ML17157B680

Duane Arnold Energy Center, Revision 24 to Updated Final Safety Analysis Report, Chapter 6, Engineered Safety Features

ML17157B680
Person / Time
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
NG-17-0111
Download: ML17157B680 (315)

Text

UFSAR/DAEC - 1 6.1-1 Revision 22 - 5/13

6.1 ENGINEERED

SAFETY FEATURE MATERIALS

6.1.1 METALLIC

MATERIALS

See Section 6.2.1.1.1.3 for mechanical property requirements for all materials used in the fabrication of pressure-containing components of the containment system.

Applicable codes and regulations used in the design and fabrication of the pressure suppression containment system are discussed in Section 6.2.1.1.1.4.

See Table 6.2-3 for a listing of primary containment materials. The primary containment is chiefly fabricated of SA-516, Grade 70 plates. The vent pipes connecting the drywell and torus are fabricated of SA-516, Grade 70 steel. The vent system is coated inside and out with paint to protect the metal against rusting.

Material and examination requirements for piping and valves are described in

Section 17.1.8.

The environmental design requirements for mechanical and electrical equipment

are discussed in Section 3.11.

6.1.2 ORGANIC

MATERIALS

Coating qualified for use inside primary containment (i.e., safety related, Service Level I) are qualified and controlled under the DAEC Protective Coatings Program (DAECPCP). In the case of Service Level I coatings system laboratory testing, irradiation and simulated Design Basis Accident (DBA) testing are included in the qualification process.

The suppression pool contains demineralized water with no inhibitors or

additives.

2011-021

°

°

Thermally Induced Pressurization

Water Hammer and Two-Phase Flow

°

Table 6.2-4 Sheet 1 of 2 GENERAL DRYWELL DESIGN CONDITIONS

Design Pressures Internal - maximum 62 psig at 281

°F - design 56 psig at 281

°F - operating

<2 psig at 150

°F External - maximum 2 psig at 281

°F - design 2 psig at 281

°F - operating

<2 psig at 150

°F Earthquake Horizontal (See curves in Figure 6.2-72)

Vertical (reviewed for 0.108g) 5.3%g

Weight of Compressible Material None

Bellows Loads Inside - operating 60 lb/in.

- refueling 0

Outside - operating 30 lb/in.

- refueling 125 lb/in.

Loads To Be Transferred Through Drywell At bottom of drywell elevation =

Vertical - normal 6,400,000 lb

- refueling 6,510,000 lb Horizontal 1,000,000 lb Moment 480,000,000 in.-lb

At stayed elevation =

(maximum at any one stabilizer)

Without jets 200,000 lb With jets 275,000 lb

Wind (prior to construction of the reactor building)

In accordance with ASCE paper 3269, "Wind Forces on Structures"

Table 6.2-4 Sheet 2 of 2 GENERAL DRYWELL DESIGN CONDITIONS

Top of Refueling Water To be at elevation

Miscellaneous Live Loads Personnel lock floor 5,500 lb Equipment access opening 80,000 lb Upper beam seats 766,800 lb Lower beam seats 640,000 lb Weights of all appurtenances are estimated weights and may be heavier than the

actual weights.

Jet Forces Location: On spherical part 393 kip of drywell (2.19 ft 3 subject to jet force) (maximum)

On cylindrical part and 325 kip sphere transition to cylinder (maximum)

(1.80 ft 3 subject to jet force)

On closure head (0.18 ft 3 subject to jet 32.6 kip force) (maximum)

Steam and/or water temperature 300°F Shell temperature 150°F Stabilizer Loads Seismic force 200 kip Seismic plus jet forces 275 kip Seismic plus flooded condition 200 kip

________________________

NOTE: The vessel was designed and analyzed for the conditions included in this table, in accordance with the Bechtel specification.

Table 6.2-5

GENERAL SUPPRESSION CHAMBER DESIGN CONDITIONS

Design Pressures Internal - maximum 62 psig at 281

°F - design 56 psig at 281

°F - operating <2 psig at 50-150

°F External - maximum 2 psig at 281

°F - design 2 psig at 281

°F - operating <2 psig at 50-150

°F Earthquake

Horizontal (reviewed for 0.30g) 12%g

Vertical (reviewed for 0.108g) 5.3%g

Water Volumes

Normal operating 58,900 ft 3

Accident and test 61,500 ft 3

Catwalks

Live load 75 lb/ft 2

Jet Forces

Downcomer (24-in. diameter) 21 kip (maximum)

_____________________

NOTE: Weights of appurtenances are estimated weights and may be more than actual weight.

a

Table 6.2-8

SUPPRESSION CHAMBER LOADING COMBINATIONS

CB&I Case Number

______________________________________________________________________________

(1) (2) (4)

Overload Final (3) Normal (5) (6) Load

Loads Test Test Construction Operating Accident Flooding Symbol a

Dead load, vessel and

attachments X X X X X X D

Suppression

pool water X X X X X D

Pressure (psi)

Positive 70 56 2 56 R

Negative 2 2 R

Seismic Vertical X X X X X X E or E'

Lateral X X X X X X E or E'

Vent thrusts X X X X R

Contained

air X X D

Live loads on catwalks and

platforms X X D

Jet forces

on downcomer

pipes X R

a Used to indicate load combinations in Tables 6.2-9 through 6.2-14.

UFSAR/DAEC-1

Table 6.2-9 Sheet 1 of 2 DRYWELL MEMBRANE STRESSES

Description/Criteria

Methods of

Analysis

Load Combination Maximum Allowable

Stress (ksi)

Maximum Stresses (ksi)

t 1

Location

The vessel is bulb shaped and

houses the primary nuclear

reactor vessel, the coolant

recirculation lines, pumps, etc. In case of operating

accident, the vessel must

contain the steam released

within the drywell and conduct

this steam to the suppression

chamber.

ASME Code, Section

III, Including Code

Cases 1330, 1177, and 1413, and

addenda as of summer

1968 Vessel Class B

D + R + E

D + R + E

Primary general membrane

PM = 17.5 at 281°F Circumferential Meridional

8.75

6.32 3.15

Head

Cylinder Stress intensities and limits are

defined per ASME

Code,Section III, paragraph N-413 Structural steel plate

material is ASME SA-516 to

SA-300; minimum service temperature is 30

°F, with Charpy impact requirements at

a maximum 0

°F.

