unidentified leakage is collected in the drywell floor drain sump. Vapor that is condensed by the drywell ventilation system will drain to this sump.

The sump systems and input sources are indicated on Figure 11.2-2.

5.2.5.2.3 Leak Detection Methods

The following six methods are used to detect leakage in the primary containment:

1. Equipment drain sump flow.

2. Floor drain sump flow.

3. Drywell ventilation system cooling water temperature.

4. Drywell pressure.

5. Drywell temperature.

6. Drywell atmosphere radioactivity.

Instrumentation is provided for the primary containment sumps having a capability to detect steam leakage of 0.5 gpm within a 45-min period. The response time depends on the amount of background leakage but will not exceed the interval between pumping cycles. The higher the leak rate the shorter the response time. Alarms are provided to annunciate leakage.

UFSAR/DAEC - 1 5.2-26 Revision 22 - 5/13 The alarm setpoints will be adjustable from 0 to 5 gpm for the floor drain sump (unidentified leakage) and 0 to 25 gpm for the equipment drain sump (identified leakage), thus giving the capability of having alarm annunciation set at or below the license limit and providing immediate response when the preselected rate is reached or exceeded.

The unidentified leakage rate is the portion of the total leakage rate received in the drywell sumps that is not identified. A threat of significant compromise to the nuclear system

process barrier exists if the barrier contains a crack that is large enough to propagate rapidly (i.e., critical crack). An allowance for leakage that does not compromise barrier integrity and is not identifiable is made for normal plant operation. The unidentified leakage rate limit for the DAEC is established at the 5-gpm rate to allow time for corrective action before the process barrier could be significantly compromised. This 5-gpm unidentified leakage rate is substantially lower than the calculated flow from a subcritical crack in a primary system pipe.

The experimental as well as mathematical background is summarized below.

Critical Crack Length

Both the GE 6 and the BMI 7 test results indicate that formulas for theoretical fracture mechanics do not predict critical crack length, but that satisfactory empirical expressions may be developed to fit test results. A simple equation (for axially oriented through-wall cracks) that fits the data in the range of normal design stresses (for carbon steel pipe) is

l c= 15,000 D (see data correlation on Figure 5.2-14) l c = critical crack length, in.

D = mean pipe diameter, in.

= nominal hoop stress, psi

Crack Opening displacement The theory of elasticity predicts a crack-opening displacement of

w = 2l E

where

l = crack length

= applied nominal stress

E = Young's modulus UFSAR/DAEC - 1 5.2-27 Revision 22 - 5/13 Measurements of crack-opening displacement made by BMI show that local yielding and bending greatly increases the crack opening displacement as the applied stress approaches the failure stress f . A suitable correction factor for plasticity effects is C = sec [/2f] The crack opening area is given by A = Cwl/4 or A = l 2 sec [/2f] 2E For a given crack length of l, f = 15,000 D/l.

Leakage Flow Rate The maximum flow rate for the blowdown of saturated water at 1000 psi is 55 lb/sec-in.

2 , and for saturated steam the rate is 14.6 lb/sec-in.

a (Reference 8). Friction in the flow passage reduces this rate, but for cracks leaking at 5 gpm (0.7 lb/sec) the effect of friction is small. The required leak size for 5-gpm flow is

A = 0.0126 in.

2 (saturated water) A = 0.0475 in.

2 (saturated steam)

Figure 5.2-15 shows general relationships between crack length, leak rate, stress, and line size using the mathematical model described above. The asterisks in the figure denote conditions at which the crack-opening displacement is 0.1 in., at which time instability is imminent. This provides a realistic estimate of the leak rate to be expected from a crack of critical size. In every case, the leak rate from a crack of critical size is significantly greater than the 5-gpm criteria.

From the mathematical model described above, the critical crack length and the 5-gpm crack length have been calculated for representative BWR pipe sizes and pressure (1050 psi).

Results are tabulated as follows.

The lengths of through-wall cracks that would leak at the rate of 5 gpm given as a function of wall thickness and nominal pipe size are

Nominal Pipe Size Wall Thickness (in.) Crack Length l (in.) Steam Line Water Line 4 in., Schedule 80 0.337 7.15 4.91 12 in., Schedule 80 0.687 8.46 4.76 20 in., main steam 0.758 7.39 -- 22 in., recirculation 0.975 -- 4.39 UFSAR/DAEC - 1 5.2-28 Revision 22 - 5/13 The ratios of crack length l to the critical crack length l c as a function of nominal pipe size are Nominal Pipe Size Ratio l/l c Steam Line Water Line 4 in., Schedule 80 0.745 0.510 12 in., Schedule 80 0.432 0.243 20 in., main steam 0.342 -- 22 in., recirculation -- 0.158 It is important to recognize that the failure of ductile piping with a long, through-wall crack is characterized by large crack-opening displacements that precede unstable rupture.

Judging from observed crack behavior in the GE and BMI experimental programs involving both circumferential and axial cracks, it is estimated that leak rates of hundreds of gpm will precede crack instability. Measured crack-opening displacements for the BMI experiments were in the range of 0.1 to 0.2 in. at the time of incipient rupture, corresponding to leaks of the order of 1

in 2. in size for plain carbon steel piping. For aust enitic stainless steel piping, even larger leaks are expected to precede crack instability, although there is insufficient data to permit quantitative

prediction.

The results given are for a longitudinally oriented flaw at normal operating hoop stress.

A circumferentially oriented flaw could be subj ected to stress as high as the 550°F yield stress, assuming that high thermal expansion stresses exist. A good mathematical model that is well supported by test data is not available for the circumferential crack. Therefore, it is assumed that

the longitudinal crack, subject to a stress as high as 30,000 psi, constitutes a "worst case" with regard to leak rate versus critical size relationships. Given the same stress level, differences between the circumferential and longitudinal orientations are not expected to be significant in this comparison.

5.2.5.2.3.1 Equipment Drain and Floor Drain Sumps

The equipment drain sump system is actually composed of two sumps: the equipment drain sump is located beneath the reactor inside the reactor vessel pedestal and is directly joined to the equipment drain pump sump located inside the drywell but outside the pedestal. These two sumps will be generally referred to as the equipment drain sump.

The equipment drain sump level is used to control the drain pumps and provide alarms to control room personnel.

The pump control and alarm function is as follows.

UFSAR/DAEC - 1 5.2-29 Revision 22 - 5/13 At the lowest of the high water level settings, the preferred pump is automatically started. If the water level continues to rise, a higher water level setting starts the standby pump and actuates an alarm in the control room. When the water level decreases to a low water level setting, the pumps are stopped and the automatic pump selector switch reverses the roles of the preferred and standby pumps.

As the water that has collected in the sump is pumped out, the discharge flow is monitored.

The flow rate is continually plotted on a recorder in the control room. The total volume pumped is indicated in the control room. The sump pump discharge flow duration, the frequency of pump operation, and the volume pumped can be used to provide a measure of the leakage rate.

Excessive leak rates are indicated by a control room alarm. This alarm is actuated by either of two timed conditions: the pump starting at shorter intervals than would be required if the alarm setpoint leak rate existed, or the pump running longer than would be required to lower

the level to the shutoff point.

The drywell floor drain sump system is monitored and controlled in the same manner as the drywell equipment drain sump.

5.2.5.2.3.2 Drywell Ventilation

The drywell ventilation system is a water-cooled, forced-air system, using well water as the cooling medium. In this system, the temperature of the gas entering and leaving the cooler and the outlet temperature of the well water are monitored. Once steady-state operation is established, variations of these parameters can indicate possible leaks. Since the inlet water has an essentially constant temperature, a rise in outlet temperature indicates additional heat load on the cooling coils and could be indicative of a leak. With the exception of the single fan units, high air or water outlet temperature will actuate an alarm.

5.2.5.2.3.3 Drywell Pressure, Temperature and Radioactivity

The drywell temperature and pressure are monitored, indicated, and recorded in the control room. The sample points and instrumentation are indicated in Figure 6.2-44.

The drywell atmosphere radioactivity detector provides a backup indication to the drywell sump system of increased nuclear system leakage. The drywell environment is continuously sampled from three locations that are chosen to provide both a representative gas mixture and an indication of the location of the leakage. The lines used for the oxygen sampling system are also used for the drywell atmosphere radioactivity detector in order to take advantage

of existing piping, penetrations, and isolation capab ilities. The piping runs to the detector are as short and as straight as possible to minimize the particulate deposition and are constructed of stainless steel to minimize chemical reactions.

UFSAR/DAEC - 1 5.2-30 Revision 22 - 5/13 The drywell atmosphere radioactivity detector is designed so that steam leakage rates as low as 1 gpm can be detected. However, their sensitivity is directly proportional to the radioactive source term in the reactor coolant during normal operation. With high fuel integrity (lower source term), the time to detect small leaks can be long. Therefore, these detectors are only used as a back-up monitor for reactor coolant system leakage.

The sampled air undergoes three separate processes in which the radioactive noble gas, halogen, and particulate content is determined. This system is thus a three-channel monitoring system. The processed air is returned to the drywell.

The readings for each channel are fed into a recorder so that a permanent record of the drywell atmosphere radioactivity is maintained. The system will alarm locally and in the control room to indicate system failure or alarm conditions. No automatic action is initiated by the system.

5.2.5.3 Safety Evaluation

5.2.5.3.1 General

The different drywell parameters that are discussed in Section 5.2.5 provide diverse methods for determining if an increased leak rate exists within the drywell. The allowable leakage rates have been based on the predicted and experimentally determined behavior of cracks in pipes, the ability to make up coolant system leakage, the normally expected background leakage due to equipment design, and the detection capability of the various drywell monitors.

Based on the behavior of cracks, a 5-gpm leak rate limit has been assigned to unidentified leaks and a 25-gpm leak rate limit for the total of unidentified and identified leaks. Experience has shown that normal leak rate is 4 gpm into the equipment drain sump and 0 to 0.5 gpm into the floor drain sump. The Technical Specifications limit is 5 gpm unidentified leakage, 25 gpm total leakage, and a 2 gpm increase in unidentified leakage within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, DAEC

Technical Specifications state that a reactor shutdown must be initiated if the unidentified drywell leakage is observed to increase by 2 gpm in any 24-hr period.

The sump working capacities and pump discharge capacities are large enough to accept the design leak rates. The sump working capacity is the amount of water between the low-level pump trip and the high-high-level alarm point. The equipment drain sump (approximate

working capacity, 450 gal) and the floor drain sump (approximate working capacity, 225 gal) are drained by two 50-gpm pumps. This pump capacity permits one pump in each sump to remove

the design total leakage because of the possibility that most of the leakage could flow into one sump.

2011-006 UFSAR/DAEC - 1 5.2-31 Revision 22 - 5/13 5.2.5.3.2 Behavior of Cracks

The behavior of cracks in piping systems has been experimentally and analytically

investigated as part of an NRC-sponsored Reactor Primary Coolant System Rupture Study (the Pipe Rupture Study). Analysis using the data obt ained in this study has shown that there is a high probability that a leaking crack can be detected before it grows to a dangerous or critical size because of mechanically or thermally induced cyclic loading, or stress corrosion cracking, or some other mechanism characterized by gradual crack growth. Earthquake and normal vibration stresses are considered in the determination of the critical crack size. For the crack size that gives a water leakage of 15 gpm, the probability of rapid propagation was calculated to be

10-4 . The crack area corresponding to a 15-gpm leak is approximately 1.8 x 10

-4 ft 2.

The Technical Specification unidentified leakage rate has been set at 5 gpm to provide further conservatism.

5.2.5.3.3 Total Leakage Rate Limit

The criterion for establishing the total leakage rate limit is based on the makeup capability of the CRD and RCIC systems and is independent of the feedwater system, normal ac power, and the emergency core cooling systems. The CRD system supplies 42 gpm into the reactor vessel; the RCIC system can supply 425 gpm through the feedwater sparger to the reactor vessel. The total leakage rate limit is set at less than 0.1 of this value or 25 gpm.

5.2.5.3.4 Drywell Leak Detection

The sump-fill timer and pump-out timer for both the equipment drain sump and floor drain sump are set to alarm at levels that provide adequate separation from expected leak rates to avoid spurious alarms but low enough to indicate significant leaks. Exact leak rates can be determined from the flow indications in the control room, and any increase beyond the normal leak rate will be apparent to control room personnel.

The drywell ventilation system consists of several coolers, each with a separate heat load.

The calculated well water differential temperature is 30° to 45°F depending on the cooler in question. It is therefore reasonable to assume that a 5°F rise in outlet temperature is detectable.

If one assumes the following, one can determine that, for a given size break, steam and water are equally detectable although four times as much reactor water is lost through a water

break.

1. A 5°F rise in cooler outlet water temperature is detectable by control room personnel.

2. Normal cooler heat load is 740,000 Btu/hr.

UFSAR/DAEC - 1 5.2-32 Revision 22 - 5/13 3. A 1000-psig blowdown of saturated steam or water.

9

4. Fifty percent of the water and 100% of the steam become airborne.

The alarms associated with the cooler air and water outlet provide additional indication

should a sudden increase in leak rate occur.

Drywell temperature and, to some extent, drywell pressure are controlled by the drywell ventilation system. As the heat load on the cooling coil is increased, the average drywell temperature will increase. If this temperature exceeds the setpoint, an alarm will occur. The combination of increased temperature and increased absolute humidity causes the drywell pressure to increase. A small increase in pressure above the setpoint will actuate an alarm; a 2-psig increase indicates a larger leak and is used to initiate a scram, nuclear steam supply isolation

and ECCS (including HPCI, LPCI and CS). Low reactor water level will also indicate larger leaks and initiate a scram and isolation.

If the drywell ventilation system is assumed to be saturated so that the steam or water from a leak does not condense, there will be an increase in drywell temperature, pressure, and relative humidity with respect to time, providing an indication of the sensitivity of these parameters.

The drywell atmosphere radioactivity detector serves as a reliable backup to the other methods of leak detection. It is anticipated that the particulate detector will be the primary

indication of leakage, with the halogen and nobl e gas detectors serving as indications of the drywell environment if drywell venting is required. These detectors, in conjunction with an isotopic analysis, can be used to indicate whether the detected leak is from a steam or water system.

The detector units are shielded to minimize the effect of background activity and thereby increase the detection sensitivity. The individual units have the capability of being tested for reaction to a source and calibrated. Since the background contamination and deposition--

chemical reaction effects--cannot be predetermined, and since it is an increase in detected values that indicates a leak, the alarm points will be determined by operator experience; the setpoints

will be low enough to provide the quickest indication without receiving spurious alarms.

It is expected that this system will provide at least an order of magnitude reduction in the leak size that can be detected and will also reduce the time delay in sensing the condition.

5.2.5.4 Inspection and Testing

The nuclear system leak detection system is an operational system in daily use. Testing of these systems are specified in the DAEC Technical Specifications.

UFSAR/DAEC - 1 5.2-33 Revision 22 - 5/13 REFERENCES FOR SECTION 5.2

1. General Electric Company, Safety Analys es Report for Duane Arnold Energy Center Extended Power Uprate, NEDO-32980, Revision 0, March 2001.

2. DAEC licensing submittal IE-77-2342, December 30, 1977.

3. DAEC licensing submittal IE-78-386, March 15, 1978.

4. General Electric Company, General Electric Process Specification for Heat Sink Welding of Austenitic Stainless Steel, NEDO-24134-1, 1978.

5. Letter from R. W. McGaughy, Iowa Electric, to H. Denton, NRC,

Subject:

Results of Inspection of Stainless Steel Piping at the DAEC, dated May 3, 1985 (NG-85-1901).

6. M. B. Reynolds, Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flow, GEAP-5620, 1968.

7. A. R. Duffy, R. J. Eiber, and W. A. Maxey, Recent Work on Flow Behavior in Pressure Vessels, 1969. Also, Quarterly Progress Reports, "Investigation of the Initiation and Extent of Ductile Pipe Rupture," by Eiber et al., 1966 through 1969.

8. F. J. Moody, Maximum Two-Phase Vessel Blowdown from Pipes, APED-4827, 1965.

9. F. J. Moody, Maximum Flow Rate of a Single Component, Two-Phase Mixture, ASME paper 64-MT-35.

10. Letter from R. McGaughy, Iowa Electric, to H. Denton, NRC,

Subject:

Second 10 Year Inspection Plan, dated August 15, 1986, (NG-86-2750).

11. Letter from R. McGaughy, Iowa Electric, to H. Denton, NRC,

Subject:

First 10 Year Inservice Inspection Summary, dated August 15, 1986, (NG-86-2520).

12. Letter from W. Rothert, Iowa Electric, to T. Murley, NRC,

Subject:

DAEC Inservice Inspection Report, dated October 22, 1987, (NG-87-2986).

13. Letter from D. Mineck, Iowa Electric, to T. Murley, NRC,

Subject:

DAEC Inservice Inspection Report, dated March 24, 1989 (NG-89-0728).

14. Letter from D. Mineck, Iowa Electric, to T. Murley, NRC,

Subject:

DAEC Inservice Inspection Report, dated December 10, 1990, (NG-90-2858).

UFSAR/DAEC - 1 5.2-34 Revision 22 - 5/13 15. Letter from J. Franz, Iowa Electric, to T. Murley, NRC,

Subject:

DAEC Inservice Inspection Report, dated July 24, 1992 (NG-92-3268).

16. Letter from J. Franz, Iowa Electric, to T. Murley, NRC,

Subject:

DAEC Inservice Inspection Report, dated January 11, 1994 (NG-93-5376).

17. Letter from J. Franz, IES Utilities, to W. Russell, NRC,

Subject:

DAEC Third 10-year Inservice Inspection Plan, dated April 26, 1996, (NG-96-0809).

18. Letter from K. Young, IES Utilities, to W. Russell, NRC,

Subject:

DAEC Inservice Inspection Report, dated July 18, 1995, (NG-95-2142).

19. Letter from K. Peveler, IES Utlitites, to NRC,

Subject:

DAEC Inservice Inspection Report, dated February 14, 1997, (NG-97-0327).

20. Letter from K. Peveler, IES Utilities, to NRC,

Subject:

DAEC Inservice Inspection Report, dated July 15, 1998 (NG-98-1244).

21. Letter from K. Peveler, IES Utilities, to NRC,

Subject:

DAEC Inservice Inspection Report, dated February 28, 2000 (NG-00-0319).

22. Letter from K. Putnam, NMC, to NRC,

Subject:

DAEC Inservice Inspection Report, dated August 15, 2001 (NG-01-0975).

23. Letter from M. Peifer, NMC, to NRC,

Subject:

DAEC Inservice Inspection Report, dated July 18, 2003 (NG-03-0509).

24. Letter from G. Van Middlesworth, NMC, to NRC,

Subject:

DAEC Inservice Inspection Report, dated July 29, 2005 (NG-05-0420).

25. Letter from G. Van Middlesworth, FPL Energy Duane Arnold, to NRC,

Subject:

DAEC Inservice Inspection Report, dated June 12, 2007 (NG-07-0492).

26. Letter from Richard L. Anderson, FPL Energy Duane Arnold, to NRC,

Subject:

Corrected Sections of Inservice Inspection Report for RFO20, dated February 28, 2008 (NG-08-0141).

UFSAR/DAEC-1 T5.2-1 Revision 18 - 10/04 Table 5.2-1 NUCLEAR SYSTEM SAFETY AND RELIEF VALVES

Valve Type Number of Valves Set Pressure (nominal) a (psig) Capacity at 103% of Set Pressure (each) (lb/hr) Relief 1 1110 853,000 1 1120 860,000 2 1130 868,000 2 1140 876,000 Total b 6 (4) Safety 2 1240 642,000 Relief (low-low set

function) 1 1030 open 910 close 1 1035 open 915 close

a Nominal setting +3% tolerance is assumed in the transient analyses in Chapter 15 for the Relief mode of the S/RV and SSVs. For the LLS function, these represent the nominal trip setpoint (NTSP), the Analytical Limits used in the transient and accident analyses

can be found in Chapter 15.0

b The number in parentheses indicates the number of relief valves that serve in the automatic depressurization capacity.

UFSAR/DAEC-1 T5.2-2 Revision 12 - 10/95 Table 5.2-2 SAFETY VALVE SCRAM AVAILABILITY

Scram Availability a Flux Five of six dual plus

Zero of two spring valves

or

Four of six dual plus

One of two spring valves

or

Four of six dual plus

Two of two spring valves

>0.99999 Pressure Six of six dual plus

Zero of two spring valves

or

Five of six dual plus

Two of two spring valves

>0.99930 a Two-year interval between tests.

.......-.,....-ASMECODEAPPROVEDSAFETYVALVECAPACITYVALVECLOSURECHARACTERISnCS(TYPICAL)r---IIIIIIItIIIIIIItIIIIIIIo'-_....JIL--__.L.-I---L.----L.I9698100102104PRESSURE/PRESSURESETPOINT(%OFRATEDSTEAMFLOW)80I-el:...Jll.,;el:Z>...J60I-<<>>I-1&1II..el:(I)II..00-:c940II..,;el:l;;DUANEARNOLDENERGYCENTERIESUTILITIES,INC.UPDATEDFINALSAFETYANALYSISREPORTTypicalDualRelief/SafetyPopValveCapacityCharacteristicsFigure5.2-1Revision14-11/98 we(.JW:2e(zw>oJwu..e(lJ)u..o;;:ooJu..:2e(wen10080604020(PROBABLELIFT//-I///////"-(VALVE/CLOSURE//CHARACTERISTICSITYPICAL)/fl-I/I/1/I/1/(ASMECODEAPPROVEDCAPACITY)(ASSUMEDLIFTCHARACTERIST1Cl10410210098o....--li--.......I"'--.l-_.......96SETPOINT(%OFRATEDSTEAMFIOWlDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTTypicalSpringLoadedSafetyValveCapacityCharacteristicsFigure5.2-2

12r----------------------------.......---.910LesCRITICALCRACKLENGTH(in.)o-MEANPIPEDIAMETER0'77=PIPEHOOPSTRESSMATERIAL-A106B90012.8fe/D=15.000/0'771110715'"0CO)-6I)(*0-0)(s:=-t:>5*200425303**0oGEDATA(""'60oF)*OJ)*8MIDATA4025060700....__...........__-'-__......"'-__......__..........._......o0.20.40.60.81.01.21.41.61.8te/DDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTAxialThrough-WallCrackDataCorrelationFigure5.2-14 800-10ksi!600-I20r/400-/I/I/II200'-I//10/II/II/100l-I/I80I-20/I/60-I/EI/0-I.$.J/w40l-t-Ic(I/a:::.:Ic(/woJI/20-I,/15-I//ILEGEND/10l-I/CALCULATEDLEAKRATEASAFUNCTIONOFCRACKLENGTHANDAPPLIEDHOOPSTRESS8t--IAXIALLYORIENTEDCRACKI/SATURATEDWATERSYSTEMAT1000psig6l-IIIASTERISKSDENOTECRACKOPENINGOF0.1in.4l-II4in.LINEII_____24in.LINEI2'-IJIIIIIIIIIIIIIII02468101214161820222426283234CRACKLENGTH!in.)DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTCalculatedLeakRateasaFunctionofCrackLengthandAppliedHoopStressFigure5.2-15 UFSAR/DAEC-1 5.3-1 Revision 21 - 5/11

5.3 REACTOR

VESSELS

5.3.1 REACTOR

VESSEL MATERIALS

5.3.1.1 Material Specifications

The reactor vessel design objective is to provide a volume in which the core can be submerged in coolant, thereby allowing power operation of the fuel. The design of the reactor vessel and appurtenances provides the means for the attachment of pipelines to the reactor vessel and the means for the proper installation of vessel internal components.

The power generation design bases are as follows:

1. The location and design of the external and internal supports provided as an integral part of the reactor vessel are such that stresses in the reactor

vessel and supports due to reactions at these supports are within applicable ASME Code limits. (See Chapter 3 and Appendix 5A for specific design

criteria.)

2. The reactor vessel design lifetime is 60 years.

3. The design of the reactor vessel and appurtenances allows for the accomplishment of a suitable program of periodic inspection and

surveillance.

The safety design bases are as follows:

1. The reactor vessel and appurtenances are designed to withstand adverse combinations of loadings and forces resulting from operation under abnormal and accident conditions.

2. To minimize the possibility of brittle fracture failure of the nuclear system process barrier, the following are required: (1) the initial ductile-brittle transition temperature of materials used in the reactor vessel is known by reference or established empirically and (2) expected shifts in the transition temperature during design service life because of neutron flux are determined and employed in the reactor vessel design.

UFSAR/DAEC-1 5.3-2 Revision 21 - 5/11 The reactor vessel is a vertical, cylindrical pressure vessel with hemispherical

heads of welded construction. The reactor ve ssel is designed and fabricated for a useful life of 60 years based on the specified design and operating conditions. The vessel is designed, fabricated, inspected, tested, and stamped in accordance with the 1965 ASME Code,Section III, and applicable requirements for Class A vessels as defined therein and in the interpretation of the ASME Code up to but not including the Winter 1967 Addenda according to the following list. General Electric comments with regard to 34 criteria proposed by the AEC were transmitted on March 13, 1968, to Harold C. Price. The positions indicated by these comments were used in the design and fabrication of the

DAEC unit.

1. Charpy impact tests per N-331.2 of the Winter 1967 Addenda were furnished for vessel studs.

2. All full-penetration pressure-carrying welds were ultrasonically examined using the angle-beam method described by N-625 of the Winter 1967

Addenda.

3. The changes to Article 4 - "Design," by the Winter 1967 Addenda were included.

4. The addition of Appendix IX, "Quality Control and Nondestructive Examination Methods," was included.

5. ASME Code Case 1441-1 was included as an option for design analysis.

The nuclear steam supplier's (GE) purchase specifications supplement the requirements of the codes and encompass the means whereby the design objective is satisfied.

The reactor pressure vessel was fabricated by the Chicago Bridge & Iron Company (CB&I). Material for the vessel was purchased by CB&I. Site assembly of the

vessel is described in Appendix 5A.

The reactor vessel and its supports are designed in accordance with the loading criteria of Chapter 3 and Appendix 5A. The materials used in the design and fabrication

of the reactor pressure vessel are shown in Table 5.3-1.

UFSAR/DAEC-1 5.3-3 Revision 12 - 10/95 The cylindrical shell and bottom hemispherical head of the reactor vessel are

fabricated of low-alloy steel plate that is cl ad on the interior with stainless steel weld overlay. The plates and forgings are ultrasonically tested and magnetic particle tested over 100% of their surfaces after forming and heat treatment. The preheat of vessel plate and forgings is maintained during welding until the weld joints are postweld heat treated.

Full-penetration welds are used in all joints that retain design pressure, including nozzles throughout the vessel with the exception of nozzles less than 3-in. nominal size incore

penetrations and CRD penetrations.

Although little corrosion of plain carbon or low-alloy steels occurs at temperatures of 500 to 600°F, higher corrosion rates occur at temperatures around 140°F.

The 0.125-in. minimum thickness stainless steel cladding provides the necessary corrosion resistance during reactor shutdown and also helps maintain water clarity during refueling operations. Since the vessel head is exposed to a saturated steam environment throughout its operating lifetime, stainless steel cladding is not required over its interior surfaces. Exterior exposed ferritic surfaces of pressure-containing parts have a minimum

corrosion allowance of 1/32 in. The interior surfaces of the top head and all carbon and

low-alloy steel nozzles exposed to the reactor coolant have a corrosion allowance of 1/16 in. The vessel shape is designed to minimize coolant retention pockets and crevices.

5.3.1.2 Special Processes Used for Manufacturing and Fabrication

Site assembly of the reactor vessel is described in Appendix 5A.

5.3.1.3 Special Methods for Nondestructive Examination

See Sections 5.2.4.3 and 5.4.3.5.4.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels

Furnace sensitization of austenitic stainless steel has been avoided. Austenitic stainless steel is considered to be furnace sensitized if it has been heated by means other

than welding within the range of 800 to 1800°F, regardless of subsequent cooling rate.

Such parts that are subsequently solution annealed are not considered to be sensitized.

The austenitic stainless steel castings were specified to contain a minimum of 5%

ferrite.

The specifications for reactor vessel beltline ferritic materials did not include any additionally imposed limits on residual elements. The specifications did include requirements on grain size that were intended to reduce sensitivity to irradiation embrittlement in service.

UFSAR/DAEC-1 5.3-4 Revision 18 - 10/05 5.3.1.5 Fracture Toughness

5.3.1.5.1 Compliance With 10 CFR 50, Appendix G

A major condition necessary for full compliance with Appendix G is satisfaction of the requirements of the Summer 1972 or later addenda to Section III of the ASME Code. This is not possible with components that were purchased to earlier ASME Code requirements. (The reactor pressure vessel was manufactured to pre-1972 ASME Code requirements, as described in Section 5.3.1.1.)

Ferritic materials complying with 10 CFR 50, Appendix G, must have both

drop-weight tests and Charpy V-notch tests with the Charpy V-notch specimens oriented transverse to the principal material working direction to establish the reference temperature RT NDT. The Charpy V-notch tests must be evaluated against both an absorbed energy and a lateral expansion criteria. The maximum acceptable RT NDT must be determined in accordance with the analyti cal procedures of the ASME Code Section III, NB-2300. Appendix G of 10 CFR 50 requires a minimum of 75 ft-lb upper-shelf Charpy V-notch energy for unirradiated beltline materials and at least 50 ft-lb upper-shelf

energy at the end of life.

By comparison, materials for the reactor pressure vessel were qualified by drop-

weight tests and longitudinally oriented Ch arpy V-notch tests, generally at only one temperature, confirming that the material nil-ductility transition temperature (NDT) was at least 60° below the lowest service temperature. There was no upper-shelf Charpy V-notch energy requirement on the beltline materials. The bolting materials were qualified

to a 30 ft-lb Charpy V-notch energy requirement at 60°F below the minimum preload temperature.

From the above comparison it can be seen that the fracture toughness testing performed on the reactor pressure vessel materials cannot be shown to comply directly with the requirements of ASME Code Section III NB-2300. However, Paragraph III.A of 10 CFR 50, Appendix G, states that an approved method may be used to demonstrate

equivalence of pre-1972 ASME Code fracture toughness data with post-1972 ASME Code requirements. The method used to develop RT NDT values to current requirements is described in Section 5.3.1.5.2.

UFSAR/DAEC-1 5.3-5 Revision 12 - 10/95 5.3.1.5.2 Method of RT NDT Evaluation

For the purpose of setting the operating limits, the RT NDT was determined from the toughness test data taken in accordance with requirements of the ASME Code,Section III, and the GE reactor pressure vessel purchase specification to which the reactor pressure vessel was designed and manufactured. These toughness test data, Charpy V-notch and drop-weight NDT, were analyzed to establish compliance with the

intent of 10 CFR 50, Appendix G. Because all toughness testing needed for strict compliance was not required at the time of reactor pressure vessel procurement, some

toughness results are not available. To substitute for this absence of certain data, toughness property correlations were derived for the vessel materials in order to operate upon the available data to give a conservative estimate of RT NDT, in compliance with the intent of 10 CFR 50, Appendix G, criteria. These toughness correlations vary, depending upon the specific material analyzed, and were derived from the results of Welding Research Council Bulletin 217, "Properties of Heavy Section Nuclear Reactor Steels," and from toughness data for other BWR reactors.

In the case of vessel plate material (SA-533 Grade B, Class 1), the predicted limiting toughness property is either NDT or transverse Charpy V-notch 50 ft-lb temperature minus 60°F, whichever is greater. As a matter of practice where NDT results are missing, NDT is estimated as the longitudinal Charpy V-notch 35 ft-lb transition temperature. However, for th e DAEC vessel plates, "no break" drop-weight information was available at purchase specification temperatures, so the NDT was conservatively taken as 10°F below the "no break" test temperature. The transverse Charpy V-notch 50 ft-lb transition temperature was estimated from longitudinal Charpy V-notch data in the following manner. The lowest longitudinal Charpy V-notch energy,

if below 50 ft-lb, was adjusted to deri ve a longitudinal Charpy V-notch 50 ft-lb transition temperature by adding 2°F/ft-lb to the test temperature. If the actual data equaled or exceeded 50 ft-lb, the test temperature was used. Once the longitudinal 50 ft-lb temperature was derived, an additional 30°F was added to account for the orientation change from longitudinal 50 ft-lb to transverse 50 ft-lb.

For forgings (SA-508, Class 2), the predicted limiting property is the same as for

vessel plates and the RT NDT was estimated in the same way.

For the vessel weld metal the predicted limiting property is the Charpy V-notch 50 ft-lb transition temperature minus 60°F, as BWR materials experience indicates that drop-weight NDT values are typically -50°F or lower. The Charpy V-notch 50 ft-lb temperature was derived in the same way as for the vessel plate material, except the 30°F addition for orientation effects was omitted since there is no principal working direction in weld metal. NDT values were not available, so the RT NDT was taken as the transverse Charpy V-notch 50 ft-lb transition temperature minus 60°F.

UFSAR/DAEC-1 5.3-6 Revision 20 - 8/09 For the vessel weld heat-affected zone material, the RT NDT was assumed to be the same as for the base material. ASME Code weld procedure qualification test requirements and postweld heat treatment data indicate that this assumption is valid.

For bolting material, the current ASME Code requirements define the lowest service temperature (LST) as the temperature at which transverse Charpy V-Notch (CVN) energy of 45 ft-lb. and 25 mils lateral expansion (MLE) were achieved. If the required Charpy results are not met, or are not reported, but the CVN energy reported is above 30 ft-lb., the requirements of the ASME Code Section III, Subsection NB-2300 at construction are applied, namely that the 30 ft-lb. test temperature plus 60°F is the LST for the bolting materials. Charpy data for the Duane Arnold closure studs indicates the materials did not meet the 45 ft-lb., 25 MLE requirement at 10°F, but the CVN energy was greater than 30 ft-lb. Thus, the higher of the LST and the RT NDT +60°F determines the boltup limit in the closure flange region.

5.3.1.5.3 Calculated Values of Initial RT NDT The methods in Section 5.3.1.5.2 were used to calculate initial RT NDT values for the core beltline plates and welds, closure flange region, nozzles and other discontinuities, and lowest service temperature for the closure bolting material. The calculation methods conservatively estimate RT NDT in order to meet the intent of 10 CFR 50, Appendix G, criteria. The beltline plate RT NDT is +40°F, based on the NDT for shell ring number one. The weld metal RT NDT of -50°F was calculated by adjusting Charpy V-notch data. The value of NDT for the reactor vessel nozzles is 40°F. The highest RT NDT value for the nozzles is 74°F for N15, Drain Nozzle. The upper vessel shell plate material at 14°F represents the limiting initial RT NDT for the closure flange region, and the LST of the closure studs is 70°F; therefore, the bolt-up temperature value used is 74°F.

The DAEC pressure-temperature operating limits in the Technical Specifications have been analyzed by GE and meet the requirements of 10 CFR 50, Appendix G, revised December, 1995.

In addition to Technical Specifications to conform to 10 CFR 50, Appendix G, the test specimen withdrawal requirements have been modified to conform to 10 CFR 50, Appendix H and the Boiling Water Reactor Vessel and Internals Project (BWRVIP) Integrated Surveillance Program (ISP). See Section 5.3.1.6.

5.3.1.6 Material Surveillance 5.3.1.6.1 DAEC-Specific Material Surveillance Program NOTE: The following information regarding the previous DAEC plant-specific program is included for information and is HISTORICAL. See Section 5.3.1.6.2 for a discussion of the current integrated surveillance program.

The material surveillance test program uses a series of Charpy V-notch impact specimens and tensile specimens from the base metal of the reactor vessel, weld heat-UFSAR/DAEC-1 5.3-7 Revision 20 - 8/09 affected zone metal, and weld metal from a reactor steel joint that simulated a welded joint in the reactor vessel. The specimens and neutron monitor wires were placed near core midheight adjacent to or near the reactor vessel wall as access permits, so that the neutron exposure is similar to that of the vessel wall. The specimens were installed at

startup or just before full-power operation. Selected groups of specimens are removed at intervals over the lifetime of the reactor and are tested to compare mechanical properties with the properties of control specimens that are not irradiated.

The DAEC-specific surveillance program for the reactor vessel is described in Reference 3 and in the following paragraphs. Additional information is provided in

References 4, 5 and 6.

This surveillance program did not conform identically to ASTM E-185-66 or its revision, ASTM E-185-70, "Recommended Practice for Surveillance Tests for Nuclear

Reactor Vessels."

The following is a comparison of the DAEC surveillance program with those portions of ASTM E-185-70 that the DAEC program did not totally coincide with. Referenced paragraph numbers correspond to paragraph numbers in ASTM E-185-70.

Test Material (Paragraph 3.1)

The test specimens were taken from a plate sample of the same heat as the wall plates in the reactor core region. The sample plate was welded with the same material and by the same procedure as a butt weld in the core region.

Fabrication History (Paragraph 3.1.1)

The test plate represents all of the fabrication processes to which the vessel plate was subjected except for forming, which has an insignificant effect on the vessel plate

properties.