D + R + E

16.18

Knuckle at End conditions are found with methods

described in Ref. 30 D + R + E 15.46 Sphere UFSAR/DAEC-1

Table 6.2-9 Sheet 2 of 2 DRYWELL MEMBRANE STRESSES

Description/Criteria

Methods of

Analysis

Load Combination Maximum Allowable

Stress (ksi)

Maximum Stresses (ksi)

t 1

Location

Seismic design load includes

load due to vertical

acceleration equal to 5.3%g.

For other design criteria, see

Table 6.2-4.

D + R + E'

Yield 33.7 at 300°F

16.3

Knuckle at After an accident, the drywell

may be flooded up to el. 854

ft 6 in.; stresses shall be

below yield point.

D + R + E'

D + R + E'

15.99 13.51

10.84 6.96

Sphere

Embedment at Accident load (R) includes

pressure and temperature in

the primary containment. D + E + Flood Yield 38.0 at ambient

Ultimate 70.0

Critical buckling 24.47 (meridional) 22.07 9.75 Embedment at NOTE: For simplicity, only additive stresses are shown.

UFSAR/DAEC-1

UFSAR/DAEC-1

UFSAR/DAEC-1

Table 6.2-11 Sheet 1 of 2 DRYWELL STABILIZER SHEAR LUG STRESSES

Description/Criteria

Methods of

Analysis

Load Combination Maximum Allowable Stress (ksi) Maximum Stresses (ksi)

Location

The stabilizer

mechanism transfers

into building the

reaction due to

seismic loads or

seismic plus jet

loads acting on the

drywell, reactor, and

shield; or seismic, plus flooding of the

drywell.

ASME Code,

Section III, including

addenda as of

Summer 1968, Vessel Class B Male Lug

D + E B = 18.0

(plate)

C = 18.0

(weld)

D + R + E B = 36.0

C = 31.9

B = 8.2 (plate)

C = 9.6 (weld)

B = 11.2

C = 12.5

Stabilizer

shear lug

for drywell at The geometry of the

stabilizer allows for

radial and vertical

movements due to

pressure and

temperature.

Ref. 30, Case

22 for plate D + E + Flood B = 36.0 B = 16.4 UFSAR/DAEC-1 Table 6.2-11 Sheet 2 of 2

DRYWELL STABILIZER SHEAR LUG STRESSES

Description/Criteria Methods of Analysis Load Combination Maximum Allowable Stress (ksi) Maximum Stresses (ksi)

Location

Materials for

components attached

to drywell are ASME

SA-516, Grade 70, to

SA-300, per ASME

Code,Section III;

those for concrete

anchors are A-36 per

AISC-1963.

C = combined stress Female Lug D + E C = 19.0 (plate)

C = 11.4 (weld)

C = 6.8

C = 5.9 ----------- (B+T)2+(S)2 where:

B = bending

stress

T = tensile

stress

S = shear

stress

D + R + E C = 38.0

C = 22.8

D + E + Flood C = 38.0

C = 22.8

C = 8.9

C = 7.8

C = 24.7

C = 21.5 UFSAR/DAEC-1

UFSAR/DAEC-1

UFSAR/DAEC-1

UFSAR/DAEC-1

UFSAR/DAEC-1

Table 6.2-14 Sheet 1 of 2 MAXIMUM STRESSES IN DRYWELL PENETRATION NOZZLES

Description/Criteria

Methods of Analysis

Load Combination Maximum Allowable

Total Stress (ksi)

Maximum Stresses (ksi)

Elevation

Penetration And Service Pipe penetration for process

lines must accommodate thermal

movement and must resist

relatively high thermal stress;

therefore, expansion bellows are

required. The process lines are

anchored outside the containment

to limit the movement relative

to the containment. This design

assures integrity of the

penetration (see Figure 6.2-2).

Welding Research Council Bulletin

D + R

D + R

52.5

52.5

37.66

37.46 X-7A through X-7D, primary steam

X-9A through X9B, primary feedwater The penetration nozzle is welded

to the drywell. The process

line, which passes through the

nozzle, is free to move axially, with the two-ply bellows joint

accommodating the movement. A

guard pipe, which surrounds the

process line, is designed to

protect the bellows should the

process line fall within the

penetration. The two-ply

expansion joint permits periodic

leak testing of the bellows

during normal operation of the

plant by pressurizing the

annular gap between the two

plies. D + R

D + R

D + R 52.5

52.5

52.5 37.76

37.48

37.22 X-11, HPCI steam

to turbine

X-12 RHR supply

X-13 A and B, RHR

system return

UFSAR/DAEC-1

Table 6.2-14 Sheet 2 of 2 MAXIMUM STRESSES IN DRYWELL PENETRATION NOZZLES

Description/Criteria

Methods of Analysis

Load Combination Maximum Allowable

Total Stress (ksi)

Maximum Stresses (ksi)

Elevation

Penetration And Service The design of the penetration

takes into account the

simultaneous stress associated

with internal pressure, thermal

expansion, dead loads, seismic

loads, and loads associated with

loss-of-coolant accident.

Restraint lugs on the guard pipe

are provided to transfer any

load associated with random

failures of the process line

directly to the vessel without

causing any bending moment

stresses. The penetration

nozzle design takes into account

the jet force loading resulting

from the failure. D + R

D + R

D + R 52.5

52.5

52.5 37.23

35.68

37.23 X-14, cleanup

supply

X-16 A and B, core

spray

X-17, RPV head

spray Structural steel plate material

is ASME SA-516-70 to SA-300. Maximum allowable total stress

is 3 S m.

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REVISION 24 - 04/17 C003-073 REV. 10 FIGURE 6.2-40 RADIAL PENETRATIONS SUPPRESSION CHAMBER -

REPORT D, LLC ER

E ORT C

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UFSAR-DAEC-1 6.3-1 Revision 17 - 10/03

6.3 EMERGENCY

CORE COOLING SYSTEMS

6.3.1 DESIGN

BASES AND

SUMMARY

DESCRIPTION

This section provides the design bases for the emergency core cooling systems (ECCS),

formerly the core standby cooling systems (CSCS), and a summary description of these systems as an introduction to the more detailed design descriptions provided in Section 6.3.2 and to the performance analysis provided in Section 6.3.3.