Test Specimens (Paragraph 3.1.2)

Test specimens were taken from the test plate to represent the base metal, heat-affected zone, and weld material. The plate ma terial was not tested before selection since this pretesting would have imposed a large material and test cost on the surveillance program. The weld procedures and materials duplicated actual fabrication. The specimens were located vertically in the highest fluence area. Circumferentially, the specimens were located where access dictates, not necessarily at the highest fluence. One extra baseline set of specimens has been retained as spares. All specimens are identified, and complete documentation is available.

Chemical Composition (Paragraph 3.1.3)

Since specimens were taken from each heat of actual plate material, the chemical analysis of this material is on record.

UFSAR/DAEC-1 5.3-8 Revision 20 - 8/09 Type of Specimens (Paragraph 3.2)

The surveillance test specimens conform to ASTM E-185-70 requirements, except that the heat-affected zone impacts have the notch at the fusion line instead of 1/32 in. away. The weld material tensile specimen is oriented parallel to the weld. All other specimens are oriented parallel to the plate-rolling direction, transverse to the weld.

The impact notch is perpendicular to the plate surface.

Number of Specimens (Paragraph 3.3)

The number and types of specimens used in this surveillance program are given in Table 5.3-2. There are equal numbers of base metal, heat-affected zone, and weld specimens. For the establishment of the baseline, the program was based on 12 impact specimens per test set, since experience indicated that this quantity was adequate.

Correlation Monitors (Paragraph 3.4)

Correlation monitors were not used since this was a surveillance program, not a research and development program.

Location of Specimens (Paragraph 4.1)

The specimens were located as close as possible to the zone of highest fluence. The test plate duplicated the vessel material, and the specimens were placed as close as practical to the vessel wall to best duplicate the vessel wall conditions.

Accelerated or Reduced Irradiation (Paragraph 4.2)

Accelerated exposures were not used.

Thermal Control Specimens (Paragraph 4.3)

Thermal controls were part of earlier test programs, and after reviews of results, the controls have been discontinued.

Test Capsules (Paragraph 4.4)

The BWR is essentially a constant-temperature system; therefore, no temperature monitoring was employed. The specimens were hermetically sealed in an inert gas environment in a thin-wall stainless steel capsule that is not buoyant and does not present any problems in removing the irradiated capsules. All specimens were encapsulated in tight containers, and tensile specimens had aluminum spacers to keep gamma heating as close as possible to vessel wall conditions. If it became necessary, the out-of-reactor spare specimens could have been encapsulated and placed in a wall basket as a replacement for one group of the initial in-reactor specimens.

UFSAR/DAEC-1 5.3-9 Revision 20 - 8/09 Corrosion-Resistant Reactor Vessel Materials (Paragraph 4.5)

The vessel wall and all test specimens are low-alloy ferritic steel.

Significance (Paragraph 5.1)

Dosimeters were a part of the specimens to measure flux. Irradiation-induced temperature was of no consequence and was not measured. The evaluation of the radiation spectrum is a development, rather than a surveillance function.

Neutron Flux Dosimeters (Paragraph 5.2)

Iron, nickel with known cobalt content, and copper were used as flux monitors. One of each was included in each impact specimen capsule. In addition, one separate removable flux dosimeter was included.

Tension Tests and Notched Bar Impact Tests (Paragraphs 6.7, 7.1, and 7.2.1)

The tension test methods recommended by GE were not in complete conformance with ASTM E-184.

The surveillance program and test interpretation are based on 30 ft-lb Charpy impact. This data would indicate significant changes in NDT temperature if any occurred.

The tensile and impact capsules were placed in three baskets, fastened to a holder, and suspended from a bracket on the reactor vessel inner wall approximately 120

degrees apart.

There are 37 spare impact specimens and 12 tensile out-of-reactor spare specimens.

The surplus base metal is approximately 12 by 21 by 4-11/16 in. The surplus weld sample plate is approximately 6 by 33 by 4-11/16 in. The surplus plates, if it becomes necessary, can be made into specimens with the following dimensions:

Charpy V-notch specimen - 2.1 by 0.39 by 0.39 in.

Tensile specimen - 0.25 in. in diameter by 3 in. long

In addition to the capsule dosimeter, one basket had a special holder with a capsule containing iron and copper dosimeter wire. This special dosimeter could be removed independently of the surveillance samples.

5.3.1.6.2 Intregrated Surveillance Program and Test Results

Withdrawal Schedule

Test specimens of the reactor vessel base, weld and heat affected zone metal were installed in the reactor vessel adjacent to the vessel wall at the core midplane level at the UFSAR/DAEC-1 5.3-10 Revision 20 - 8/09 start of operation. A withdrawal of specimens was performed in accordance with the following:

Withdrawal Period (Approx. effective full power years) Estimated Max. Fluence @ 1/4 T (10 18 nvt> 1 MeV) 6 15 0.7 1.2 Future specimen withdrawal is in accordance with the Boiling Water Reactor Vessel and Internals Project Integrated Surveillance Program.

The program for implementation of the scheduling, withdrawal, and testing of the material surveillance specimens is governed and controlled by the Boiling Water Reactor Vessel and Internals Project (BWRVIP) BWRVIP-86-A, "BWR Vessel and Internals Project Updated, BWR Integrated Surveillance Program (ISP) Implementation Plan" (Reference 11). The BWRVIP Integrated Surveillance Program (ISP) complies with the requirements of 10 CFR 50, Appendix H. The specimens will be pulled in accordance with the test matrix included in BWRVIP-86-A.

A neutron fluence calculation methodology which has been approved by the NRC staff and conforms with U.S. Nuclear Regulatory Commission Regulatory Guide 1.190, "Calculation and Dosimetry Methods for Determining 'Pressure Vessel Neutron Fluence", will be used for the determination of neutron fluence values for the DAEC.

First Surveillance Capsule The first surveillance capsule at the 288

° location was withdrawn after 5.9 effective full power years (Cycle 7) for testing. It contained 24 Charpy V-notch specimens, six tensile specimens and six flux wires. The test results are presented in

Reference 3. These results are superceded by those results of the Second Surveillance Capsule which is summarized below and contained in Reference 6.

Second Surveillance Capsule The second surveillance capsule at the 36° location was removed at approximately 14.7 EFPY in October 1996 (end of Cycle 14). The capsule contained 9 flux wires for neutron fluence measurement and 36 Charpy and 8 tensile test specimens for material property evaluations. The flux wires were evaluated to determine the fluence experienced by the test specimens. Charpy V-Notch impact testing and uniaxial tensile testing were performed to establish the properties of the irradiated surveillance materials.

The 36° azimuth position surveillance capsule was removed and shipped to VNC.

The flux wires and Charpy V-Notch and tensile test specimens removed from the capsule were tested according to ASTM E185-82. The methods and results of the testing are presented in Reference 6. This evaluation was re-performed to incorporate ASME Code

Case N-640 and revised fluence (Reference 7). The fluence was calculated in accordance UFSAR/DAEC-1 5.3-11 Revision 20 - 8/09 with GE Licensing Topical Report NEDC-32983P, which has been approved by the NRC in Reference 8. The evaluation was used to generate Pressure-Temperature Limit Curves (Reference 9). The significant results of the evaluation are below:

a. The second surveillance capsule contained 9 flux wires: 3 copper (Cu), 3 nickel (Ni), and 3 iron (Fe). There were 36 Charpy V-Notch specimens in the capsule:

12 each of plate material, weld material, and heat affected zone (HAZ) material. The 8 tensile specimens removed consisted of 3 plate, 2 weld, and 3 HAZ metal specimens.

b. The curves of irradiated and unirradiated Charpy specimens established the 30 ft-lb shifts. After the first capsule specimens were tested, the weld material showed a 2.5°F shift and a 2.7 ft-lb increase in USE (2.7% increase). The plate material

showed a 41.8°F shift and a 0.7 ft-lb increase in USE (0.4% increase). The HAZ materials showed a 2.9°F shift and a 8.2 ft-lb increase in USE (7.1% increase).

After the second capsule specimens were tested, the weld material showed a 16.1°F shift and a 3.4 ft-lb decrease in USE (3.4% decrease). The plate material

showed a 77°F shift and a 12.2 ft-lb decrease in USE (10.5% decrease).

c. The measured shifts of 77°F for the plate material and 16.1°F for weld material, for a fluence of 1.1x10 18 n/cm 2 , were within the Reg. Guide 1.99, Rev. 2 range predictions (RT NDT+/-2) of 15°F to 83°F and -44°F to 68°F for plate and weld material, respectively. The best estimate chemical composition for the surveillance materials was used for this calculation.

d. The irradiated tensile specimens were tested at room temperature, reactor operating temperature (550°F), and at 185°F for the additional base and HAZ weld specimens. Unirradiated and first capsule testing results were available for comparison.

e. The peak RPV ID fluence used in the P-T curve evaluation is 4.17E18 n/cm 2 for the entire plant life. This fluence applies to the lower-intermediate plates and

longitudinal welds. The fluence is adjusted for the lower plates and longitudinal

welds and the girth weld based upon an attenuation factor of 1.18; hence, the peak ID surface fluence for these components is 3.55E18 n/cm

2. Similarly, the fluence is adjusted for the N2 (Recirculation Inlet) Nozzle based upon an attenuation factor of 5.46; hence the peak ID surface fluence used for this component is UFSAR/DAEC-1 5.3-12 Revision 19 - 9/07 7.64E17 n/cm

2. The same method is applied to the N16 (Instrumentation) Nozzle, which has an attenuation factor of 3.7, resu lting in a peak ID surface fluence of 1.13E18 n/cm

2.

f. The adjusted reference temperature (ART=Initial RT NDT + RT NDT + Margin) was predicted for beltline materials, based on the methods of Reg. Guide 1.99, Rev. 2.

g. An update of the beltline material USE values at 32 EFPY was performed using the Reg. Guide 1.99, Rev. 2 methodology. The Equivalent Margin Analyses demonstrate that the 10CFR50, Appendix G safety requirements are satisfactorily met for the DAEC.

h. P-T curves were developed with incorporation of ASME Code 1995 edition with 1996 addenda including Cases N-640 methodology and with current evaluation and the

effect of extended power uprate for three r eactor conditions: pressure test (Curve A), core not critical heatup and cooldown (Curve B), and core critical operation (Curve C) which are valid for up to 32 EFPY of operation. The P-T curves are beltline (N2 Recirculation Inlet Nozzle) limited above 240 and 230 psig for Curve A for 25 and 32

EFPY, respectively, and above 30 psig for Curve B for both 25 and 32 EFPY. The P-

T curves as shown in Figure 5.3-1 include a set of A curves established at

heatup/cooldown rate of 20 °F/hr. The P-T curves as shown in Figure 5.3-1 include a

set of B and C curves evaluated at a heatup/cooldown rate of 100 °F/hr.

i. The requirement of 10 CFR50 Appendix G deal with vessel design life conditions and with limits of operation designed to prevent brittle fracture. Based on the

evaluation of current analysis (Extended Power Uprate), the following conclusions are made:

The values of ART and USE for the reactor vessel beltline materials are expected to remain within the limits of Reg. Guide 1.99, Rev. 2 and Appendix G of

10CFR50 (<200°F and >50 ft-lbs, respectively) for at least 32 EFPY of operation.

5.3.1.7 Reactor Vessel Fasteners

The vessel top head is secured to the reactor vessel by studs, nuts, and bushings

that are designed to be tightened with a stud tensioner. The vessel flanges are sealed by

two concentric Inconel-718 seal rings designed for no detectable leakage through the

inner or outer seal at any operating condition including the following:

1. Cold hydrostatic pressure test at the design pressure.

2. Heating to operating pressure and temperature at a maximum rate of 100°F/hr.

To detect the lack of seal integrity, a 1-in. vent tap is provided in the area between the two seal rings, and a monitor line is attached to the tap to provide an indication of leakage from the inner seal ring seal. A 1-in. tap is also provided in the area outside the outer seal ring for use in monitoring leakage.

UFSAR/DAEC-1 5.3-13 Revision 18 - 10/05

5.3.2 OPERATING

PRESSURE AND TEMPERATURE LIMITS

Operating limits curves are required for the Technical Specifications for three reactor conditions: (a) system hydrostatic and leakage tests, (b) non-nuclear heatup or cooldown, and (c) core critical operation. The curves are established by requirements of

Section III, Appendix G, of the ASME Code and by 10 CFR 50, Appendix G. Figure 5.3-1 shows all three operating limits curves, including irradiation shift of the core beltline region curves to their positions at end of life (32 full power years).

5.3.2.1 Irradiation Effects on Core Beltline

The beltline contains the N2 Recirculation Inlet Nozzle and the N16 Instrumentation Nozzle, which represents a slight extension beyond the core region. This is determined by the location on the vessel where the fluence exceeds 1x10 17 n/cm 2. An evaluation of ART for all beltline plates, the N2 and N16 Nozzles, and several beltline welds was made for 32 EFPY.

Estimated maximum changes in RT NDT as a function of the end-of-life (32 full power years) fluence at the one-quarter thickness (1/4 T) depth of the vessel beltline materials are listed below.

Flux densities at the 288 and 36 degree surveillance capsule locations in the reactor pressure vessel were evaluated by testing flux wires removed with the surveillance capsule after Cycles 7 and 14 respectively.

The relationship between the capsule location and the peak flux location at the 1/4 T depth was determined by a combination of two-dimensional and one-dimensional flux distribution computer analyses.

The transition temperature shift due to irradiation was calculated in accordance with Regulatory Guide 1.99, Revision 2, taking into account the data from the surveillance testing. The results for the core beltline materials are tabulated below:

Plate N16 N2 Weld Limiting material chemistry 0.15% Cu, 0.65% Ni 0.18% Cu 0.85%Ni 0.18% Cu 0.84%Ni 0.03% Cu, 0.91% Ni End-of-life transition temperature shift 130.5°F 89.1°F 79.2°F 56.3°F Initial reference temperature 10°F 40°F 40°F -50°F End-of-life adjusted

reference temperature 140.5°F 129.1°F 119.2°F 6.3°F 1/4 T Fluence (n/cm 2) 3.19E+18 8.63E+17 5.85E+17 3.19E+18 UFSAR/DAEC-1 5.3-14 Revision 18 - 10/05 Since the predicted end-of-life adjusted reference temperatures are below 200°F, provisions to permit thermal annealing of the reactor pressure vessel in accordance with

Paragraph IV.B of 10 CFR 50, Appendix G, are not required.

5.3.2.2 Temperature Limit for Boltup and Pressurization

The minimum temperature for boltup and pressurization of 74°F was established

by adding 60°F to the RT NDT for the limiting closure flange region. The 60°F added to the RT NDT for boltup and pressurization is a requirement of the ASME Code applicable to the original reactor pressure vessel design work. However, Appendix G of the 1995 ASME Code with 1996 Addenda,Section XI requires a minimum permissible temperature of RT NDT for boltup and pressurization up to 20% of hydrotest pressure (Paragraph G-2222c). The 60°F added to the RT NDT is extra margin included because the closure flange region stress analysis assumes a 0.24-in. flaw (which is detectable) instead

of a 1/4 T flaw. In the case of the core critical operation curve C in Figure 5.3-1, 10 CFR 50, Appendix G, Table 1 requires a minimum permissible temperature of (RT NDT + 60°F) or 74°F.

The minimum temperature for boltup prior to pressurization must be 74°F or greater. Boltup at 74°F satisfies the requirement s of the original code of construction and exceeds the 1995 ASME Code with 1996 Addenda requirements. A sufficient number of studs may be partially tensioned to seal the closure flange O-rings for the purpose of raising reactor water level above the closure flanges, in order to assist in warming the flanges and adjacent shells to a minimum temperature of 74°F before they are stressed by

the full intended bolt preload.

5.3.2.3 Temperature Limits for System Hydrostatic or System Leakage Tests

The fracture toughness analysis for system pressure tests results in the curve labeled A shown in Figure 5.3-1. The N2 Recirculation Inlet Nozzle is the limiting material for the beltline region for 32 EFPY. The beltline pressure test P-T curves are calculated in the same manner as the Feedwater Nozzle pressure test P-T curves, using the N2-specific geometry. The initial RT NDT for the N2 Recirculation Inlet Nozzle materials is 40°F. The generic pressure test P-T curve is applied to N2 Nozzle curve by shifting the P vs. (T-RT NDT) values for the Feedwater Nozzle to reflect the ART value for the N2 Nozzle (119.2°F).

5.3.2.4 Temperature Limits for Non-Nuclear Heatup/Cooldown

The fracture toughness analysis for non-nuclear heatup and cooldown results in Curve B shown in Figure 5.3-1. The N2 Recirculation Inlet Nozzle is the limiting material for the beltline region for 32 EFPY. The beltline core not critical P-T curves are calculated in the same manner as the Feedwater Nozzle core not critical P-T curves, using the N2-specific geometry. The initial RT NDT for the N2 Recirculation Inlet Nozzle UFSAR/DAEC-1 5.3-15 Revision 18 - 10/05 materials is 40°F. The generic core not critical P-T curve is applied to the N2 Nozzle curve by shifting the P vs. (T-RT NDT) values for the Feedwater Nozzle to reflect the ART value for the N2 Nozzle (119.2°F). The Curve B analysis assumes a normal heatup or cooldown rate of 100°F/hr and it also includes th e effects of cold water injections into the nozzles and other operational transients. The resulting temperature gradients and thermal

stress effects are included.

5.3.2.5 Temperature Limits for Core Critical Operation 10CFR50, Appendix G, Table 1 requires that core critical P-T limits be 40

°F above any Curve A or B limits when pressure exceeds 20% of the pre-service system hydrotest pressure. Curve B is more limiting that Curve A, so limiting Curve C values are at least Curve B plus 40

°F for pressures above 312 psig.

10CFR50, Appendix G, Table 1 indicates that the allowed initial criticality at the closure flange region is (RT NDT + 60°F) at pressures below 312 psig. This requirement makes the minimum criticality temperature 74

°F, based on an RT NDT of 14°F. In addition, above 312 psig the Curve C temperature must be at least the greater of RT NDT of the closure region + 160

°F or the temperature required for the hydrostatic pressure test (Curve A at 1035 psig.) This requirement does not cause a temperature shift in Curve C at 312 psig due to the presence of the N2 Nozzle discontinuity.

5.3.2.6 Operating Procedures

For most reactor operating conditions, coolant pressure and temperature are at saturation conditions, which are well into the acceptable operating area (to the right of the P-T curves). The operations where P-T curve compliance is typically monitored closely are planned events, such as vessel boltup, leakage testing and startup/shutdown operations, where operator actions can directly influence vessel pressures and temperatures.

The most severe unplanned transients relative to the P-T curves are those that result from SCRAMs, which sometimes include recirculation pump trips. Depending on operator responses following pump trip, there can be cases where stratification of colder water in the bottom head occurs while the vessel pressure is still relatively high.