6.3.1.1 Design Bases

6.3.1.1.1 Performance and Functional Requirements

The ECCS is designed to provide protection against the postulated LOCA caused by ruptures in the primary system piping. The functional requirements (i.e., coolant delivery rates) specified in detail in Table 6.3-1 are such that the system performance under all LOCA conditions postulated in the design satisfies the requirements of 10CFR50.46. (Note: These are the original design values. Sensitivity studies were performed (Reference 12) that demonstrated margin was available to relax these performance requirements while still meeting the acceptance criteria of 10CFR50.46. See Section 15.0 for current values used in the LOCA analysis. These requirements, the most important of which is that the post-LOCA peak cladding temperature (PCT) be limited to 2200°F, are summarized in Section 6.3.3. In addition, the ECCS is designed

to provide the following:

1. Protection is provided for any primary system line break up to and including the double-ended break of the largest line.

2. Two independent phenomenological cooling methods (flooding and spraying) are provided to cool the core.

3. One high pressure cooling system is provided, which is capable of maintaining the water level above the top of the core and preventing automatic depressurization system (ADS) actuation for small breaks.

4. Automatic actuation is provided such that no operator action is required until 10 min after an accident, to allow for operator assessment and decision.

5. The ECCS is designed to satisfy all criteria specified in this section for any normal mode of reactor operation.

UFSAR-DAEC-1 6.3-2 Revision 13 - 5/97

6. A sufficient water source and the necessary piping, pumps, and other hardware are provided so that the containment and reactor core can be flooded for possible core heat removal following a LOCA.

6.3.1.1.2 Reliability Requirements

The following reliability requirements apply:

1. The ECCS conforms to all applicable requirements for redundancy and separation.

2. To meet the above requirements, the ECCS network has built-in redundancy so that adequate cooling can be provided, even in the event of specified failures. As a minimum, the following equipment makes up this system:

a. One high-pressure coolant injection (HPCI) system.

b. Two core spray (CS) systems.

c. One low-pressure coolant injection (LPCI) system.

d. One automatic depressurization system (ADS).

3. The system is designed so that a single active component failure, including power buses, electrical and mechanical parts, cabinets, and wiring, cannot disable the automatic depressurization system.

4. If there is a break in a pipe that is not a part of the ECCS, no single component failure in the system prevents automatic initiation and successful operation of less than one of the following combinations of ECCS equipment:

a. Two LPCI pumps, one core spray loop, the automatic depressurization system, and the HPCI system (i.e., single diesel-generator failure).

b. Two LPCI pumps, one core spray loop and the automatic depressurization system (i.e., Division II 125V battery failure).

c. Four LPCI pumps, two core spray loops, and the automatic depressurization system (i.e., HPCI failure).

d. Two core spray loops, the HPCI system, and the automatic depressurization system (i.e., LPCI injection valve failure).

UFSAR-DAEC-1 6.3-3 Revision 17 - 10/03

5. If there is a break in a pipe that is a part of the ECCS, no single component failure in the system prevents automatic initiation and successful operation of less than one of the following combinations of ECCS equipment:

a. Two LPCI pumps, the HPCI system, and the automatic depressurization system (core spray break with a concurrent diesel-generator failure).

b. Two LPCI pumps and the automatic depressurization system (core spray break with a concurrent Division II 125V battery failure).

c. One core spray, HPCI system, and automatic depressurization system (core spray, LPCI injection valve failure).

d. Two LPCI pumps, one core spray loop, and automatic depressurization system (HPCI break with a concurrent diesel-generator failure or HPCI break with a

concurrent single 125V battery failure).

e. Two core spray loops and automatic depressurization system (HPCI break, LPCI injection valve failure).

These are the minimum ECCS combinations that result after assuming any failure (from item 4 above), and assuming that the ECCS line break disables the affected system.

6. Long-term (10 min after initiation signal) cooling requirements call for the removal of decay heat via the service water system. In addition to the break that initiated the loss-of-coolant event, the system can sustain one active failure and still have at least one RHR pump with a heat exchanger, and 100% service water flow to the heat exchanger operating for heat removal. For the LOCA analysis (Chapter 15.2.1), long-term core cooling requires core reflood above the top of the active fuel (TAF) OR core reflood to top of the jet pump and one core spray operating.

7. Offsite ac power is the preferred source of ac power for the ECCS network, and every reasonable precaution is made to ensure its high availability. However, onsite ac power has sufficient diversity and capacity to meet all the above requirements, even if offsite ac

power is not available.

8. Each system of the ECCS network, including flow rate and sensing networks, is capable of being tested during shutdown. All active components (except those that could impact

on plant operation) are capable of being te sted during plant operation, including logic required to automatically initiate component action.

UFSAR-DAEC-1 6.3-4 Revision 13 - 5/97

9. Provisions for testing the ECCS network components (electronic, mechanical, hydraulic and pneumatic, as applicable) are installed in such a manner that they are an integral and

nonseparable part of the design.

6.3.1.1.3 ECCS Requirements for Protection from Physical Damage

The ECCS piping and components are protected against damage from the effects of movement, thermal stresses, the effects of th e LOCA, and the design-basis earthquake (DBE).

The ECCS is protected against the effects of pipe whip, which might result from piping failures up to, and including, the design-basis LOCA. This protection is provided by separation, pipe whip restraints, or energy-absorbing materials if required. One of these three methods is applied to provide protection against damage to piping and components of the ECCS, which

otherwise could reduce ECCS effectiveness to an unacceptable level.

For the purpose of mechanical separation ECCS components are in two divisions. The Division 1 ECCS components include the following:

1. Core spray loop A.

2. RHR pumps A and C.

3. Automatic Depressurization System.

The Division 2 ECCS components include the following:

1. Core spray loop B.

2. RHR pumps B and D.

3. High-pressure coolant injection.

Two RHR pumps and one core spray pump in each division are in a common compartment (the HPCI pump is in its own compartment). This compartmentalization ensures that environmental disturbances such as fire, pipe rupture, flooding, etc

., affecting one division does not affect the remaining division. For ECCS mechanical components outside the pump compartments, such as the outboard containment isolation valves, separation between the

different divisions is provided by distance or by locating the components in different compartments.

Electrical separation is described in Section 8.3.

UFSAR-DAEC-1 6.3-5 Revision 13 - 5/97 6.3.1.1.4 ECCS Environmental Design Basis

Each system of the ECCS injection network, except the HPCI system, has a safety-related injection/isolation check valve located in piping within the drywell. The HPCI system injects through the feedwater system, and the (non-ECCS) RCIC system injects through the other feedwater system. However, both systems have isolation valves in the drywell portion of their steam supply piping. No portion of the ECCS and RCIC piping is subject to drywell flooding, since water drains into the suppression chamber through the downcomers.