Experience with such events has shown that operator action is necessary to avoid P-T curve exceedance, but there is adequate time for operators to respond.

In summary, there are several operating conditions where careful monitoring of P-T conditions against the curves is needed:

• Head flange boltup

• Leakage test (Curve A compliance )

• Startup (coolant temperature change of less than or equal to 100°F in one hour period heatup)

UFSAR/DAEC-1 5.3-16 Revision 18 - 10/05

• Shutdown (coolant temperature change of less than or equal to 100°F in one hour period cooldown)

• Recirculation pump trip, bottom head stratification (Curve B compliance)

The average rate of reactor coolant temperature change during normal heatup and cooldown is limited to 100°F in any 1-hr period Figure 5.3-1, Curves B & C. During emergency and faulted conditions, the cooling rates may exceed this value as a result of rapid blowdown due to postulated valve malfunctions or rupture accidents.

A record is maintained of the actual reactor vessel transients that occur versus the design number of transients listed in Table 5.3-7. The record is updated at the end of

each fuel cycle.

UFSAR/DAEC-1 5.3-17 Revision 21 - 5/11

5.3.3 REACTOR

VESSEL INTEGRITY

This section contains information about vessel integrity that may not be contained in other sections. It describes some of the considerations in achieving reactor vessel

safety and describes factors contributing to vessel integrity.

5.3.3.1 Design

The reactor vessel design pressure of 1250 psig is determined by an analysis of margins required to provide a reasonable range for maneuvering during operation, with additional allowances to accommodate transients above the operating pressure (1025

psig at the level of the top head flange) without causing the operation of the safety valves. The design temperature for the reactor vessel (575°F) is based on the saturation temperature of water corresponding to the design pressure.

To withstand external and internal loadings while maintaining a high degree of corrosion resistance, a high-strength low-alloy steel is used as a base metal with an

internal cladding of stainless steel applied by weld overlay. The use of the ASME Code,Section III, Class A, pressure vessel code design criteria ensures that a vessel designed, built, and operated within its design limits has an extremely low probability of failure due to any known failure mechanism.

Reactor vessel data are contained in Tables 5.3-5 and 5.3-6. The reactor vessel is

designed for a 60-year life. The reactor vessel is also designed for the transients that could occur during the 60-year life as indicated in Table 5.3-7.

Extensive tests have established the magnitude of changes in the NDT temperature as a function of the integrated neutron dosage. Figure 5.3-2 presents

pertinent test data for SA-302B/SA-533B Class 1 steel and plots the change in ductile to brittle transition temperature as a function of integrated neutron flux (nvt). The 30 ft-lb refers to the energy absorbed by the Charpy V-notch sample at the test (transition) temperature. The upper two curves apply to thick-walled pressure vessels, and the lower

curve is for the wall thickness range representative of this reactor vessel .

Detailed stress analyses have been made on the reactor vessel for both steady-state and transient conditions with respect to material fatigue. The results of these transients are compared to allowable stress limits. Requiring the coolant temperature in an idle recirculation loop to be within 50°F of the operating loop temperature before a recirculation pump is started ensures that the changes in coolant temperature at the reactor vessel nozzles and bottom head region are acceptable.

Heating and cooling transients throughout plant life at uniform rates of 100°F/hr were considered in the temperature range of 100 to 549°F and were shown to be within the requirements for stress intensity and fatigue limits of Section III of the ASME Code (1971 Edition including Summer 1972 Addenda).

UFSAR/DAEC-1 5.3-18 Revision 18 - 10/05 The coolant in the bottom of the vessel is at a lower temperature than that in the

upper regions of the vessel when there is no recirculation flow. This colder water is forced up when recirculation pumps are started. This will not result in stresses that exceed ASME Code,Section III limits when the temperature differential is not greater than 145°F.

The minimum temperature of the fluid retained by a component can be used as a conservative estimate of metal temperature in evaluating the margin from the temperature at which the NDT properties were measured. Additional margin can usually be shown by calculating the temperature of the metal for the condition and area of concern.

During operation when pressure depends on temperature, brittle failure of the

vessel is not possible until the neutron fluence of the reactor vessel reaches a value of the

order of 10 20 nvt. This value is approximately 20 times the maximum neutron fluence conservatively calculated during the lifetime of the DAEC plant.

5.3.3.2 Materials of Construction

In addition to the minimum requirements of the ASME Code, the following precautions are taken and tests made either to ensure that the initial NDT temperature of the reactor vessel material is low or to reduce the sensitivity of the material to irradiation

effects:

1. The material is selected to produce as fine a grain size as practical. It is an objective to maintain a grain size of five or finer.

2. Drop-weight impact tests are performed on each heat and heat treatment charge of all low-alloy steel plate material in its as-fabricated condition.

3. Drop-weight impact tests are made on the weld metal, the heat-affected zone of the base metal, and the base metal of the weld test plates simulating seams. If different welding procedures are used for nozzle welds, drop-weight tests of similarly prepared coupons are made. The NDT temperature test criteria for the weld and heat-affected zone of the base material are the same as for the unaffected base metal.

4. The actual NDT temperature of the plates opposite the center of the

reactor core is determined. In other areas, it is sufficient to demonstrate that the two drop-weight test specimens do not break at 10°F above the design NDT temperatures. The area of the vessel opposite the core is fabricated

entirely of plate and is not penetrated by nozzles nor are there any other

structural discontinuities in this area that would act as stress risers.

The head and vessel flanges are low-alloy steel forgings. The sealing surfaces of

the reactor vessel head and shell flanges are weld overlay clad with austenitic stainless UFSAR/DAEC-1 5.3-19 Revision 18 - 10/05 steel similar to the vessel that consists of a minimum of two layers and minimum of 0.25 in. total thickness after all machining, including the area under seal grooves. The first layer is deposited with a composition equivalent to ASTM A-371, Type ER309, and subsequent layers have a composition equivalent to ASTM A-371, Type ER308, except

that the carbon content does not exceed 0.035% at the finished surface.

The vessel nozzles (Figure 5.3-3) are low-alloy steel forgings made in accordance with ASTM A-508 as modified by ASME Code Case 1332, Paragraph 5. Nozzles of 3 to 9 in. nominal size or larger are full-penetration welded to the vessel. Nozzles of less than 3-in. nominal size may be partial penetration welded as permitted by ASME Code,Section III. Nozzles that are partial-penetration welded are nickel-chromium-iron forgings made in accordance with ASME SB-166 or SB-167 as modified by Code Case

1420.

The reactor vessel including all nozzles was reviewed for compliance with

Paragraph N-331, Ductile-Brittle Transition Tests, Section III, ASME Code, 1965 Edition plus addenda through Summer 1967 Addenda. It was determined that the vessel and its components, with the exception of the feedwater nozzle safe end, met the code

criteria.

The materials for the feedwater nozzles and safe ends were ordered on the basis of a 100°F lowest service metal temperature. The ASME Code requires all material to have impact tests 60°F below the lowest service metal temperature. The code requirements for Charpy V-notch energy on the A-508 Class 2 nozzle is 30-ft-lb average for three test specimens. The Charpy V-notch energy requirement for the A-508 Class 1 safe ends is 20 ft-lb average for three test specimens.

The 90°F water steady-state flow case was determined to be the governing normal service condition for the original design of these nozzles because of a thermal sleeve

design that exposed the safe end and nozzle to a bypass flow of 90°F water. Therefore, the original design did not meet the ASME Code requirements, since the impact tests were performed at +40°F based on 100°F water, instead of +30°F based on +90°F

water.

In addition to the governing normal service condition described above, feedwater

nozzles N4C and N4D were also evaluated for the abnormal condition of RCIC injection. The conservative conditions assumed for this evaluation were 200-gpm flow per nozzle of 40°F water for an indefinite time. RCIC flow would probably be switched from the 40°F condensate storage supply to the 100°F RHR system within 30 min, but for this analysis, it was assumed the RCIC flow would continue to be from the condensate storage supply. The initial warm leg of water in the feedwater and RCIC piping was also

conservatively neglected.

UFSAR/DAEC-1 5.3-20 Revision 18 - 10/05 According to tests made on the original safe-end material, the average Charpy energy values at the temperatures of primary concern are the following:

Test Temperature (°F) Energy (ft-lb) 40 33 10 20 The 40°F water steady-state 200 gpm per nozzle flow case analysis indicated that the limiting temperature is 68°F in the 1-in. length of the original safe-end material. The 58°F margin between the 68°F steady-state metal temperature and the 10°F 20-ft-lb temperature is considered to be technically adequate for this abnormal condition.

Therefore, RCIC injection to the vessel through the feedwater nozzle is appropriate.

After the consideration of several alternatives, the feedwater thermal sleeve detail was changed by welding the thermal sleeve directly to the safe end. This detail prevents the flow of cold water behind the thermal sleeve, and therefore the nozzle forging temperature is maintained above 100°F for turbine roll. The original safe ends except for a short length (approximately 1 in.) adjacent to each nozzle have been removed.

In addition, a portion of the safe-end that could be exposed to the 90°F water flow

was replaced with a new safe end that has a minimum of 20 ft-lb Charpy V-notch impact properties at -20°F.

With these changes in the feedwater safe-end detail, the 90°F steady-state flow case will still govern the lowest service metal temperature of the nozzle and remaining

portion of the original safe end. The 1-in. length of original safe-end material and the nozzle forging have Charpy impact tests made at +40°F. With the design change, the lowest calculated temperatures are 118°F in the nozzle forging and 108°F in the 1-in.

portion of the original safe end. This exceeds the requirements of the code.

After these changes were made, the feedwater nozzles were hydrostatically tested and the vessel was ASME Code stamped. The feedwater nozzle thermal sleeve design is

shown in Figure 5.3-4.

The vessel top head nozzles have flanges with small-groove facing. The drain nozzle is of the full-penetration weld design and extends 16 in. below the bottom outside

surface of the vessel. The recirculation inlet nozzles located as shown in Figure 5.3-3, feedwater inlet nozzles and core spray inlet nozzles have thermal sleeves similar to those

shown in the detail of Figure 5.3-4.

Nozzles connecting to stainless steel piping are clad on the interior to a minimum

thickness of 0.125 in. with stainless steel weld overlay equivalent to that used in the

vessel. Nozzles for connecting carbon steel piping are clad through at least the thickness of the vessel wall or one-half the diameter of the nozzle bore, whichever is less.

UFSAR/DAEC-1 5.3-21 Revision 18 - 10/05 The nozzle for the core differential pressure and liquid control pipe is designed with a transition so that the stainless steel outer pipe of the differential pressure and

liquid control line can be socket welded to the inner end of the nozzle and so that the

inner pipe passes through the nozzle. This design provides an annular region between the nozzle and the inner liquid control line to minimize thermal shock effects on the reactor vessel in the event that the use of the standby liquid control system is required.

The jet pump instrumentation penetration seal is welded directly to the outer end of the jet pump instrumentation nozzle. The stainless steel recirculation loop piping is welded to the outer end of the recirculation outlet and inlet nozzles. The main steam line piping is welded to the outer end of the steam outlet nozzle.

The piping attached to the vessel nozzle is designed, installed, and tested in accordance with the requirements of the ASME Code.

Thermocouple pads are located on the exterior of the vessel (see Table 5.3-6 and Figure 5.3-5). At each thermocouple location, two pads are provided--an end pad to hold the end of a 3/16-in.-diameter thermocouple and a clamp pad equipped with a set screw to secure the thermocouple.

5.3.3.2.1 Shroud Support

The reactor vessel shroud support is a cylindrical shell that surrounds the reactor core assembly and is designed so that stresses due to reactions at the shroud support are within limits given in Chapter 3. The design pressure differential across the shroud

support is 100 psi (higher pressure under the support) occurring at the vessel design temperature. The design of the shroud support also takes into account the restraining effect of the components attached to the support and weight and earthquake loadings.

The vessel shroud support and other internal attachments (jet pump riser support pads, guide rod brackets, steam dryer support brackets, dryer holddown brackets, feedwater sparger brackets, surveillance specimen brackets, and core spray brackets) are as shown

in Figure 5.3-6 and Table 5.3-6.

5.3.3.2.2 Reactor Vessel Support Assembly

The reactor vessel is laterally and vertically supported and braced to make it as rigid as possible without impairing the movements required for thermal expansion.

Where thermal requirements prohibit the use of rigid supports, spring anchors are employed to resist earthquake forces while allowing sufficient flexibility for thermal

expansion.

The reactor vessel is supported on a steel cylinder that is welded to the bottom of the reactor vessel and extends down and through the drywell shell and is embedded in the UFSAR/DAEC-1 5.3-22 Revision 18 - 10/05 reactor building mat. After the erection of the reactor vessel, a concrete pedestal is added, which is constructed monolithically with the steel support cylinder.

5.3.3.2.3 Vessel Stabilizers

The lateral loads from the vessel stabilizers and shield wall are transmitted to the drywell stabilizers by rigid struts extending from the top of the shield wall to the drywell

stabilizers.

The vessel stabilizers are connected between the reactor vessel and the top of the

shield wall surrounding the vessel to provide lateral stability for the upper part of the

vessel. Four stabilizer brackets are attached by full-penetration welds to the reactor

vessel at evenly spaced locations around the vessel below the flange. Each vessel

stabilizer consists of a gusset plate attached to the top of the shield, a clevis (a U-shaped piece of metal with ends perforated to receive a pin) pinned to the stabilizer bracket, and a spring-loaded drawbar between them. Two stabilizers are attached to each bracket and

apply tension in opposite directions. The stabilizers are evenly preloaded with tensioners

to the values of the residual loads shown in Table 5.3-5. The stabilizers are designed to permit radial and axial vessel expansion, to limit horizontal vibration, and to resist seismic and jet reaction forces.

5.3.3.2.4 Refueling Bellows

The refueling bellows form a seal between the reactor vessel and the surrounding primary containment drywell to permit flooding of the space (reactor well) above the vessel during refueling operations. The refueling bellows assembly (see Figure 5.3-3)

consists of a Type 304 stainless steel bellows, a backing plate, a spring seal, and a removable guard spring. The backing plate surrounds the outer circumference of the bellows to protect it and is equipped with a tap for testing and for monitoring leakage.

The self-energizing spring seal is located in the area between the bellows and the backing plate and is designed to limit water loss in the event of a bellows rupture by yielding to make a tight fit to the backing plate when subjected to full hydrostatic pressure. In the event that refueling bellows leakage is in excess of 5 gpm, an alarm will annunciate in the control room. The guard ring attaches to the assembly and protects the inner circumference of the bellows. The guard ring can be removed from above to inspect the bellows. The assembly is welded to the reactor bellows support skirt flange and the

reactor well seal bulkhead plate. The reactor bellows support skirt is welded to the

reactor vessel shell flange (see Figure 5.3-3), and the reactor well seal bulkhead plate bridges the distance to the primary containment drywell wall. A bellows seal of similar design forms a seal between the outside of the drywell and the outer portion of the reactor well. Six watertight hinged covers are bolted in place for normal refueling operation.

For normal operation, these covers are opened and removable air supply ducts and air return ducts permit the circulation of ventilation air in the region above the reactor well

seal bulkhead plate.

UFSAR/DAEC-1 5.3-23 Revision 18 - 10/05 5.3.3.2.5 Control Rod Drive Housings

The CRD housings are inserted through the CRD penetrations in the reactor vessel bottom head and are welded to the stub tubes extending into the reactor vessel (Figure 5.3-3). Each housing transmits a number of loads to the bottom head of the

reactor. These loads include the weight of a control rod and control rod drive, which are bolted to the housing from below (see Section 4.6), the weight of a control rod guide tube, one fuel support piece, and the fuel assemblies that rest on the top of the fuel

support piece (see Section 3.9.5). The housings are fabricated of Type 304 austenitic

stainless steel.

5.3.3.2.6 Control Rod Drive Housing Supports

The CRD housing support is designed to prevent a nuclear transient in the

unlikely event there is a CRD housing failure. This device consists of a grid structure below the reactor vessel from which housing supports are suspended. The supports allow only slight movement of the control rod drive or housing in the event of failure.

The CRD housing support is treated in detail in Section 3.9.4.

5.3.3.2.7 Incore Neutron Flux Monitor Housings

The incore neutron flux monitor housings are inserted up through the incore penetrations in the bottom head of the reactor vessel and are welded to the inner surface of the bottom head (Figure 5.3-3). An incore flux monitor guide tube is welded to the top of each housing (see Section 3.9.5). Either a source range monitor/intermediate range monitor drive unit or a local power range monitor is bolted to the seal ring flange at the bottom of the housing (see Section 7.6).

5.3.3.2.8 Reactor Vessel Insulation

The reactor vessel insulation has an average maximum heat-transfer rate of approximately 80 Btu/hr-ft 2 at the operating conditions of 550°F for the vessel and 135°F for the outside air. Insulation thicknesses vary in different regions of the vessel up to 4 in. maximum.

The cylindrical shell insulation is supported at three levels. The upper level supports have close-in insulation above them and standoff permanently installed insulation below them down through the intermediate support level to the lower support level. The lower supports have removable, hanging, standoff insulation below them.

The top head insulation consists of ver tical cylindrical sections, a flat annular ring, and a disk closing off the top of the smallest vertical cylinder. This insulation is mounted on a steel frame for easy removal as an assembly. The bottom head insulation is in the form of a disk and is permanently installed.

UFSAR/DAEC-1 5.3-24 Revision 18 - 10/05 Liquids containing chlorides are not used on any austenitic stainless steel parts of the insulation at any time.

5.3.3.3 Fabrication Methods

Quality control methods were used during the fabrication and assembly of the reactor vessel and appurtenances to ensure that the design specifications are met (see

Chapter 17 and Appendix 5A) .

The fabrication test program was carried out by the reactor vessel vendor on material representative of the formed, heat-treated, and fully fabricated vessel. Tests of base metal and welded joint were performed, and the results were reported during the early stages of vessel construction. Tensile specimens from the shell plate material are prepared for various thickness levels of the plate material. These specimens are tested at various temperatures per ASTM Specifications E-8 and E-21 to determine tensile

strength, yield strength, elongation, and reduction of area. Charpy V-notch impact specimens are prepared from base metal a nd tested per ASTM Specification E-23, Type A, to establish curves for determining the transition temperature at which 30 ft-lb of absorbed energy result in ductile fracture for various thickness levels of the plate material.

The quality control program for the field-fabricated DAEC reactor vessel was a continuing program involving the surveillance of GE, Iowa Electric, and the CB&I. The design and fabrication of the reactor vessel is of the highest quality practicable with

current technology. The reactor vessel was designed, analyzed, independently checked,

fabricated, and inspected in accordance with ASME Code,Section III, for Class A

nuclear vessels.