6.3.1.2 Summary Descriptions of ECCS

The ECCS injection network comprises an HPCI system, a low-pressure core spray system, and the LPCI mode of the RHR system. These systems are briefly described here as an introduction to the more detailed system design descriptions provided in Section 6.3.2. The automatic depressurization system, which assists the injection network under certain conditions, is also briefly described. Boiling-water reactors (BWRs) with the same ECCS design are listed

in Reference 1.

6.3.1.2.1 High-Pressure Coolant Injection System

The HPCI system pumps water through one of the feedwater spargers. The primary purpose of the HPCI system is to maintain the reactor vessel water inventory after small breaks

that do not depressurize the reactor vessel.

6.3.1.2.2 Core Spray System

The two core spray system loops pump water into peripheral ring spray spargers, mounted above the reactor core. The primary purposes of the core spray are to provide inventory makeup and spray cooling during large breaks in which the core is calculated to uncover. Following ADS initiation, the core spray provides inventory makeup following a small

break.

6.3.1.2.3 Low-Pressure Coolant Injection

Low-pressure coolant injection is an operating mode of the RHR system. Four pumps deliver water from the suppression pool to the selected recirculation loop, which discharges inside the core shroud region. The primary purpose of low-pressure coolant injection is to provide vessel inventory makeup following la rge pipe breaks. Following ADS initiation, low-pressure coolant injection provides inventory makeup following a small break.

UFSAR-DAEC-1 6.3-6 Revision 17 - 10/03

6.3.1.2.4 Automatic Depressurization System

The automatic depressurization system uses a number of the reactor safety relief valves to reduce reactor pressure during small breaks, in the event of HPCI failure. When the vessel pressure is reduced to within the design of the low-pressure systems (core spray and low-pressure coolant injection), these systems provide inventory makeup so that acceptable postaccident temperatures are maintained.

6.3.2 SYSTEM

DESIGN

More detailed descriptions of the individual systems, including individual design characteristics of the systems, are covered in detail in Sections 6.3.2.2.1 through 6.3.2.2.4. The following discussion provides details of the combined systems, and in particular, those design features and characteristics that are common to all systems.

6.3.2.1 Piping and Instrumentation and Process Diagrams

The piping and instrumentation diagrams for the ECCS and the process diagrams that identify the various operating modes of each system are identified in Section 6.3.2.2.

6.3.2.2 Equipment and Component Descriptions

The starting signal for the ECCS comes from at least two independent and redundant

sensors of high drywell pressure and low reactor water level. The ECCS is actuated automatically and is designed to require no operator action during the first 10 min following the accident. A time sequence for starting the systems is provided in Table 8.3-1. (Note: These are the original design values. Sensitivity studies were performed (Reference 12) that demonstrated margin was available to relax these performance requirements while still meeting the acceptance criteria of 10CFR50.46. See Section 15.0 for curre nt values used in the LOCA analysis.

Electric power for operating the ECCS (except the dc-powered HPCI and automatic depressurization system) is from the preferred offsite ac power supply. Upon loss of the preferred source, operation is from the onsite standby diesel-generators. Chapter 8 contains a more detailed description of the power supplies for the ECCS.

As discussed in Section 1.8.1, the low pressure ECCS pumps must rely upon containment (wetwell) pressure for meeting Net Positive Suction Head (NPSH) requirements at elevated suppression pool temperatures, as shown in Figure 5.4-15(a). However, there are limitations on the containment pressure that can be credited for satisfying these NPSH requirements (Fig. 5.4-15(b)).

UFSAR-DAEC-1 6.3-7 Revision 21 - 5/11 Requirements for net positive suction head at the centerline of the pump suction nozzles for each pump are given in Figures 6.3-1 (HPCI), 6.3-2 (core spray), and 6.3-3, Sheets 1 and 2 (LPCI). Pump characteristic curves are given in Figures 6.3-4 (HPCI), 6.3-5 (core spray), and

6.3-6 (LPCI).

As part of the plant's review for Generic Letter 2008-01 (Ref. 15 and 16), CS, RHR, and HPCI system suction and discharge piping designs were evaluated for potential sources of gas accumulation. Walkdowns of these piping systems were conducted that confirmed plant as-built configurations were consistent with design dr awings/specifications with respect to proper locations for vent valves and piping slope. Plant procedures were reviewed for potential enhancements to preclude unacceptable voiding in these piping systems upon return to service from maintenance or re-alignment to standby readiness conditions from secondary modes of operation. Filling and venting operations were found to the highest potential risk for unacceptable gas accumulation. Procedure upgrades were made, including the addition of ultrasonic testing (UT) inspections of identified piping high points to verify proper filling and venting as part of return to service, and instructions to write Corrective Action Program (CAP) documents whenever voiding is detected.

6.3.2.2.1 High-Pressure Coolant Injection System

The HPCI system consists of a steam turbine that drives a constant-flow pump, system piping, valves, controls, and instrumentation.

Figure 7.3-10, Sheets 1 through 3, are the HPCI flow control diagrams and Figure 6.3-1 is the HPCI process diagram. Figure 6.3-7, Sheets 1 and 2, is the HPCI piping and instrumentation diagram.

The principal HPCI system equipment is installed in the reactor building. The turbine-pump assembly is located in a shielded area to ensure that personnel access to adjacent

areas is not restricted during the operation of the HPCI system. Suction piping comes from the condensate storage tank and the suppression pool. Injection water is piped to the reactor feedwater pipe at a T-connection. Steam supply for the turbine is piped from a main steam header in the primary containment. This piping is provided with an isolation valve on each side of the drywell barrier. Remote controls for valve and turbine operation are provided in the main control room. The controls and instrumentation of the HPCI system are described, illustrated, and evaluated in detail in Section 7.3.1.1.2.

The HPCI system is provided to ensure that the reactor is adequately cooled to meet the design bases in the event of a small break in the nuclear system and a loss of coolant that does not result in rapid depressurization of the reactor vessel. The HPCI system permits the nuclear plant to be shut down while maintaining sufficient reactor vessel water inventory until the reactor vessel is depressurized. The HPCI system continues to operate until reactor vessel pressure is below the pressure at which either LPCI operation or core spray system operation maintains core

cooling.

UFSAR-DAEC-1 6.3-8 Revision 21 - 5/11 If a LOCA occurs, the reactor scrams on the receipt of a low water level signal from the reactor or a high-pressure signal from the drywell. The HPCI system starts when the water level drops to a preselected height above the core, or if high pressure exists in the primary containment. The HPCI system automatically stops when it receives a signal of high water level

in the reactor vessel.

The HPCI system is designed to pump water into the reactor vessel for a wide range of pressures in the reactor vessel. Two sources of water are available. Initially, the system uses demineralized water from condensate storage. Approximately 75,000 gal of the 400,000 gal condensate storage are held in reserve for the HPCI system and the RCIC system. System demands on condensate storage other than the HPCI system and RCIC system will draw from an elevated tank connection with the exception of the core spray outlet, which is connected to the RCIC penetration by two locked-closed valves (see Figure 7.3-3). This isolation arrangement is in accordance with the established HPCI/RCIC system design requirements. This tank connection is set at a level so that approximately 75,000 gal will be below the intake and unavailable to these other systems. Both the HPCI system and RCIC system connect separately to the condensate storage tank near the bottom. Should the condensate storage tank be drawn down to a low level, automatic transfer to the suppression pool occurs. Water from either source is pumped into the reactor vessel via the feedwater sparger, causing mixing with the hot water or steam in the reactor pressure vessel.

To ensure positive suction head to the pump, the pump is located below the level of the condensate storage tank and below the water level in the suppression pool. Pumps meet net positive suction head (NPSH) requirements by providing adequate suction head and adequate

suction line size.

The HPCI system turbine-pump assembly and piping are located so as to be protected from the physical effects of design-basis accidents, such as pipe whip and high temperatures; the equipment is located outside the primary containment.

The feedwater spargers in the reactor vessel are used for high-pressure coolant injection.

Each sparger is mounted to the inside reactor vessel surface. The thermal sleeve is welded to the

feedwater nozzle on one end and connected to the sparger by a slip fit on the other end.

Therefore, the feedwater sparger is removable. The spargers are mounted in the vessel at one elevation to distribute the feedwater in a symmetrical pattern about the vessel axis. Each sparger is supported by the thermal sleeve and a bracket mounted to each end of the sparger. Provision is made for the differential expansion between the stainless steel sparger and carbon steel vessel.

Radial differential expansion is taken up by the slip fit of the sparger connection into the vessel nozzle thermal sleeve. Tangential differential expansion is taken up by tangential slots cut in the bracket mounted to each end of the feedwater spar ger bracket. The sparger is analyzed with the thermal sleeve welded into the nozzle. In addition, pressure differentials, jet reactions, and

earthquake loading are all added; these stresses within the sparger are all within the allowable

stresses given in the ASME Code,Section III, for Class 1 vessels.

UFSAR-DAEC-1 6.3-9 Revision 21 - 5/11 The presence of a steam bubble near the normally closed injection valve (MO2312) to the feedwater system (See Figure 6.3-18 for a simplified representation of the energy transport mechanisms) has been analyzed for potential effects, with the overall conclusion that the pressure transients due to the collapse of the steam bubble are structurally acceptable and do not challenge the ability of the HPCI system to perform its design safety functions. This analysis encompasses a range of steam bubble sizes, with the largest predicted steam bubble nearly filling the horizontal piping run immediately upstream of MO2312. The loads from the steam bubble collapse transient are included in the applicable piping analyses, which conclude that all pipe stresses and support components meet design basis allowable limits. Thus, the HPCI pump discharge piping is adequately filled to support performance of the HPCI system design safety functions when the standy readiness pressure in the HPCI pump discharge piping at MO2312 is not less than the pressure provided by the static head from a 8 feet CST level.

While the presence of a steam bubble near MO2312 does not adversely affect the HPCI system, capability is provided for the Condensate Service Water system to provide a "high pressure" keep fill for the HPCI pump discharge piping near MO2312 that minimizes the conditions for this steam bubble near MO2312 at operating power levels. The connection flow path from the Condensate Service Water system to the HPCI pump discharge piping incorporates

series check valves to preclude diversion of HP CI flow or inadvertent pressurization of the Condensate Service Water system in the event of one check valve failing to close. A pressure relief valve is provided for the "closed volume" upstream of MO2312 to preclude over pressurization from the thermal expansion of water (e.g., during plant startup to normal full

power operation).

HPCI is also vented at its high points to remove accumulation of non condensable gases. Venting may be performed if either the "high pressure" or "low pressure" keep fill systems are in operation. In the event that neither the "high pressure" nor "low pressure" keep fill systems are in operation, CST tank level is monitored in the control room at 8 ft to ensure an adequate water level is available in the CST tanks to allow for acceptable venting.

Steam from the reactor drives the HPCI system turbine. Decay heat and stored heat generate steam, which is extracted from a main steam header upstream of the main steam line isolation valves. The two HPCI system isolation valves in the steam line to the HPCI system turbine are normally open to keep piping to the turbine at elevated temperatures and to permit rapid startup of the HPCI system. Signals from the HPCI system control system open or close the turbine stop valve.

To prevent the HPCI system steam supply line from filling with water, a condensate drain pot is provided upstream of the turbine stop valve. The drain pot normally routes condensate to the main condenser, but on a receipt of an HPCI system initiation signal or loss of control air pressure, isolation valves on the condensate line shut automatically.

UFSAR-DAEC-1 6.3-10 Revision 21 - 5/11 Two devices control turbine power: (1) a speed governor limits turbine speed to its maximum operating level and (2) a control governor with an automatic speed setpoint control is positioned by a demand signal from a flow controller to maintain constant flow over the pressure range of HPCI system operation. When the governor is in the test mode, it can be operated manually; however, it is automatically repositioned by the demand signal from the flow controller if system initiation is required.

As reactor steam pressure decreases, the HPCI system turbine throttle valve opens wider; this permits the passage of the steam flow required to provide necessary pump flow.

Exhaust steam from the HPCI system turbine is discharged to the suppression pool. A

drain pot at the low point in the exhaust line collects condensate that is discharged to the suppression pool or bypassed to the barometric condenser.

The HPCI system turbine gland seals are vented to the HPCI system barometric condenser, and part of the water from the HPCI booster pump is routed through the condenser for cooling purposes. Noncondensible gases from the barometric condenser are exhausted through the standby gas treatment system.

The system piping is designed in accordance with the requirements stated in Chapter 3.

The HPCI system equipment, piping, and support structures are designed as Seismic Category I equipment.

The system is managed and inspected for aging effects, including corrosion, erosion, and material fatigue.

The startup of the HPCI system is completely independent of ac power. For startup to occur, only dc power from the plant batteries and steam extracted from the nuclear system are

required.