5.3.3.4 Inspection Requirements

Refer to Section 5.2.4.

5.3.3.5 Shipment and Installation

Field fabrication of the reactor vessel is discussed in Appendix 5A.

5.3.3.6 Operating Conditions

The reactor coolant system was cleaned and flushed before fuel was loaded initially. During the preoperational test program, the reactor vessel and reactor coolant system were given a hydrostatic test in accordance with code requirements at 125% of design pressure. The vessel temperature is maintained at a minimum of 60°F above the NDT temperature before pressuring the vessel for a test. A pressure test in accordance with the Inservice Inspection Plan is made following each removal and replacement of

the reactor vessel head. Other preoperational tests include calibrating and testing the

reactor vessel flange seal ring leakage detection instrumentation, adjusting reactor vessel UFSAR/DAEC-1 5.3-25 Revision 18 - 10/05 stabilizers, checking all vessel thermocouples, and checking the operation of the vessel flange stud tensioner.

During the startup test program, the reactor vessel temperatures were monitored during vessel heatup and cooldown to ensure that thermal stress on the reactor vessel was

not excessive during startup and shutdown.

5.3.3.7 Inservice Surveillance

For the inservice inspection program for the DAEC vessel, see Section 5.2.4.

UFSAR/DAEC-1 5.3-26 Revision 20 - 8/09 REFERENCES FOR SECTION 5.3

1. L. C. Hsui, An Analytical Study on Brittle Fracture of GE-BWR Vessel Subject to the Design Basis Accident (LOCA), NEDO-10029, 1969.

2. General Electric Company, Duane Arnold Energy Center Reactor Pressure Vessel Fracture Toughness Analysis to 10 CFR 50, Appendix G, May 1983, NEDC-30839, December 1984.

3. General Electric Company, Duane Arnold Energy Center Reactor Pressure Vessel Surveillance Materials Testing , NEDC-31166-1, Revision 1, 1986.

4. NEDO-32205, "BWR Owners' Group Topical Report on Upper Shelf Energy Equivalent Margin Analysis", dated March 21, 1994.

5. Letter from J. Franz (IES) to T. Murley (NRC) dated July 30, 1993, NG-93-2800, Response to Request for Additional Information Regarding

Response to Generic Letter (GL) 92-01, Revision 1, "Reactor Vessel

Structural Integrity."

6. General Electric Company, Duane Arnold RPV Surveillance Materials Testing and Analysis , GE-NE-B1100716-01, Revision 0, July 1997.

7. General Electric Company, Pressure-Temperature Curves for Duane Arnold Energy Center, GE-NE-A 22-00100-08-01-R2, Revision 2, August 2003. 8. Letter, S. A. Richards, USNRC to J. F. Klapproth, GE-NE, "Safety Evaluation for NEDC-32983P, Genera l Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation (TAC No. MA9891)",

MFN 01-050, September 14, 2001.

9. Amendment No. 253 regarding Pressure and Temperature Limit Curves, dated August 25, 2003.

10. Not Used 11. Boiling Water Reactor Vessel and Internals Project (BWRVIP) BWRVIP-86-A, "BWR Vessel and Internals Project, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan", EPRI Technical Report 1003346, dated October 2002.

12. Not Used.

UFSAR/DAEC-1 5.3-27 Revision 20 - 8/09

13. Not Used.

14. Letter to Mr. Carl Terry, BWRVIP Chairman, from Mr. William H. Bateman, Nuclear Regulatory Commission, dated December 16, 2002, subject: 'NRC Staff Review of BWRVIP-86-A, "BWR Vessel and Internals Project, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan."'

UFSAR/DAEC-1 T5.3-1 Revision 12 - 10/95 Table 5.3-1 Sheet 1 of 3 REACTOR PRESSURE VESSEL MATERIALS

Component Form Material Specification (ASTM/ASME)

Heads, shell Rolled plate Low alloy steel SA533, Grade B, Class 1 Closure flange Forged rings Low alloy A508, Class 2, cc 1332

Cladding (excluding

flange seal

surface) Weld overlay Austenitic stainless steel SA371 Type ER309, Type ER308 (and

finished surface

carbon content 0.08% maximum)

Nozzles (See additional pages of this table)

CRD stub tubes Tubes Inconel SB167, cc 1420

CRD housings Pipe Austenitic stainless steel SA312, Type 304 (tubing and piping);

SA182, Grade F, Type 304 (flanges) Incore housings Pipe Austenitic Stainless steel SA213, Type 304 (tubing and piping);

SA182, Grade F, Type

304 (flanges)

UFSAR/DAEC-1 T5.3-2 Revision 12 - 10/95 Table 5.3-1 Sheet 2 of 3 REACTOR PRESSURE VESSEL MATERIALS Nozzle Number Component Specification (ASTM/ASME)

Code Case N1A/B Recirculation outlet Nozzle Safe end SA-508, Class 2

SA-336, F8 (a ) N2A/H Recirculation inlet Nozzle Safe end

Safe end extension Thermal sleeve Thermal sleeve extension SA-508, Class 2

SB-166 SA-336, F8

SB-168 SA-240, Type 304L (a) N3A/D Steam outlet Nozzle Safe end SA-508, Class 2

A-508, Class 1 (a) (b ) N4A/D Feedwater Nozzle Safe end

Safe end extension Thermal sleeve Thermal sleeve extension SA-508, Class 2

SA-508, Class 1

SA-508, Class 1

SB-166 SA-336, F8 (a) (b ) (b) N5A/B Core Spray Nozzle Safe end

Safe end extension Thermal sleeve SA-508, Class 2

SB-166 SA-336, F8

SA-336, F8 (a) N6A/B A - blind flanged B - head instrumentation

Nozzle Flange SA-508, Class 2

SA-508, Class 1 (a) (b) N7 Vent Nozzle Flange SA-508, Class 2

SA-508, Class 1 (a) (b)

Note: For these cases, liquid penetrant was allowed in lieu of magnetic particle inspection on inside diameters less than 4 in.

a Code Case 1332-3, Paragraph 5.

b Code Case 1332-4, Paragraph 1.

UFSAR/DAEC-1 T5.3-3 Revision 13 - 5/97 Table 5.3-1 Sheet 3 of 3 REACTOR PRESSURE VESSEL MATERIALS Nozzle Number Components Specification (ASTM/ASME)

Code Case N8A/B Jet pump instrumentation

Nozzle Safe end

SA-508, Class 2

SA-336, F8 (a ) N9 CRD hydraulic system return Nozzle Safe end

SA-508, Class 2

SA-336, F8 (a) N10 Core P and liquid control Nozzle Safe end

SA-508, Class 2

SA-336, F8 (a) N11A/B 2-in. instrumentation N12A/B Nozzle SA-508, Class 2 (a) N16A/B Safe end SA-336, F8 N13 1-in. seal leak detection N14 Nozzle Pipe extension SB-166 A-508, Class 1 (b ) N15 Drain Nozzle Pipe extension SA-508, Class 1

SA-508, Class 1 (b) (b)

Note: For these cases, liquid penetrant was allowed in lieu of magnetic particle inspection on inside diameters less than 4 in.

a Code Case 1332-3, Paragraph 5.

b Code Case 1332-4, Paragraph 1.

UFSAR/DAEC-1 T5.3-4 Revision 18 - 10/05 Table 5.3-2 NUMBER OF SPECIMENS BY SOURCE

Specimen Base Weld Heat- Affected Zone Suggested Withdrawal Period a Actual Specimen Withdrawal a

Unirradiated

baseline tested C b T c 14 3 12 3 12 0

--

--

--

--

In-reactor C 12 12 12 15 14.7 T 3 2 3 15 14.7 C 8 8 8 6 5.9 T 2 2 2 6 5.9 C 8 8 8 32 T 2 2 2 32

RCd, f, g 16 8 12 9 RTe, f, g 3 3 0 9

Out-of-reactor spares C 11 13 13 -- -- T 3 3 6 -- --

a Effective full power years.

b C is standard Charpy V-notch impact bar.

c T is 1/4 in. gauge diameter tensile specimen.

d RC is Reconstituted Charpy V-notch impact bar.

e RT is Reconstituted 0.113 inch minimum diameter tensile specimen.

f Reconstituted specimens fabricated from ten specimens removed at the end of cycle 7 (5.9 effective full power years) and re-insta lled at the beginning of cycle 9. Therefore, this set of reconstituted specimens does not reflect the irradiation effects of cycle 8.

g These reconstituted reactor specimens were re-installed for augmented testing and/or plant life extension testing and are not required to meet the material surveillance test program.

UFSAR/DAEC-1 T5.3-5 Revision 17 - 10/03 Table 5.3-3 Deleted UFSAR/DAEC-1 T5.3-6 Revision 17 - 10/03 Table 5.3-4 Deleted UFSAR/DAEC-1 T5.3-7 Revision 12 - 10/95 Table 5.3-5 REACTOR VESSEL DATA Parameter Value Reactor vessel

Inside diameter, in. (min) 183 Inside length, ft-in. 66 - 4 Design pressure and temperature, psig at ºF 1250 at 575

Reactor vessel support

Design horizontal seismic shear, kip 680 Design seismic moment, ft-kip 15,400

Vessel nozzles (number), in.

Recirculation outlet (two) 30 to 22 Steam outlet (four) 20 Recirculation inlet (eight) 10 Feedwater inlet (four) 10 Core spray inlet (two) 8 Instrument (two) 6 Control rod drive (89) 6 Jet pump instrumentation (two) 4 Vent (one) 4 Instrumentation (six) 2 CRD hydraulic system return (one) 2-1/2 Core differential pressure and standby 2 liquid control (one)

Drain (one) 2 Incore flux instrumentation (30) 2 Head seal leak detection (two) 1

Vessel stabilizers

Design seismic load (per stabilizer), kip 200 Design preload (per stabilizer), kip 215

Weights, lb

Vessel 716,200 Top head 99,800 Operating weight 1,797,000 UFSAR/DAEC-1 T5.3-8 Revision 12 - 10/95 Table 5.3-6 REACTOR VESSEL ATTACHMENTS Item Quantity Internal attachments Guide rod bracket 2 Steam dryer support bracket 4 Dryer holddown bracket 4 Feedwater sparger bracket 8 Jet pump riser support pad 2 each, 8 places Core spray bracket 2 each, 4 places Surveillance specimen bracket 2 each, 3 places

External attachments Stabilizer bracket 4 Top head lifting lug 4 Insulation support - vessel support skirt 18

Insulation support bracket -

cylindrical shell 12 each, 3 elevations

Thermocouple pad 2 each, 28 places Name plate pad 1 Reactor bellows support skirt flange 1

UFSAR/DAEC-1 T5.3-9 Revision 21 - 5/11 Table 5.3-7 REACTOR VESSEL TRANSIENT DESIGN Type of Cycle Number of cycles

Bolt up/Unbolt 45

Hydrostatic pressure test 49

Startup/Shutdown at100ºF/h 212 b

Scram (to hot standby and return to power) 150

Loss of feedwater heaters 6

Feedwater heaterbypass 16

Improper start of a cold recirculation loop 5

Sudden start of pump in cold recirculation loop 2

CRD Isolation 3

Single CRD scram 3

125% design hydrostatic pressure test 1 a a APED A41-003 shows 3 cycles for this type of cycle, however, only 1 cycle has occurred. This test is no longer performed.

b Involves "aborted startup cycle (Cold Shutdown to Hot Standby and return to Cold Shutdown) i.e. 36 cycles, is conservatively analyzed as equivalent to a startup shutdown cycle since both involve a heatup and cooldown of the RPV.

(176 cycles + 36 cycles = 212 cycles).

\

Inertialbftspeedradiansgfttorqueftlballshaftsxx

hQ s V R

()=test W W m P P t xflowh = (Q) V12.9 x 10 x (R) s 2 4 3xflow

()=test W W test test P P

UFSAR/DAEC - 1 T5.4-1 Revision 20 - 8/09 Table 5.4-1 Sheet 1 of 2 DESIGN CHARACTERISTICS OF THE REACTOR RECIRCULATION SYSTEM Parameter Value External loops

Number of loops 2

Pipe sizes (nominal outside diameter), in.

Pump suction 22

Pump discharge 22

Discharge manifold 16

Recirculation inlet line 10

Design pressure, psig/design temperature, °F

Suction piping 1150/562

Discharge piping 1325/562

Pumps 1500/575

Operation at warranted conditions b , c Recirculation pump

Flow, gpm 28,800 (28,035) [29,410]

Flow. lb/hr 11.05 x 10 6 (10.61 x 10

6) [11.12 x 10 6]

Total developed head, ft 520 (527) [580]

Suction pressure (static), psig 1030 (1039) [1038]

Available NPSH a (minimum), ft 350 (464) [440]

Water temperature, °F 522 (532) [533]

a Includes velocity head.

b Extended Power Uprate values in parentheses.

c Increased Core Flow (105%) values in brackets [ ].

UFSAR/DAEC - 1 T5.4-2 Revision 20 - 8/09 Table 5.4-1 Sheet 2 of 2 DESIGN CHARACTERISTICS OF THE REACTOR RECIRCULATION SYSTEM Parameter Value Pump motor output (minimum), HP 3180 (3365) [3979]

Flow velocity at pump suction, fps 30.2 (29.4) [30.8]

Drive motor and power supply

Frequency of (at warranted), Hz 56

Frequency (operating range), Hz 11.5 to 57.5

Total required power to M-G sets

kW/set 3120 (3100) [3494]

kW total 6240 (6200) [6988]

Jet pumps

Number 16

Total jet pump flow, lb/hr 49.0 x 10 6 [51.5 x 10 6]

Throat inside diameter, in. 6.1

Diffuser inside diameter, in. 14.0

Nozzle inside diameter, in. (representative) 2.95

Diffuser exit velocity, fps 17.4

Jet pump head, ft 82.2 UFSAR/DAEC - 1 T5.4-3 Revision 13 - 5/97 Table 5.4-2 MAIN STEAM ISOLATION VALVE DESIGN SPECIFICATIONS Parameter Normal Emergengcy a A B Temperature 150°F maximum 340°F maximum 340°F maximum Pressure 0 to 2 psig -2 to 56 psig -2 to 35 psig maximum

Relative humidity 100% 100% 100%

Duration Continuous 45 sec 1 hr a Total duration is the sum of the separate durations.

UFSAR/DAEC - 1 T5.4-4 Revision 13 - 5/97 Table 5.4-3 PUMP DESIGN DATA OF THE RCIC SYSTEM TURBINE Parameter Value Pump

Number required 1

Capacity, % 100

Design temperature, °F 40 to 140

Design pressure, psig 1500

NPSH (minimum), ft 20

Developed head, ft

At 1135 psia reactor pressure 2800

At 165 psia reactor pressure 525

Flow rate, gpm

Injection flow 400

Cooling water flow 16

Total pump discharge 416

Turbine

Number required 1

Capacity, % 500

Steam inlet pressure (saturated), psia 150 to 1120

Turbine exhaust pressure, psia 15 to 64

UFSAR/DAEC - 1 T5.4-5 Revision 20 - 8/09 Table 5.4-4 DESIGN DATA OF THE RHR SYSTEM EQUIPMENT

• Parameter Value Main system pumps Number required 4 Capacity per pump, % 33-1/3 Design temperature, °F 360 Design pressure, psig 450 Design conditions per pump at 20 psid Discharge flow, gpm 4800 Discharge head, ft 360 Operating conditions per pump Discharge flow, gpm 0-5700 Discharge head, ft 750-120 Differential pressure, psid 295-0 Number required 2 Shell-side fluid Reactor water Tube-side fluid Service water Design pressure, psig 450 Design temperature, °F 40 to 400 Pressure drop at design condition, shell

and tube sides, psi 10 Design conditions Shell-side flow, gpm 4800 Inlet temperature, shell side, °F 125 Heat exchanger duty, Btu/hr 20.1 x 10 6 RHR Service Water Temperature 85ºF RHR Heat Exchange K-Factor per Loop in Containment Cooling Mode 142 Btu/sec-ºF RHR Heat Exchanger K-Factor per Loop during the Loss of Offsite Power Event 135 Btu/sec-ºF Key: psid = pound per square inch difference between reactor vessel and drywell

• See Chapter 15.0 for values of parameters used in accident analyses.

UFSAR/DAEC - 1 T5.4-6 Revision 13 - 5/97 Table 5.4-5 CORE SPRAY AND RHR SYSTEM CONTAINMENT ISOLATION VALVES AND ASSOCIATED PRESSURE PROTECTION DESIGN FEATURES Line Number (high/low pressure)

Check Valve Number (inside containment) MOV Numbers (outside containment) a Pressure Relief Valve Number b Pressure Switch Used to Detect Leakage c Core Spray System 8"-DLA-7 V-21-72 MO-2117 PSV-2109 PS-2116 8"-EBB-17/ MO-2115

10"-GBB-13

8"-DLA-8 V-21-73 MO-2137 PSV-2129 PS-2136 8"-EBB-18/ MO-2135

10"-GBB-14

RHR System 20"-DLA-5 V-20-82 MO-2003 PSV-2057 PS-2040A 20"-DBB-1/ MO-2004 PS-2040B 20"-GBB-4

20"-DLA-6 V-19-149 MO-1905 PSV-1975 PS-1955A 20"-DBB-2/ MO-1904 PS-1955B 20"-GBB-3

Key: MOV = motor operated valve

a All motor-operated valves are located outside containment on the high pressure 600-psig or 900 psig piping.

b All pressure relief valves are located on the low-pressure 300-psig piping upstream of the containment isolation valves.

c All pressure switches are located on the low-pressure piping upstream of the motor-operated valves. Annuniciators are provided on control room panel 1C03 to indicate high pump discharge pressure.