Various operations of the HPCI system components are summarized as follows: The HPCI system controls automatically start the system and are designed to bring it to design flow rate within 30 sec from the receipt of a low water level signal from the reactor vessel or a high-pressure signal from the primary containm ent (drywell), however the licensing basis LOCA analysis (Chapter 15.2.1) conservatively assumes that design flow is achieved within 45 sec.

The HPCI system turbine is shut down automatically (with the exception of the Manual

Push button) by any of the following signals:

1. Turbine overspeed - This prevents damage to the turbine and the turbine casing.

UFSAR-DAEC-1 6.3-11 Revision 21 - 5/11 2. Reactor vessel high water level - This indicates that core-cooling requirements are satisfied.

3. HPCI system pump low suction pressure - This prevents damage to the pump due to loss of flow.

4. HPCI system turbine exhaust high pressure - This indicates a turbine or turbine control malfunction.

5. Automatic isolation signal.

6. Manual push button.

7. Low steam inlet pressure.

If an initiation signal is received after the turbine is shut down, the system is capable of automatic restart if no shutdown signals exist.

Because the steam supply line to the HPCI system turbine is part of the nuclear system process barrier, certain signals automatically isolate this line, causing the shutdown of the HPCI system turbine. Automatic shutoff of the steam supply is described in Section 7.3.1.1. However, the automatic depressurization system and the low-pressure systems of the emergency core cooling systems act as backup, and automatic shutoff to the steam supply does not negate the ability of the emergency core cooling systems to satisfy the safety objective.

In addition to the automatic operational features of the system, it also provides for remote manual startup, operation, and shutdown (provided initiation or shutdown signals do not exist). All automatically operated valves are equipped with a remote manual functional test feature.

HPCI system initiation automatically actuates the following valves:

1. HPCI system pump discharge test bypass valves.

2. HPCI system pump suction shutoff valve.

3. HPCI system pump discharge shutoff valve.

4. HPCI system steam supply shutoff valve.

5. HPCI system turbine stop valve.

UFSAR-DAEC-1 6.3-12 Revision 21 - 5/11 6. HPCI system turbine control valve.

7. HPCI system steam supply line drain isolation valves.

8. HPCI system condensate drain isolation valves.

9. HPCI system steam supply isolation valves.

10. HPCI system cooling water supply valve.

The hydraulic oil pump must be started and the hydraulic control system must be functioning properly before the turbine valves can be opened. The barometric condenser components must be operating to prevent outleakage from the turbine shaft seals. The startup of the equipment is automatic, but its failure does not prevent the HPCI system from fulfilling its

core-cooling objective. This is because even with steam leakage past the turbine shaft seals and valve stems into the room, no system operational limits or radiological limits are exceeded.

Before startup, the control governor may be anywhere between its high-speed and low-speed stop positions. On the receipt of an initiating signal, the flow control signal automatically runs the control governor toward its high-speed stop. (The maximum demand signal is received from the flow controller.) The same initiating signal automatically starts the hydraulic oil pump, and

when enough oil pressure is developed, both the turbine stop valve and the control valves open simultaneously and the turbine accelerates to the speed setting of either the control governor or the speed governor, whichever is lower. When rated flow is established, the flow controller signal adjusts the setting of the control governor to maintain rated flow as nuclear system

pressure decreases.

A minimum flow bypass is provided for pump protection and to help prevent an overspeed trip that might otherwise occur if the system were started with no discharge path available. The bypass valve automatically opens on a low-flow signal, and automatically closes on a high-flow signal. When the bypass is open, flow is directed to the suppression pool. A system test line

provides recirculation to the condensate storage tank during system test. Shutoff valves are provided with proper interlocks that automatically close the test line on the receipt of an HPCI system initiation signal.

Initial preoperational testing of the HPCI and RCIC systems at several BWRs revealed varying degrees of water hammer and check valve slamming that are undesirable. Preliminary testing of these systems at the DAEC (using house boiler steam) revealed a tendency for check valve noise plus the potential for water hammer, even with the improved piping layout incorporated in the DAEC design. A 2-in. vacuum breaker that allows the torus atmosphere to communicate with the HPCI/RCIC exhaust piping during turbine operation was added to mitigate these dynamic conditions.

UFSAR-DAEC-1 6.3-13 Revision 21 - 5/11 The modification consisted of vacuum breakers to ensure that during HPCI/RCIC system operation and subsequent shutdown, check valve slamming or water hammer on the exhaust line is mitigated (a later modification relocated check valve V22-0016 closer to V22-0017 to provide

added assurance).

Following system shutdown after LOCA, a closure of the motor-operated isolation valves in the vacuum breaker lines results in torus pressure forcing water to the exhaust line check

valves, precluding gaseous outleakage through this path.

During normal operation, both motor-operated valves are in the open position to ensure vacuum breaker availability should the HPCI or RCIC systems operate. The fact that either of these valves has left the full-open position is annunciated in the control room. Isolation valve

closure is initiated by concurrent signals of reactor pressure vessel low pressure (the sensors

used will be those which secure the HPCI/RCIC turbine on low pressure) and drywell high

pressure.

This logic selection ensures the availability of the vacuum breaker feature following shutdown from "normal" HPCI/RCIC operation while at the same time providing the desired containment isolation capability following a design-basis LOCA. Isolation valve power and control logic shall meet the separation requirements applied to other containment isolation valves.

The vacuum breaker arrangement incorporates series check valves that preclude

inadvertent pressurization of the torus gas space in the event of a single failure of one check valve to close.

Manual maintenance valves are provided in each leg of the vacuum breaker piping to allow the isolation of check valves for maintenance.

Test connections across the check valves allow proper valve functioning to be ascertained.

6.3.2.2.2 Automatic Depressurization System

The automatic depressurization system provides automatic nuclear system depressurization for small breaks assuming failure of the HPCI system so that low-pressure coolant injection and the core spray system can operate. The relief capacity of the automatic depressurization system is based on the time required after its initiation to depressurize the nuclear system so that the core can be cooled by the core spray and the LPCI systems and meet the requirements of 10 CFR 50.46.

The automatic depressurization system uses four of the nuclear system pressure relief valves to relieve the high-pressure steam to the suppression pool. The design, description, and

evaluation of the pressure relief valves are discussed in detail in Section 5.2.2.

UFSAR-DAEC-1 6.3-14 Revision 21 - 5/11 The pressure relief valves open automatically after receiving reactor vessel low water level signals and discharge pressure indications from any low-pressure cooling system pump (LPCI or core spray) and after a 2-min (nominal) delay. The delay provides time for the operator to manually inhibit the automatic depressurization system actuation if control room information

indicates the signals are false or actuation is not needed.

Each of the four automatic depressurization system safety relief valves is equipped with a Seismic Category I 200 gal nitrogen accumulator. The accumulators receive their supply from the nonseismic normal primary containment nitrogen pneumatic supply system (Section 9.3.1.2).

Each automatic depressurization system accumulator system has an inlet check valve at the boundary between the safety-grade accumulator system and the nonsafety drywell nitrogen supply system. The inlet check valves serve to minimize the loss of nitrogen from the automatic depressurization system accumulator systems in the event that the normal drywell nitrogen supply system should fail.

The inlet check valves are a soft-seated type which have significantly lower leakage rates than conventional hard-seated type check valves. In addition, leakage tests are performed during each refueling outage on the check valves and other system components to ensure that the leakage rates are at an acceptable level. The maximum acceptable leakage rate for the tests is 25

standard cm 3/min. The soft seat is replaceable.

Each ADS accumulator system has the capability to accommodate a nitrogen system

leakage of 30 standard cm 3/min for up to 100 days without makeup and still provide five actuations of the ADS safety/relief valves. Thus the accumulators meet the requirement of NUREG-0737, Item II.K.3.28, which is to cycle the ADS valves open five times over a 100 day

period following a design-basis LOCA.

6.3.2.2.3 Core Spray System

Figure 6.3-8 is the core spray system piping and instrumentation diagram.

The core spray system is provided to protect the core by removing decay heat following the postulated design-basis LOCA. The core spray system is designed to provide cooling to the

reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the core spray operates in conjunction with the automatic depressurization system, the effective core-cooling capability of the core spray is extended to all break sizes. This is because the automatic depressurization system rapidly reduces the reactor vessel pressure to the core spray operating range. The system design head flow characteristics

are shown in Table 6.3-1. (Note: These are the original design values. Sensitivity studies were performed UFSAR-DAEC-1 6.3-15 Revision 21 - 5/11 (Reference 12) that demonstrated margin was available to relax these performance requirements while still meeting the acceptance criteria of 10CFR50.46. See Section 15.0 for current values

used in the LOCA analysis.

The core spray system consists of two independent loops. Each loop includes one 100%

capacity centrifugal water pump driven by an electric motor, a spray sparger in the reactor vessel above the core, piping and valves that convey water from the suppression pool to the sparger, and associated controls and instrumentation. Figure 6.3-2 is a schematic process diagram of the core spray system. Figure 7.3-12 is the flow control diagram.

The actuation of the core spray system results from low ("low-low-low") water level in the reactor vessel or high pressure in the drywell. When reactor vessel pressure is low enough, the core spray system automatically sprays water onto the top of the fuel assemblies to cool the core. (The same signals start the low-pressure coolant injection, which operates independently to flood the reactor vessel and achieve the same objective.)

The core spray pumps receive power from the 4160-V ac emergency auxiliary buses.

Each core spray pump motor and the associated automatic motor-operated valves receive ac power from a different bus. Similarly, the control power for each loop of the core spray system comes from different dc buses (see Chapters 7 and 8).

The core spray pumps and all automatic valves can be operated individually by manual switches in the main control room.

Pressure indicators, flow meters, and indicator lights provide operating information in the main control room.

The following paragraphs describe the major equipment for one of two identical loops.

When the system is actuated, water is taken from the suppression pool. Flow then passes through two motor-operated gate valves that are normally open, but that can be closed by a remote manual key-lock switch from the main control room. Closure isolates the system from the suppression pool in the case of core spray system leakage. One valve is located in the core spray pump suction line, as close to the suppression pool as practical; the other valve is located toward the pump suction nozzle just upstream of the condensate storage line intertie.

A local pressure gauge for each pump indicates the presence of a suction head for the pump. The core spray pumps are located in the reactor building below the water level in the suppression pool. Separation of the pumps, piping, controls, and instrumentation of each loop is such that any single physical event cannot make both core spray loops inoperable. The switchgear for each loop is located in a separate room for the same reason.

UFSAR-DAEC-1 6.3-16 Revision 21 - 5/11 A low-flow bypass line runs from the pump discharge to a test line, shared with the RHR system, which directs the flow into the suppression pool (below the normal water level). The bypass line shutoff valve opens automatically on a low-flow signal and closes automatically on a high-flow signal. The bypass flow is required to prevent the pump from overheating when pumping occurs against a closed discharge valve. An orifice limits the bypass flow. In response

to NRC Bulletin 88-04, it has been shown by calculation and by special test that dead-heading of pumps is not likely to occur with 2 RHR pumps and a Core Spray pump discharging from their minimum flow lines into the shared line. Additional information is given in Section 5.4.7.3.

A relief valve protects the core spray system upstream of the outboard shutoff valve from

reactor pressure. The relief valve discharges to the suppression pool.

A full-flow test line allows water to be circulated to the suppression pool for system testing during normal plant operations. A remote manual switch in the main control room operates a motor-operated valve in the line that is normally closed. Partial opening of the valve

in the test line provides rated core spray flow at a pressure drop equivalent to that of the discharge into the reactor vessel. A loop flow indicator is located in the main control room.

Both injection lines are provided with two isolation valves. One of these valves is a check

valve located inside the drywell, as close as practical to the reactor vessel. Core spray injection

flow causes this valve to open during LOCA conditions (i.e., no power is required for valve actuation during the LOCA). If the core spray line should break outside the containment, the

check valve in the line inside the drywell preven ts the loss of reactor water. To facilitate operation and maintenance, two motor-operated valves are installed outside the drywell;

however, they are placed as close to the drywell as practical to limit the length of line exposed to reactor pressure. The valve nearer the containment is normally closed to back up the inside check valve for containment purposes. The outboard valve is normally open to limit the equipment needed to operate in an accident condition. When the outboard valve is closed, the inboard valve

can be operated for testing with the reactor vessel pressurized. A vent line is provided between the two motor-operated valves that can be used to measure leakage through the inside check valve or the inboard motor-operated valve. On the vent line between the two isolation valves (i.e., the check valve and the inboard motor-operated valve) the inboard vent line valve is used to ensure containment integrity and reactor coolant pressure boundary integrity (the inject line check valve is the inboard isolation valve). The vent line is normally closed with two valves, and a pipe cap.