UFSAR/DAEC - 1 T5.4-7 Revision 17 - 10/03 Table 5.4-6 DESIGN DATA OF THE RWCU SYSTEM EQUIPMENT

Main cleanup recirculation pumps

Number 2 Capacity (each), % 107 (at rated pump speed)

Flow rate (each), lb/hr 83,000 (at ~93% rated pump speed) Design temperature, °F 564 Design pressure, psig 1400

Heat Exchangers Regenerative Non-Regenerative Reactor coolant flow rate, lb/hr 83,000 83,000 Shell-side design pressure, psig 1,400150 Shell-side design temperature, °F 564370 Tube-side design pressure, psig 1,4001,400 Tube-side design temperature, °F 564564

Filter-Demineralizers

Number required 2

Capacity (each), %

50 Flow rate (each), lb/hr 41,500 Effluent conductivity, µmho max. 0.1 Effluent pH 6.5 to 7.5 Effluent insoluble, ppb, measured as residue on 0.45-µm filter paper 10

Design temperature, °F 150 Design pressure, psig 1400

UFSAR/DAEC - 1 T5.4-8 Revision 13 - 5/97 Table 5.4-7 COMPONENT SUPPORT DESIGN CRITERIA Ambient Conditions

Temperature 70°F (before initial startup) 135°F normal/150°F maximum

during operation and shutdown

Relative humidity 40% (during operation) 95% (during shutdown)

Relation 100 R/hr (3.5 x 10 7 R/40 yr)

Load Combinations Primary Membrane Stress Limits

weight + thermal

expansion + OBE S a weight + thermal

expansion + DBE 0.9 S y weight + thermal

expansion + DBE +

pipe rupture

Key: OBE = operating-basis earthquake DBE = design-basis earthquake

a (S is allowable stress for material under consideration as specified in SP-58)

-DRIVINGTHROAT[DIFFUSERNOZZLEMIXINGSUCTIONSECTION___DRIVINGFLOW-----------FLOW..-/-=':-=-:.:a=__---DRIVINGFLOW.....c:::::;).....g:FLOW---"DRIVINGFLOW11PSUCTIONFLOW11PDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTJetPump-OperatingPrincipleFigure5.4-5 STEAMSEPARATORSNORMALWATER.........'"-.....---f=tt-+-_.....LEVEL,-STEAMSEPARATIONDISTRIBUTIONPLENUMr-----...-rIIIII,__WATERLEVELAFTERBREAKINRECIRCULATIONLOOPACTIVECOREDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTRecirculationSystemCoreFloodingCapabilityFigure5.4-6 REACTORVESSELMAINSTEAMLINE/ISOLATIONVALVESlSTEAMFLOWRESTRICTOR.rPRIMARYCONTAINMENTrv1..IORAINSTESTCONNECTIONDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTMainSteamLineFlowRestrictorLocationFigure5.4-7 TOBF.SUPPL.IEDWITHACTUATORSAFETYPINHOL.ES12PERTueEISHOWNROTATED4!5"rROt.!TRUEPOSITIONREVISION14-11/98FIGURE5.4-8MAINSTEAMLINEISOLATIONVALVEDUANEARNOLDENERGYCENTERIESUTILITIESUPDATEDFINALSAFETYANALYSISREPORT*APPLY750.25-0F'1.LB.TORQUE)----018191.0IllBlI*n*.,IllB10-31'89"ALB02-0"90IllBII-Zl*n,_/11'1.OHI'h.U'",,",,<HI'APPLY45'5-0FT.LB.TORQUE16.*j.,....*...BI'!*--08'aRS02*aa*9QstA*'08-90Rill02-01-90SAn*z.1I*28-1JSLAIt'll'"RDllII*2I*.,APPLY200TO220F'T.LB.TORQUEAPPLY240'25-0FT.LB.TORQUE!<<In.10**NlC"IINil"l:t'l'l'lICIII"""fOUl:lIII'TIOIII'<Ita1IlNO.1.....REV.1APED-B21-2793-1Il73

---

IUQUIRI!'!!I C.Oito.IC.IDI!NT "!'IIIII' Rl"C:ro;:--1 j,.) ITC.I+ I&I*HO!oiA. 0111 &li-NO!IB ANC VE-;i'Y.L I II'I.I*NO!\G OR B'l.HIO!!C 1"0 '!!IT.IroR'T '!!1"1!!1-UI-LO LE'IEl ! ('"!Ioiii llli.F OWG& !1 HI FOR ADDITIOIIIAJ.. I '!. 1 l.fl v t=UNC.TIDN'!!I F'ti.RPORMED e.v T'""' I I '!!lli:T OF REF. tNt(,"' II llEII.tTOR. Jl : I I ' 0 .START -l---AUTO IIIIITIATION (NOTE 1)"'\ ':IW. LE" OPENING I I OPEN I'!!Olii.TION !116NIIL LD,ICA' RE5ET ,. '" IN . ""'" RUE'T I C1.0$E. CDNTRGL -.w IN I'DSITION RMC, D I I DC. REVE.RSINCO CDI\IT,I\CTOft '71! * !ITEAM WJE "OLA11Ui VALVE 1'10 F008 ";E NOTE!I 1!15 I!IOLATION '!III>NAL l61.1l'8" PB C.R r.""'c.'"'c";-;,cw::-1 IN *oi'EN" POS!TIOhl LIMIT !>W PERM1!1'51YE WHILE DPENING) I OPEN SEI.L '" I I;ONTROL IN 'tl05E" PO!>ITION IRM':o JZ. j l {w1111..E CLQ51N' " ' !>WITrH vn 1: j tLQ:OE I A.C. Ri"rUSIN&. 'QNTA,TOR 42. M STEAM 5UPP'LY LINE VALVE MO F007 SI:E NOTES 'l15 SE'Al. IN 72 a !>EAL IN 42.

• l!IOLATION PU'!!I\o\ BUTTON RMS CR w;:_<; ./INITIATION 51,NAL 1!1 /'RESENT F.C..F. U&XI!IC.fl fiii.N!n.D) E 61-1030 !:!.Q.!.ll = .;:Ji\NE Aftlfiii.D I, THE RCIC SYS IS ARRANGED FOR TEST OF PUMP AT FULL FLOW & All VALVES FOR OPEN & CLOSE CAPABILITY AT ANY TIME EXCEPT WHEN INITIATION SIGNAL DR AUTO ISOLATION SIGNAL IS ACTIVATED, IN EVENT THE INITIATION SIGNAL OCCURS WHILE TEST IS UNDERWAY THE SYSTEM AUTOMATICALLY RETURNS TO STARTUP MODE, 2. ALL POWER FOR OPERATION OF D.C. VALVE MOTORS SHALL ORIGINATE FROM A PLANT D.C. BUS. POWER FOR AC OPERATED VALVES SHALL ORIGINATE FROM AN EMERGENCY A.C, BUS, ALL EQUIPMENT & INSTRUMENT PREFIXED BY SYSTEM NO, (E'il) UNLESS OTHERWISE NOTED, '1. ISOLATION SIGNAL SWITCHES SHALL BE OF THE TYPE THAT CLOSE CONTACTS FOR THE SPECIFIED ISOLATION EVENT. WHERE AUXILIARY RELAYS ARE USED IN THE ISOLATION CHANNELS THEY SHALL BE POWERED FROM THE STATION BATTERIES, r;, AUXILIARY RELAYS & DEVICES NOT SHOWN ON FUNCTIONAL CONTROL DIAGRAMS EXCEPT WHERE REQUIRED TO CLARIFY FUNCTION, .. 7, FURNISHED WITH B. AN ALTERtJATI:: SOURCE OF EMERG:::NCY AC SHALL BE PROVIDED TO THE FOJJ (SEE REF 1), q, RCIC SWST5M SHALL BE 1; PROT:CTIO'. -AS PRACT i 10. ALL s..,:.LL :*: i), LOAO c:qc_r-II. R&JIJOT£ 5/JUTlU!I<I# ,e.; Wl::; ....... -;;;z"".v A .. '?. .:'A" Gfl;Hr'.S" W/l(.. MfT * /,ws ,..., ""'" ,.,c REFERENCE DOCUMENTS: J. NUCLEAR BOILER P&tO-----2, NUCLEAR BOILER MISC SYS FCD -RHR SYSTEM FCD -------CORE SPRAY SYSTEM FCC r;, HPCI SYSTEM FCD ----6, RCIC SYSTEM P&IO 7. L:lGIC SYMBOLS -----B. TURBINE CONT SYS I ELEC WIRING 821-IJ:c 3CI-':;: ::. :-:: >: E21-IO'l: E4i-IO;O A-+ I 0\l VPF-9, REAC WATER CLEANUP SYS P&ID I 0, I.EAK DETECTION SYS 1-4040 II. ELEC EQUIP SEPARATION FOR SAFEGUARD SYSTEM--------------A61-40'i0 DUANE ARNOLD ENERGY CENTER NEXTERA ENERGY DUANE ARNOLD, LLC UPDATED FINAL SAFETY ANALYSIS REPORT REACTOR CORE ISOLATION COOLING SYSTEM FIGURE 5.4-11 SHEET 1 REVISION 22 -05/13 . I

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___2.-POSITlQI<.I"01<.1"-"OFF"l>,.IAI\.JTA.lIoJEOCQl.JT,l..,CTC.O\.JTR.OLSill"Ol-.i"POSITIOI-Jo.U>>Co.mC:OJ...lTROU-f.1I,'ACRTRA.CK'0£."/,I\"\PUT"'00"00XRESE"TSUPPLYT'I.3REF:'PO"coIFROMIIN'E\o..I'5,\..0,",UIS,CR,rtJTEST5\GN/'o,L1....."....AAvTv,l)'vl'LGENli:.R....TOR....I'te..."....'-"E./"R'-"LTPOl:i'j-.ITo..If.1E:RCONTROl.:.:IPO'SITIONPOSITION"'"D404.=,co.RM,F!£J'NINDIC/l..TORjCONTROLLERI>JJTO-M"'NlJr-L/c\({URBINETE.';;T<;:,TA.T1ON'5E.LEC:TOR**00Co.'S.*,nTc.1-IIN"TE::;1A)::'IT\ONI/lIJTIATJVNC4!';,J"/\IALt::TESrTURBINETESTPEI<MI';;'O.lVEt-D"T>'tRM1"IJE'5E.LECTORSWWHENMJTOIN)("N1Tl/l..TIOt-lSIC,INITIKnON<;;1<:-)POSITIONPRE:;E.NTPRE.':>E:NTRMSOR,.co.[.:IE:IJICE51<..,MJDESELIOCTORFU'll:'SWIN'RC.IC.IS)co.IZLIOC.TRO>lIC.TllRBIN"RIGOJERNORCONTRCU.t.RREF8LSEe"-J2.POSITIONSw."NORMAM....IN,/>..INEIDCONTp.,C.T':lPOSITIOl>l(SEEREF3ADDITIONALTIONSOFTI-IOTE7speeDCONTROLAPED-E51-013(3)Figure5.4-11,Sheet3Revision7-6/89FCD,ReactorCoreIsolationCoolingSystemDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTArIiWI".IIM"",.'.'LOWDEC19I9nOIsmlSUTION150LA,tO\-.lSIGl-.lA.L'5PUSKEUTTOiJSW.CLOSEToTRIPSEEMOTE7_R,"E5ET"",,,'UYBYV,IIVf.:om"01r-LOWPUMPSUCTIO'lPRESRCICPUMPENERGI'Z-ESOTOTRIPTURBINEHIGHTiJRBINEE)(.H.co.RMSSWlTCl-lINOPENPITIONVA\..veLIMITSWITCI-lWI-lILEOPENINGLtf\AITONJBOJERSPEEDT,o"c\\OMETERTRtP....TIIO%'R"'TED':>PEEDRE'BV/>J...VE.CONTROLSWITc.HINCIJJ'5l':P0'51T10NTORQUE,,>WITCHPERMI":>SiVEWHILECLOSINGTORQUE0..E....TETUINE:TpkTOTTV/>..JFURF\Oo,RTQFTURSINE/>Oo,=>EM.8LY---TURBINETR\PCONTROL----.JPoSITIONSW,ilCHSPRIN<>RE:TU!l:NTO'NORMAI"HWMbptNOR*ClOSE'J':>:SIT",!'lIssue6Rev6BI',ROMfTRICCOND£N5ERVACUUMTANI\,PUMPHIGHVACUUMTAf..lK'AUTO:LSJ.lRNTO'lOTe7'STOP.'WWl-lENC.ONTROL5WITeKISIN*....UTO..P05i1l0f,.j!RM'JILOWVACUUMTANKLEVELCOL(.sa"N!J/C7C.ONTROLSWIN"5TOP"POSITIONRM;JIJ?:',/,ISTOPDC.STARTERen)*I----------TURBINEEQUIPMEt.JTCONTROL':OJIN"STt>.RT3P05mON"START""5,OP'SPRIN(,RHUAvTO"FRO,"""rART'"oRL L.'MITSW\\,WHILE!\iW:l(lIi:<1"15iCREo:'imRT£RI£/1:>,/¥OrE,r<l.roll1(17U>>N;;','Ci';,r.:-HI)I;NiOPENCLO'liECONTACTORPlj/'tPSUCTiON,ROMl;UPPR!sSiONVAl.VE1'1010Z'(;'(1'FClRVALV,,-Fa:!J)NOiE:;,VAl.\I£MQron,FULLYOPEN1.11'11':'.ON'VAl.vtII!7HI""'"I,":oWliNII'---_:=fdiIIINII72:1f:;tIYALV£HOF031)Ii\11k¥,I,'"'!cONTROl.<,;W!:l)iI,..ICRiCONTROLSWiIN*OPEN....,...O.C(ONTACTORnJfVALVETORQUf.iNl/ll£(LOSING..WHIUliM..VALVf.TDROUEWHILECl-OSINlO.0<(lOSE.OPEN/LVELIM.,".5W\,WHILEuVAL"£.MOrO't211,1,'5'TOCQN.QgMAT[STORAGE,"'11/1((TlIROTT1..I,".HI"eVALVE)'COTES-PUMPSUCTlllNFRO!"!STDRo\GETANKVALVE..I1DFOlD)fGL:'5"REACTORCOREISOLATIONC8C:UNGSYSTEHDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHTANDPOWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORT"VAl.VETDRAV£SPEltMISSI\l£WIlILEIItIUlelMT70NTROLSWIN"CLOSE"poSmaNALliEPERMISSIVE'"**0'il..IStM!EI:'.--;oE:\:o.>:il\ol:!l:CQ,",URSINEI'!lTOPVALVEfULL'!'CLOS£Ovj!ITEAMSuPPLVIIF045IRJLLYCLO:.EOIhJl..1f'ew!vi"Vi)It..lfte.LOl5'E:AU:>**H11..1"*RC!CIFLOWL'WVALVELIMITWiWI/Ill:OPENI),!GIt'llItOPlNOPENCLD!t.ED.C.REVeRSINGCONTACTOR7ZMINIMUMFLOWeYPAS'510SUI'Pl!fSSIONCHAMBERVALVE.1'10FOl'MOTE5"o.c.R£ViRSIN6CONTACTDR12.IIPUMPO1SCWARGf.VALVEMOFDI'!.(n?RlRPUMPDlSCILVALVE1'10'1"0120),1I0TEFIGURr=-5.4-11SHo4Revision11-4/94 MODE D STEAM CONDENSING RHRSW RHRSW (SEE NOTE 11 & 15)

MODE D-2 CONT'D.

MODE E - SHUTDOWN COOLING RHRSW 16. STRAINER HEADLOSS FOR NPSH IS DEFINED IN CAL-M97-007.

MODE F - SHUTDOWN COOLING MODE G - LPCI INJECTION MODE H - FULL FLOW TEST MODE J - MINIMUM FLOW RHRSW P P P P P P P AND CAL-M97-007.

IN ACCORDANCE TO CAL-M98-002 P - STRAINER PLUGGED WITH DEBRIS MODE A - LPCI INJECTION MODE B - LPCI INJECTION MODE C CONTAINMENT SPRAY MODE C CONTAINMENT SPRAY MODE D STEAM CONDENSING RHRSW RHRSW RHRSW RHRSW (SEE NOTE 11 & 15)

NOTE 15}(LPCI)(LPCI)NOTE 16NOTE 16 (CONTAINMENT SPRAY) }NOTE 16 (CONTAINMENT SPRAY) }NOTE 16 (SHUTDOWN COOLING)(SHUTDOWN COOLING) }NOTE 16}NOTE 15 EXPECTED RHR FLOW RATES. EXCHANGER, REFER TO CAL-MC-040J FOR REQUIRED AND AT 20 PSIG) AND 1 PUMP OPERATION THROUGH RHR HEAT FOR ACCIDENT W/RECIRC LINE BREAK IN SIDE 1 (Rx PRESSURE 17.CONTAINED IN THE UFSAR CHAPTER 15 ACCIDENT ANALYSIS. EACH RHR HEAT EXCHANGER USED IN THE ACCIDENT ANALYSES IS THE VALUES OF PARAMETERS AND RESULTS FROM ANALYSES FOR 18.(SEE NOTE 3, 14 & 18) HISTORICAL VALUE SEE NOTE 18 REVISION 24 - 04/17 APED-E11-008<1> REV. 9 FIGURE 5.4-12, SHEET 1 PROCESS FLOW DIAGRAM RESIDUAL HEAT REMOVAL SYSTEMS, UPDATED FINAL SAFETY ANALYSIS REPORT NEXTERA ENERGY DUANE ARNOLD, LLC DUANE ARNOLD ENERGY CENTER IRESIDUALHEATREMOVALSYSTEMPROCESSFLOWDIAGRAMDUANEARNOLDENERGYCENTERIES.UTlLITIESUPDATEDFINALSAFETYANALYSISREPORTIDEIIIItvtUEOrlOM'!,ttL1'001..TO"el<:(i;\......y'TOfUlL-r-OO....Ur.,."rtGE'It.EllY",,--l.sS.1I11l0TEJV.0J.1'0.10'01'"tOll....@FlIZ)BFOI"B@1&"I'R:U*Slllh:**""FOI7...'OlS'"FO;OA0.6;'OIOSFOlseFons'<i.:Y""-e-/_VEUlil.IOlliY.__2,Ij>*roo,*f'I\.JI(lJv*Faa....jFon...SPitAl'M'iAtlellFavlSFOl:tlllau.FOZ@:Q00Q@:.&'.-=_",'iiWATER.....1"'1l"EVEL.__".&.A1iht8....5UPPI'IU!llONPO",""0.0.0.0-5rooaI'OIiA10'01111lP*10'04&1101'04118""'"'"Fl>""a-.I@A,os......FOZ."ooauFOn,1!I*10'0181ft*10'047"";t.ft*10'0..711"'./SU.1'0s....!"ou:",'OStBleo",,-'",,-......HI'TrnHI".....,.yv.UCH,t,N4I:R..TilleH""",,UBOOlA0.-.....!!l001!>4.e,;,:0.F075.././""'......--,....-140.101M5li:llV1CE..",FClOtoD@l-J@.5£W...*Hlt._)"9.W'T*PIJIolrt\.1V...F004C..""mv.__I*FOIOIJA,o**a5,<SIDEIREVISION17-10/03APED-EIH108(2)REV.4.FIGURE5.4-12SH.2

I'remJreforAdequateOJreSprayandRElRPmq:lNPSH(l)picalJnitialRflp:mefirrBA-LIX'A))j....25i;'-_(w'IaoIo!l:)il.-.e.i;"'"-<>.ap=re...-ntslgiiW...;I...,...'"........t...***R<qIiRdftr<:lre'i-"*!-"*.........*"****R<qIiRdftrRllR(rnepnp)..C-IS.J-14,714....."....'..."to16)l;\llID1!Xl:100210m!Juwnssiool\lolT.............(degFjN:J1E_fl"&I1'IIByoolybe_tirNI'SHq>to36Inrs__s!U<b'MI.DUANEARNOLDENERGYCENTERIESUTILITIES,INC.UPDATEDFINALSAFETYANALYSISREPORTLicensingBasisOverpressureAllowanceforCoreSprayandRHRPumpNPSH(WetwellPressureVB.Time)Figure5.4-15Sheet1Revision1710/03 I're&<ureforNPSH*Mlgnitude&DuralionConstraints101/....I'..II"25..."'-..!r-..i'"!'o.;;I"r-.E20i"I"--...*'.=,,.....!,I!"oo..,,,"r-,,,,,IS*.,,,,.,.***.,....,....,..:',......'.10012243648(fJ7111me(hooa><)I-AvaiWe(vlkakage)***RequiredlirQreSpayI..._.RequiredlirRHR(",,_lDUANEARNOLDENERGYCENTERIESUTILITIES,INC,UPDATEDFINALSAFETYANALYSISREPORTLicensingBasisOverpressureAllowanceforCoreSprayandRHRPumpNPSH(WetwellPressureVS.SuppressionPoolTemperature)Figure5.4-15Sheet2rRevision1710/03

STEAMLi"EScRVoREACTORVESSELARVBRVDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTSafetyRelief/SafetyValveLocationSchematicPlanViewFigure5.4-17 UFSAR/DAEC-1 5A-i Revision 20 - 8/09 5A: SITE ASSEMBLY OF THE REACTOR PRESSURE VESSEL TABLE OF CONTENTS

Section Title Page 5A.1 SCOPE ......................................................................................................................... .... 5A-1 5A.2 DESCRIPTION ............................................................................................................... 5A-2 5A.2.1 GENERAL ................................................................................................................... 5A-2 5A.2.2 PRACTICES................................................................................................................. 5A-4 5A.2.3 FORMING AND FABRICATION OPERATIONS ..................................................... 5A-5 5A.2.4 SUPERVISION ............................................................................................................ 5A-7 5A.3 DESIGN BASES AND EVALUATION ......................................................................... 5A-8 5A.3.1 GENERAL ................................................................................................................... 5A-8 5A.3.2 FUNCTIONAL DESIGN ............................................................................................. 5A-8 5A.3.3 DETAILED DESIGN ................................................................................................... 5A-8 5A.3.4 CODE DESIGN ............................................................................................................ 5A-8 5A.3.5 REACTOR PRESSURE VESSEL STRESS REPORT ................................................ 5A-8 5A.4 SURVEILLANCE AND TESTING .............................................................................. 5A-10 5A.4.1 QUALITY CONTROL ............................................................................................... 5A-10 5A.4.2 EXAMINATION ........................................................................................................ 5A-11 5A.4.3 VESSEL TESTING .................................................................................................... 5A-12 REFERENCES FOR SECTION 5A.5 ..................................................................................... 5A-13

UFSAR/DAEC-1 5A-ii Revision 20 - 8/09 5A: SITE ASSEMBLY OF THE REACTOR PRESSURE VESSEL LIST OF FIGURES

Figure Title 5A.2-1 Reactor Pressure Vessel - Site Assembled - Post Weld Heat Treat-Longitudinal Weld 5A.2-2 Reactor Pressure Vessel - Site Assembled - Post Weld Heat Treat-Girth Weld 5A.2-3 Reactor Pressure Vessel - Site Assembled - Vessel Flange Machining 5A.2-4 Reactor Pressure Vessel - Site Assembled - Top Head Flange Hold Drilling 5A.2-5 Reactor Pressure Vessel - Site Assembled - No. 1 Shell 5A.2-6 Reactor Pressure Vessel - Site Assembled - No. 2 Shell 5A.2-7 Reactor Pressure Vessel - Site Assembled - No. 4 Shell 5A.2-8 Reactor Pressure Vessel - Site Assembled - Drilling Control Rod Holes in Bottom Heat 5A.2-9 Reactor Pressure Vessel - Site Assembled - Placing Heat Treating Furnace in Vessel

UFSAR/DAEC-1 5A-1 Revision 13 - 5/97 APPENDIX 5A SITE ASSEMBLY OF THE REACTOR PRESSURE VESSEL 5A.1 SCOPE The reactor pressure vessel is discussed in Section 5.3. That discussion covers the operational and safety requirements but does not cover the assembly of the vessel.

A feasibility study of shipping an assembled reactor pressure vessel to the Palo, Iowa, site led to the conclusion that the reactor pressure vessel should be site assembled. The site-assembled vessel for the DAEC was furnished in a manner similar to those furnished for and the schedule of operations was similar to the ones for those vessels.

This appendix discusses the technical and safety considerations pertinent to a site-assembled reactor pressure vessel.

Site assembly of the reactor vessel involves some machining, welding, heat treatment, and testing operations at the plant site that in the past have been performed in the vendor's

fabrication shop. A significant portion of the vesse l was fabricated in the shop just as though the vessel were to be completely assembled and tested before shipping. Major subassemblies were assembled in the shop to the degree consistent with shipping capability, but final assembly took place at the plant site. A field shop area was established at the site to complete work on subassemblies. The complete assembly of the reactor vessel at the site was done in place. Assembly at the plant site, therefore, was a matter of setting up equipment to perform some of the operations usually performed in the vendor's shop.

Based on the experience gained in the site assembly of the reactor pressure vessels, it was evident that site-assembled vessels can be constructed in accordance with specification requirements without compromise. The techniques and site-assembly procedures that were developed for thevessel proved satisfactory, and modifications to these procedures were not necessary. The quality assurance and control programs functioned well on the site-assembled DAEC Unit 1 vessel.

The overall evaluation of the reactor vessel site assembly is covered in detail under the categories of design, fabrication and assembl y, quality control, inspection, and testing.

Chicago Bridge & Iron Company (CB&I) fabricated the site-assembled vessel.

UFSAR/DAEC-1 5A-2 Revision 13 - 5/97 5A.2 DESCRIPTION 5A.2.1 GENERAL

Chicago Bridge & Iron performed the various operations of reactor vessel fabrication and assembly at the shop, the field shop set up at the site, and in place at the final reactor vessel

location.

The materials for the reactor vessel were ordered, received, and inspected in routine fashion. The specifications and suppliers for these materials are the same as those used to supply materials for other reactor pressure vessels that have been fabricated by CB&I. The adequacy of the CB&I quality control has been established, and a description of the quality control program

in effect for this plant can be found in Chapter 17.

The bottom head plates, shell, and top head plates were shop formed, on heavy pressing equipment. The bottom head was shop assembled from subassemblies and was shipped to the site in one piece. The bottom head was postweld heat treated, radiographed, overlay welded, and heat treated as required. The control rod housing holes were rough bored in the shop. Some of the vessel penetration nozzles in the bottom head subassembly were shop installed.

Several shell rings compose the cylindrical shell portion of the vessel. Each ring was shipped to the site in two sections. After forming, associated heat treatment, and initial sizing, the two sections of each ring were temporarily welded to permit the application of the weld overlay with automatic equipment in the shop. The temporary longitudinal weld was cut, the overlay removed from the joint, and the joint prepared and sized for final welding in the field

shop area. The nozzle penetrations were installed in the ring sections in the shop as far as practicable. All radiographs and postweld heat treatments were performed as required. The top head of the vessel was fabricated in the shop and shipped to the site in one assembly similar to the bottom head configuration. The head closure flanges were shipped directly to the site as rough-machined integral ring sections.

The field shop area at the site was equipped with stress-relieving furnaces, a storeroom, a toolroom, radiographic equipment, a darkroom, preheating and welding equipment, and lifting and handling equipment. The main derrick swung over this area to pick up the reactor vessel components and set them in final position on a support skirt in the drywell structure.

The following operations were performed in the field shop area:

1. The half rings of the shell sections were welded into full rings and the cladding completed over the welds.

2. Welds were heat treated and radiographed as required; the weld overlay was applied and heat treated.

UFSAR/DAEC-1 5A-3 Revision 13 - 5/97 A suitable environment was made around all welding and heat-treating operations in the field shop area. Igloo-type weather enclosure stru ctures sites were used to protect the work from adverse weather conditions. Similarly, the welders and work on the vessel were protected in position during all welding and heat-treating operations by modular-type circular weather enclosures suitably covered with a temporary roof.

Figure 5A.2-1 illustrates a typical field stress relief of a longitudinal weld on a shell ring. Figure 5A.2-2 shows a similar setup in place on the vessel to stress relieve a girth seam weld. Indicators and controls were provided to maintain temperatures within the range of 1100 to 1175°F. The top head flange was machined, and the stud holes were drilled in the field shop area. A temporary support skirt was attached to the head to permit these operations. The setup shown in Figure 5A.2-3, in which the work remains stationary while the machine revolves about it, was used in machining the flanges.

The drilling of the top head flange holes was done with the equipment setup that was developed for the project similar to that shown in Figure 5A.2-4. This operation closely resembles an actual shop setup and was done, as was the machining, under a weather hood to minimize the effects of weather conditions.

The reactor vessel subassemblies were assembled in place. The bottom head and stub

skirt were set in the drywell. Next, the No. 1 shell ring was hoisted into place, fitted and welded to the bottom head, back clad, and stress relieved (see Figure 5A.2-5). With the completion of welding shell ring No. 1 to the bottom head, shell ring No. 2 was hoisted into place and joined to ring No. 1 (see Figure 5A.2-6). When overlay welding and stress relief of this closure seam was completed, boring bar equipment, guide templates and ventilation equipment was installed for boring the close tolerance control rod penetration holes. The machining equipment and techniques were similar to those used for the project. A temporary bulkhead was

built to protect operations inside the reactor vessel as subsequent rings were set, welded, and

stress relieved.

The vessel flange was set in place, leveled, and welded to Ring No. 4 (Figure 5A.2-7). This flange was drilled and tapped by using the same equipment under the same careful machine alignment control as was used on the head flange. Ring Nos. 3 and 4 were then set in position and welded and related operations performed.

Boring the control rod drive (CRD) penetrations in the bottom head was accomplished in a manner similar to that used for the reactor vessels as shown in Figure 5A.2-8. The boring bar guide templates were made in a machine shop on a precision boring mill. They were attached to the bottom head and vessel support skirt and aligned for the high degree of accuracy required for these penetrations by using optical devices. Temperature-controlled ventilation equipment was used because the success of this operation was dependent UFSAR/DAEC-1 5A-4 Revision 13 - 5/97 on keeping the reactor vessel shell and templates at a common temperature. The work was done by skilled personnel in an environment equivalent to, if not better than, that of the CB&I shop. After the stub tubes were installed, the machining was completed on the lower head. Chicago Bridge & Iron hydrostatic tests have been completed and the CRD housings have been installed.

There are many key operations in the previous discussion that were not detailed because of their repetitive nature and the number of variations in which they may occur. These are (1) intermediate interstage tempering after welding, (2) "final" post-weld treatment of some

individual welds, and (3) the various inspection steps. These three operations were interspersed

throughout the sequence as required by the ASME Code, GE, and CB& I. General Electric required that CB&I prepare a detailed fabrication sequence that met GE approval. The entire

detailed fabrication procedure was reviewed by GE for proper type and sequence of operations required to achieve the built-in quality that is considered necessary for a nuclear reactor pressure

vessel.

With the vessel design and quality (Chapter 17) established at the predetermined level by

the ASME Code and by GE specifications, the various manufacturing operations were performed as necessary to meet those requirements whether the operations were performed in the shop, in the field shop, or in place at the final reactor vessel location. To complete the reactor vessel, a combination of both shop and site fabrication and assembly was required. The major difference between the assembly of this vessel and those assembled in the shop was the increased quantity of work performed at the site.

The construction of the reactor vessel in the field has some advantages over a shop-assembled vessel with respect to the placement of the vessel on its foundation. With the vessel being final assembled in place, the initial parts of the vessel are placed on the foundation, and the vessel is built up in its final location. Since the initial placement includes only the lower head assembly, equal loading on supports and true plumb alignment can be ensured. While true plumb alignment is not essential to reactor operation, it greatly facilitates the installation of the

critical portions of the internal structure that must be carefully aligned with the CRD penetrations in the bottom head. Final boring of the CRD penetrations in place means that the attitude of the penetrations relative to plumb are controlled by a machining operation rather than as a function of the placement of the premach ined penetrations of the shop-fabricated component. The use of specially fabricated fixtures to support boring apparatus above and below the vessel bottom head results in an accuracy equivalent to that associated with usual shop boring operation on a horizontal boring mill.

5A.2.2 PRACTICES

All practices for the site assembly fall into one of four acceptable categories when an apparent difference between shop practice and site assembly is scrutinized closely in context

with the GE specification. These categories are as follows: UFSAR/DAEC-1 5A-5 Revision 13 - 5/97 1. Practices that have been proved and used to a limited extent on shop-fabricated-and-assembled reactor primary vessels and that are intended to be used more generally on a site-assembled reactor vessel.

2. Practices that have been proved and widely used in the fabrication of other vessels and that are fully applicable for use on a reactor vessel.

3. Practices that will be conducted in the field the same as in the shop.

4. Practices that will continue to be conducted in the shop without change.

It is apparent from these categories that there are no new or novel practices required for site assembly of the reactor vessel. Furthermore, the manufacturers and distributors of plate, forgings, bar tubular products, and bolting and welding materials for vessel components for both shop and field are all selected from the same group of qualified vendors. The purchase specifications for the reactor vessel material are approved by GE as has always been the practice.

5A.2.3 FORMING AND FABRICATION OPERATIONS

The forming of the vessel components was done in the shop because the heavy equipment involved in forming the shell and head components virtually dictated this approach. The vessel was fabricated from high-strength, low-alloy materials that were heat treated at high temperatures above 1500 °F to austenitize and then quenched in water. Because of the requirement for a high- temperature furnace (over 1500 °F) and for large water-quenching facilities, the availability of the process equipment favors the high-temperature heat treatment being performed either at the mill or in the shop. The material for the DAEC reactor vessel was high-temperature heat treated at the mill. The material was preheated at the shop to 800 °F and formed while at temperatures in the range of 400 to 800 °F. After the material was formed and welded in the shop, low-temperature postweld heat treatment and intermediate-temperature postweld heat treatment at temperatures up to 1175 °F were performed. Low-temperature postweld heat treatment and intermediate-temperature postweld heat treatment were also performed in the field after joining the vessel components. The only difference in postweld heat treatment between the shop and site-assembled reactor vessel is that more local postweld heat cycles may be expected in the field than are used in the shop. Local postweld heat treatment has been used in the shop and field where facilities and size limitations have required doing so. The ASME Code, Section III specifically permits local postweld heat treatment, and since both the

code and GE have well-developed standards that do not change between shop and field, no change in quality level occurs as a result of the increased number of local postweld heat treatments.

Local postweld heat treatment consists essentially of heating a circumferential band of the vessel that encompasses the weld joints being postweld heat treated. The permissible temperatures, times, and rates are the same for both local and total postweld heat treatment. The difference between local and total postweld heat treatment is the presence of a thermal gradient

between the heated band and the cold section. General Electric standards for an acceptable local UFSAR/DAEC-1 5A-6 Revision 13 - 5/97 postweld heat-treatment procedure are based on the fabricator providing a detailed written plan that pays particular attention to (1) the type of furnace, furnace controls, and insulation to provide an inherently stable operation that is easily controlled; (2) operating procedures, heating and cooling rates, and temperature gradients in all directions to meet code requirements and to meet GE requirements for the control of thermal stresses to avoid warpage and distortion; and (3) sufficient instrumentation of proper type, quality, and location to measure accurately the

progress and acceptability of the operation within the specified tolerances.

Total postweld treatment of some subcomponents at the site was done. A furnace was built in the field shop area that differed in shape from a shop furnace but met all the functional and technical requirements of a shop furnace (Figure 5A.2-9). This technique has been used in

the field on other types of vessels and on the reactor vessels for the power stations. The methods and techniques of postweld heat treatment of the site-assembled vessel therefore represent nothing unique in pressure vessel construction and have been used by pressure vessel vendors for many years.

The welding and weld cladding of the vessel was performed with conventional processes involving conventional, manual, and automatic welding equipment. The major differences

between shop and site welding consist of the following:

1. Possible variations in the experience of field welders. This factor is potentially encountered with any new vessel fabricator and was controlled by instruction, practice, performance qualification tests, supervision, and inspection so that the development of experience was obtained while maintaining an adequate quality level.

It should be noted that most of the welders working on the DAEC vessel at the site had prior field experience on other BWR nuclear reactor pressure vessels.

2. More manual welding "out of position," that is, other than the flat welding position. This is a matter of degree since some major parts of all reactor vessels are manually

welded out of position. Out-of-position welding was minimized where practical, but where not practical, the welding procedures and joint designs and field supervision

were of a nature that provide good quality welds.

3. The shop and the site have different methods of protection from the weather; however, the equivalent of shop conditions was provide d in the field where required, at least in localized work areas. The weather protection for the site-assembled reactor vessel weldment was more elaborate than normally provided for field welding where preheat and postweld heat treatment requirements may have been less stringent.

4. The field storage, drying facilities, and handling of coated electrodes and submerged arc welding flux were equal to shop facilities in the control of the moisture content of the welding material. Field practice is well developed in this regard.

All welding was performed by ASME Code qualified boilermakers, qualified by CB&I. Longitudinal seams were welded manually with the metallic shielded arc process. Head plate UFSAR/DAEC-1 5A-7 Revision 13 - 5/97 seams and closure welds in position on the vessel were hand welded, using the metallic shielded arc process.

Any required machining of penetrations and mating surfaces in the field was performed by built-up boring equipment that attaches to the vessel and that is guided by accurately machined templates in contrast to the huge boring mills usually associated with large shop equipment in which the work is brought to the machine. This approach to machining is not new

in reactor vessel construction and has been used in the past on other vessels, including the vessel supplied for the power station. It has been demonstrated as an acceptable method for construction of larger vessels. Portable, built-up boring equipment has also been used extensively in shipyard construction for machining gun turrets. The tolerances obtainable with this approach to machining depend on the method of attaching the tooling to the vessel, the accuracy of the templates, the flexure of the boring arm, the tool characteristics, the skill of the machinist, the accuracy of the reference point, and the effect of subsequent operations. Most of the effect of this approach to machining was handled by good tooling design. The major difference between shop and site construction is that (1) machinist skill is provided in the field and (2) site sequence and accessibility for short, inflexible boring arms and equal tool pressure may require a shift in tolerances from one location to another in any given dimensional system. However, this does not result in a major shift of the overall envelope within a given system because system tolerances are set by the requirements of the completed vessel and not by the equipment of the fabricator. System tolerance envelopes can be relaxed only by changing the design requirements and are independent of shop or site facilities.

5A.2.4 SUPERVISION

The need for adherence to written procedures and dimensional requirements of the

reactor vessel is apparent to the site erection crew. Highly qualified and experienced site field supervisors direct the work of the craftsmen and instruct them regarding the importance of their role in the quality and procedure of the job. UFSAR/DAEC-1 5A-8 Revision 20 - 8/09 5A.3 DESIGN BASES AND EVALUATION 5A.3.1 GENERAL

The design of the site-assembled reactor vessel is the same as the design for a shop-fabricated-and-assembled reactor vessel. The same quality factors and design margins are applied since the requirements for material and process inspection and control and acceptance criteria are identical in both cases and are equal to or better than requirements of ASME Code, Section III. Various aspects of the vessel design are summarized below.

5A.3.2 FUNCTIONAL DESIGN

The principal functional design requirements of the reactor vessel are (1) to provide a

high-integrity barrier to contain the reactor coolant and prevent the leakage of radioactive materials during the 40-year service life of the plant and (2) to support and maintain proper alignment of the reactor core, control rods, and control rod drives during all modes of reactor operation. These requirements are equally applicable to both site-assembled and shop-assembled

vessels.

5A.3.3 DETAILED DESIGN

The same detailed design is used for the site-assembled vessel as for a shop-assembled

vessel except for the installation of nozzle safe ends and for weld preps for field welding. The stainless steel nozzle safe ends will not be welded on until the vessel is heat treated. Heat

treating of the nozzle safe ends would cause se nsitization of the stainless steel that can be avoided in this manner. There is no need to make any special design allowance for plate sizes, seam weld locations, nozzle locations, or tolerances for site assembly.

The reactor vessel parts meet the requirements of ASME Code, Section III, for trueness to form and fit-up. These are the same tolerances applicable to a shop-assembled vessel. Plate

for the shell and heads are ASME SA-533, Grade B, Class 1. Low-alloy steel forgings for

nozzles and flanges are ASME SA-508, Class 2. All material used meets the requirements of Article 3 of Section III of the ASME Code.

5A.3.4 CODE DESIGN

The site-assembled vessel is designed to the requirements of the ASME Code, Section

III, Class A reactor vessel.

5A.3.5 REACTOR PRESSURE VESSEL STRESS REPORT The stress analysis for the DAEC reactor vessel has been performed in accordance with the certified General Electric Purchase Specification and Section III of the ASME Code.

UFSAR/DAEC-1 5A-9 Revision 20 - 8/09 The stress results for the various components of the DAEC reactor vessel are summarized in calculation APED-B11-232, latest revision, hereby incorporated by reference. For each reactor pressure vessel component, the calculated stress intensities for each stress category (primary membrane stress intensity, local membrane plus bending stress intensity, and primary plus secondary stress intensity range) are compared with the appropriate Section III, ASME Code allowable. The fatigue usage factors are also calculated, where appropriate, and compared to the code allowable limit.

UFSAR/DAEC-1 5A-10 Revision 20 - 8/09 5A.4 SURVEILLANCE AND TESTING 5A.4.1 QUALITY CONTROL

General Electric requirements for inspection and quality control are the same for both shop and field, but they may be expected to differ somewhat in the method of achievement for the same end result (see Chapter 17).

With site assembly, the attention of fewer people is directed more entirely to the pressure vessel under construction. However, there is more formal documentation of specific detailed

operations such as found in a shop. Therefore, special effort and emphasis are directed toward maintaining controls in the field that are equivalent to shop practices where each operational step is detailed on a document sheet called a "traveler." The traveler contains formal automatic work stops and checkoffs for inspection, and, in addition, automatically incorporates the details of the approved written procedures. Means are provided in the field for a quality control system, instruction and diligence, to provide the equivalent of shop practice. This provides the assurance of working to approved written procedures and also ensures that proper inspections and quality control are performed at the required times.

As there are fewer field personnel than shop personnel, the field personnel used may be less specialized and somewhat broader in coverage than their counterparts in the shop. In this manner, the areas of supervision, inspection, and quality control are properly and adequately covered. Therefore, some field quality control procedures for dimensional, welding, and materials control are more specific than required for reactor vessels in the shop where standard practices and chain of command are well established. With all of the responsible people paying attention to one vessel, the inspection and quality control function at the site is equivalent to that

in the shop.

The reactor vessel was fabricated and assembled in accordance with the GE quality control plan for a BWR vessel. This plan is a formal document that defines the quality control and inspection requirements to the supplier. The plan requires complete access for GE surveillance of all work on the vessel and defines many mandatory witness points for materials, testing, heat treatment, welding, and nondestructive testing.

The identical plan is applied for shop- and field-assembled vessels. Chicago Bridge &

Iron was required to develop written procedures for welding, heat treating, radiography, and several other operations. The detailed drawings and procedures were reviewed and approved by

GE prior to use by CB&I.

The quality control program is designed to positively ensure that only approved drawings and procedures are used at all times and places, both in the shop and at the site. Emphasis is

placed on detailed planning and process control to ensure that the quality is built-in step by step.

UFSAR/DAEC-1 5A-11 Revision 20 - 8/09 When defects do occur, a thorough analysis is performed to determine the cause, and appropriate corrective action must be taken. The resident quality control representative reports all defects to the GE Quality and Design Engineers on a current basis. This results in additional

investigation at the shop or site (see Chapter 17).

In summary, the GE quality program plan consists of a thorough and independent verification by technically competent people during all phases of vessel assembly. General

Electric places the full burden of quality proof on CB&I and is confident that this approach gives

positive assurance of quality in accordance with specifications and the ASME Code.

The only difference between a field-assembled vessel and a shop-assembled vessel is that

quality control representatives are assigned at the site as well as in the CB&I shops.

5A.4.2 EXAMINATION

Considering the five major methods of examination given to vessel material (visual, magnetic particle, liquid penetrant, ultrasonic, and radiographic), the only difference between shop and site inspection may be the method of radiography and the processing of radiographic films.

Shop radiography of vessel sections consists of a combination of X-ray and gamma ray; however, more gamma-ray radiography was used on the DAEC site-assembled vessel than is used on most shop-fabricated-and-assembled vessels because the high-energy X-ray equipment used in the shop is not readily transportable and set up at the site. Therefore, gamma-ray radiography with a relatively large, high-energy, isotope source of cobalt 60 was used more extensively in this application. Radiography procedures using the gama-ray source have been developed and tested, and adequate sensitivity has been demonstrated.

Ultrasonic examination of the welds supplemented the radiography and was similar to the method presently used by CB&I both in the shop and in the field.

Although GE requires the approval of all inspection procedures, they also require particular attention to gamma-ray procedures. Emphasis was placed on developing an average sensitivity that is better than the required ASME Code minimum sensitivity, so that even with the larger size of the gamma-ray focal spot and the potentially greater amount of scatter (because of longer exposure times), films that had better than marginal sensitivity could be produced.

The radiographic procedures may also potentially involve less sophisticated film processing and handling techniques in the field, but high-quality field processing of radiographic film has been demonstrated. UFSAR/DAEC-1 5A-12 Revision 20 - 8/09 5A.4.3 VESSEL TESTING

The code-required hydrostatic testing of the completed site-assembled vessel is performed with temporary covers on the penetrations, much as is the practice with shop-

fabricated vessels. In addition to the ASME Code test, a design pressure test to verify the leaktightness of the head closure seal was performed to fulfill one of the many additional requirements imposed before GE would accept the DAEC reactor vessel. This test was performed with the temporary covers in place.

UFSAR/DAEC-1 5A-13 Revision 20 - 8/09 REFERENCES FOR SECTION 5A.5

1. A. Kalnins, "Analysis of Shells of Revolution Subjected to Symmetrical and Nonsymmetrical Loads," Journal of Applied Mechanics , Vol. 31, 1964, pp. 467-476, Chicago Bridge & Iron Computer Program 7-81.

2. K. R. Wichman, A. G. Hooper, and J. L. Mershon, "Local Stresses in Spherical and Cylindrical Shells due to External Loadings," Welding Research Council Bulletin 107, 1965.

3. Chicago Bridge & Iron Computer Program 6-20. This program is named "Cookbook" and is based on the data presented in Reference 2.

4. CAL-M97-015, Revision 1, Reassessment of Duane Arnold RPV Fatigue Usage.

5. APED-B11-236, Revision 0, "Reactor Vessel Tensioning Optimization Stress Report Duane Arnold Energy Center."

6. APED-B11-232, Latest Revision, "Stress Repor t - Reactor Vessel," Incorporated by Reference in Section 5A.3.5.

• "&.'l'Il\IJS1VNIOn.LlDN01r11'&.1I'"IIr:II,I,III1ILJ<'DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledPostWeldHeatTreat-LongitudinalWeldFigure5A.2-1 TEMPORARYBULKHEADINSULATION--EXHAUSTc.-------------------'BAFFLETEMPORARYBULKHEAD-VESSELWALLGIRTHrOINTWELDDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledPostWeldHeatTreat-GirthWeldFigure5A.2-2 i'f'!'>DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledVesselFlangeMachiningFigure5A.2-3 DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORT.ReactorPressureVessel-SiteAssembledTopHeadFlangeHoldDrillingFigure5A.2-4 DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledNo.1ShellRingFigure5A.2-5

\'DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledNo.2ShellRingFigure5A.2-6 <'..DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledNo.4ShellRingFigure5A.2-7 1]"/t,r\I**'\\1.,...].r..,...DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledDri11ingControlRodHo1esinBottomHeatFigure5A.2-8 DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTReactorPressureVessel-SiteAssembledPlacingHeatTreatingFurnaceinVesselFigure5A.2-9 5B-i Revision 17 - 10/03 UFSAR/DAEC-1

5B: Over Pressurization Protection TABLE OF CONTENTS Section Title Page 5.B.1 Design Evaluation...................................................... 5B-1 5.B.1.1 Valve Position Switch Scram (Direct)....................... 5B-2 5.B.1.2 High-Neutron-Flux Scram......................................... 5B-2 5.B.1.3 High Vessel Pressure Scram...................................... 5B-3 5.B.1.4 Summary of Analyses................................................ 5B-3 5.B.1.5 Sensitivity to Safety Valve Failure............................ 5B-3

5B-ii Revision 17 - 10/03 UFSAR/DAEC-1

5B: Over Pressurization Protection LIST OF FIGURES Figures Title 5B.1-1 Effect of Various Scram Times on Peak Vessel Pressure 5B.1-2 Comparison of High Pressure Vessel Transients 5B.1-3 Effect on Peak Vessel Pressure of Various Valve Failures with Turbine Generator Trip Scram following a Turbine Trip without Bypass 5B.1-4 Effect of Peak Vessel Pressure of Various Valve Failures with High Neutron Flux Scram following MSIV Closure 5B.1-5 Effect of Peak Vessel Pressure of Various Valve Failures with High Vessel Pressure Scram following a MSIV Closure 5B.1-6 Peak Vessel Pressure Versus Relief/Safety Valve Capacity

5B-1 Revision 17 - 10/03 Appendix 5B: Over Pressurization Protection 5B.1 Design Evaluation To determine the required steam-flow capacity of the safety valves, a parametric study was performed with the following assumptions:

1) The plant is operating at the turbin e-generator design condition with a vessel dome pressure of 1025 psig, a steam flow of 7.17 x 10 6 lb/hr, and a reactor thermal power of 1658 MW.

2) The reactor experiences the worst pressurization transient. Both the closure of all main steam isolation valves and a turbin e trip (without bypass response) produce severe transien ts. The evaluation of the final plant configuration has shown that the main steam isolation valve closure is slightly more severe when credit is only taken for backup scrams; therefore, it is used as the design-ba sis event for overpressure protection.

3) Direct reactor scram based on main steam isolation valve position switches (valve closure) - failed.

4) Various total capacities of dual safety

/relief valves were used. These valves functioned properly and were cons idered to be part of the total safety valve capacity requirement with a nominal lowest setpoint of 1080 psig. This satisfied the ASME Code requirement that the lowest safety valve be set at or below the vesse l design pressure of 1250 psig.

5) The design basis takes credit for high neutron flux scram, although the analysis also shows the adequacy of the valves even with high vessel pressure scram, as a backup to high flux scram.

6) Various safety valve tota l capacities were used with a 1240-psig nominal setpoint, which satisfies ASME Code, Section III requirements that the highest safety valve setpoint be less than 105% of vessel design pressure (1.05 x 1250 = 1313 psig).

7) Both the dual safety/relief valves and the spring safety valves were assumed to have 1% (high) error in pr essure setpoint throughout the study.

5B-2 Revision 17 - 10/03 Under Section III of the ASME Code, the peak allowable pressure is 110% of vessel design pressure or 1375 psig at the vessel bottom. Design specifications for safety/relief valve and spring safety valve capacities, based on the rated steam flow and the above parametric studies, were 61.9% and 10%, respectively. Th e six safety/relief valves have a combined capacity of 68.4%. Two spring safety valves are required to meet the specified 10% capacity and have a combined capacity of 18.7%. Figure 5B.1-1 shows the nominal peak vessel bottom pressures attained when the turbine trip without bypass and main steam isolation valve closure transients are terminated by various modes of reactor scram, in the order in which they would occur. Notice that when direct scrams are ignored, the main steam isolation valve closure transient is the more severe of the two transi ents. Safety/relief and spring safety valve capacities for this comparison are 68.4% and 18.7 %, respectively, representative of the six safety/relief valves and two spring safety valves. The pressure at tained with neutron flux scram is considerably lower than that attained with pressure scram. Vessel bottom pressure transients for each of the foregoing reactor high-pressure even ts are presented in Figure5B.1-2. The cases with direct (trip or position) scrams are designed to avoid lifting the spring safety valves. Using the overpressure protection system consisting of six dual-purpose safety/relief valves and two spring safety valves, analyses were performed to determine the effects on the pressure transient of various combinations of valve failures. 5B.1.1 Valve Position Switch Scram (Direct) With this protection system functioning as expected, the turbine trip without bypass transient is more severe than the main steam isolation valve cl osure transient. Figure 5B.1-3 shows the peak vessel bottom pressure attained during such a transient with one, two, or three safety/relief valves functioning properly in combination with zero, one, or two spring safety valves. As s hown, vessel overpressure protection, with a minimum margin of 25 psi, exists if three re lief valves in combination with no safety valves or two relief valves in combinati on with two safety valves function properly. Furthermore, vessel overpressure protection is maintained below code limits if two relief valves in combination with no safety valves or one relief valve in combination with two safety valves function properly. 5B.1.2 High-Neutron-Flux Scram A main steam isolation valve closure transient when terminated by a high- neutron-flux scram causes the peak neutron flux to reach its scram setpoint about 1.24 sec after a main steam isolation valve position switch scram would have been initiated. Figure 5B.1-4 shows the peak vessel bottom pressures attain ed during such a transient with three, four, or five safety/relief valves functioning properly in combination with zero, one, or two spring safety valves. As shown, vessel overpressure protection, with a minimum margin of 25 psi, exists if five relief valves in combination with no safety 5B-3 Revision 17 - 10/03 valves or four relief valves in combina tion with two safety valves function properly, Vessel pressure is maintained below code limit when four relief valves in combination with no safety valves or three relief valves in combination with two safety valves function properly. This case, using an indirect reactor scram, demonstrates compliance with the requirements of S ection III of the ASME Code. 5B.1.3 High Vessel Pressure Scram The General Electric (GE) design gives even more vessel overpressure protection by providing enough valves to adequately cover the case in which reactor scram is initiated by high vessel pressure, reached at approximately 1.70 sec af ter a valve position switch scram would have occurred. As shown in Figure5B.1-5, adequate vessel overpressure protection, with a minimum margin of 25 psi, exists if six relief valves in combination with no safety valves or five reli ef valves in combination with two safety valves function properly. 5B.1.4 Summary of Analyses Figure 5B.1-6 summarizes the results of th e analyses using relief capacity as the independent parameter. Also shown is the main steam line isolation valve closure with valve position switch scram. The evaluations described in Section 5B.1.2 assume the use of Dresser safety/relief valves, which were replaced with equivalent Target Rock valves in 1977. The safety implications of the replacement we re evaluated with the conclusion that the modification did not represent an undue ri sk to public health and safety. The only discernable effect on the transient and safety analyses concerned a slight (3.6%) reduction in valv e capacity, which led to a 4-psi peak steam-line pressure increase for the transient of turbine trip without bypass and a 5-psi peak vessel bottom pressure increase for the transient of main steam isolation valve closure. Data for the Target Rock valves are given in Tables 5.2-1 and 5.2-2. 5B.1.5 Sensitivity to Safety Valve Failure A study of a typical high-power-density BWR was conducted to show the sensitivity of peak vessel pressu re to valve operability. This study is applicable to the DAEC reactor and is supplemental to previous overpressure protection analyses. safety valve is approximately 20 psi. To fu rther substantiate this study, a safety analysis assuming plugged bypass flow holes was submitted on June 10, 1975, and showed a sensitivity of 19 psi for a flux scram w ith one inoperable relief valve. Rather than perform a DAEC plant-specifi c analysis based on the failure of a safety valve with high-flux scram, reference is made to a generic an alysis provided in a GE letter to the NRC (Ivan F. Stewart to Victor Stello, Jr.) da ted December 23, 1975. The results provided in this le tter are described below. 5B-4 Revision 17 - 10/03 The design of safety/relief valves for GE reactors is based on the requirements of Section III of the ASME Code, which has been adopted by the NRC as part of the requirements in the Code of Federal Regulations (10 CFR 50.55a). It is GE's interpretation that this code does not require the failure of a qualified safety/relief valve in addition to the failure of the direct safety-grade position scram and is therefore not considered to be part of the licensing basis for reactor vessel over pressure protection. Furthermore, the consideration of the failure of the direct safety-grade position scram by itself requires multiple equipment failures. The probability of an overpressurization event with these multiple equipment failures is so low that such an event should be considered, as a minimum, an "emergency" c ondition. Therefore, the application of the emergency limit under these assumed failure conditions would be appropriate. In determining the required safety/rel ief valve capacity, GE conservatively assumes the failure of all direct safety-grade position scrams in the analysis. The GE analysis conservatively relies on indirectly de rived signals (high neutron flux) from the reactor protection system, and although this cond ition could appropriately be classified as an emergency condition, GE conservatively applies the "upset" code requirements rather than the emergency limits. In summary, the sensitivity study shows that several valves have to fail in order to violate the emergency limit. General Electric considers the failure of the direct position scram and subsequent shutdown by high-neutron-flux scram, with all safety-relief valves operable, to satisfy the code requirements and to be an appropriate licensing basis for reactor vessel overpre ssure protection.

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