A check valve in each core spray line just inside the primary containment prevents the loss of reactor coolant outside the containment in case the core spray line breaks. A manual valve, which is normally locked open, is provided downstream of the inside check valve. The valve shuts off the core spray system from the reactor during shutdown to permit maintenance of the upstream valves. The two pipes in the core spray system enter the reactor vessel through UFSAR-DAEC-1 6.3-17 Revision 21 - 5/11 nozzles located 180 degrees apart. Each internal pipe then divides into a semicircular header, with a downcomer at each end that turns through the shroud near the top. A semicircular sparger is attached to each of the four outlets to form two circles, one above the other and both essentially complete. Short elbow nozzles are spaced around the spargers to spray the water radially onto the tops of the fuel assemblies.

Core spray piping upstream of the outboard shutoff valve is designed for the lower pressure and temperature of the core spray pump discharge. The outboard valve and piping downstream are designed for reactor vessel pressure and temperature. All piping and pump

casings are designed in accordance with the criteria presented in Chapter 3.

As discussed in detail in Section 1.8.1, an analysis has been performed to demonstrate, under worst-case accident conditions, that adequate Net Positive Suction Head (NPSH) is available to the Core Spray pumps. The results of this analysis are shown in Figure 5.4-15(a).

However, there are limitations on containment overpressure that can be credited for satisfying NPSH requirements (Fig. 5.4-15(b)).

The RHR/core spray keep fill pump maintains system discharge piping sufficiently filled with water to prevent the potential for water hammer as discussed in Section 5.4.7.2.1.

The core spray equipment, piping, and support structures are designed in accordance with Seismic Category I criteria to resist motion effected by the DBE at the installed location within the supporting building. For seismic analysis, the core spray system is assumed to be filled with

water.

Low ("low-low-low") water level in the reactor or high pressure in the drywell signals the automatic controls to energize the core spray pumps and place system valves in the spray mode. When reactor pressure decreases, the core spray shutoff valves are signaled to open.

Flow to the sparger begins when the pressure differential opens the inside check valve. Section

7.3.1.1.2 gives further details and evaluation.

6.3.2.2.4 Low-Pressure Coolant Injection

The LPCI system is an operating mode of the RHR system. The LPCI system is automatically actuated by low water level in the reactor and/or high pressure in the drywell. It uses four motor-driven RHR pumps to draw suction from the suppression pool and inject cooling water into the reactor core.

The LPCI system, like the core spray system, is designed to provide cooling to the

reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the LPCI system operates in conjunction with the automatic depressurization system and the Core Spray system, the effective core-cooling capability of the LPCI system is extended to all break sizes because the automatic depressurization system rapidly

reduces the reactor vessel pressure to the LPCI operating range.

UFSAR-DAEC-1 6.3-18 Revision 21 - 5/11 Figure 6.3-3 is a schematic process diagram of low-pressure coolant injection. LPCI operation is based on using three of the four ac motor-driven centrifugal pumps that take water from the suppression pool and pump it into one of the two recirculation loops. The water enters the reactor through jet pumps and restores the water level in the reactor vessel. Figure 7.3-13, Sheets 1 through 3A, is the flow control diagram for the RHR system including the LPCI system.

Because the motor-operators to the recirculation discharge bypass valves may not be qualified for all postulated operating environments, analyses have been performed (Section 15.2.1) that demonstrate that the acceptance criteria of 10 CFR 50.46 are met if these valves remain open during the LOCA and allow a portion of the injected flow to be lost out of the

break.

The RHR/core spray keep fill pump maintains system discharge piping sufficiently filled with water to prevent the potential for water hammer, as discussed in Section 5.4.7.2.1.

The LPCI pumps receive power from the 4160-V ac emergency auxiliary buses. For each loop, the LPCI pump motors and associated automatic motor-operated valves receive ac power from different buses.

LPCI pumps and piping equipment are described in detail in Section 5.4.7. Also described are other functions served by the same pumps if they are not needed for the LPCI function. Portions of the RHR system requi red for accident protection are designed in accordance with Seismic Category I criteria.

6.3.2.2.5 HPCI, Core Spray, and LPCI Pump Curves

Curves showing head, horsepower, net positive suction head versus flow, and efficiency for the HPCI, Core Spray, and RHR (LPCI) pumps are presented as Figures 6.3-4a, 6.3-4b, 6.3-4c, 6.3-5, and 6.3-6. Specific speed for each pump is also indicated in these figures.

6.3.2.2.6 ECCS Principal Design Parameters

Table 6.3-1 summarizes the principal design parameters such as cooling capacity, flow, pressure, and backup systems of the emergency core cooling system. (Note: These are the original design values. Sensitivity studies were performed (Reference 12) that demonstrated margin was available to relax these performance requirements while still meeting the acceptance

criteria of 10CFR50.46. See Section 15.0 for curre nt values used in the LOCA anaylsis.

6.3.2.2.7 ECCS Actuation Parameters

See Section 15.0 for current values used in the LOCA analysis.

UFSAR-DAEC-1 6.3-19 Revision 21 - 5/11 6.3.2.2.8 Evaluation of RHR(LPCI) Pump Runout Conditions

Pump runout conditions during the first ten minutes following a LOCA could occur in certain situations where the RHR (LPCI) pumps discharge to flow paths with too little system flow resistance. The operation of the RHR (LPCI) pumps under this condition could result in damage to the pumps from cavitation and/or motor overload. The DAEC is in the category of BWR/3 and BWR/4 plants with loop selection logic systems (LSLS). The following situations could potentially result in RHR (LPCI) pump runout conditions and a subsequent reduction or loss of long-term heat removal capability following a postulated LOCA for this category of

plant:

1. Four LPCI pumps injecting into a broken recirculation loop from a single LSLS failure.

2. Four LPCI pumps injecting into both recirculation loops simultaneously, with one loop broken, from a single LSLS failure.

3. Operation with three pumps providing flow (one pump inoperable as allowed per the Technical Specifications) to the unbroken loop, w ith the single failure of a recirculation loop discharge valve to close.

4. Three LPCI pumps injecting into the broken loop, with one loop broken.

An evaluation was performed on the DAEC RHR system to determine possible effects on long-term heat removal capabilities. With respect to the above potential RHR runout conditions, no other situations were found to be more severe than conditions 1 through 4 above.

Resistance calculations were performed on the RHR-recirculation piping network to determine the loop with the highest RHR pump runout potential. The following network

configurations were evaluated with respect to their associated potential RHR runout conditions:

1. Condition 1

a. RHR pumps A, B, C, and D operating.

b. Recirculation loop B broken.

c. All RHR pumps injecting into recirculation loop B.

UFSAR-DAEC-1 6.3-20 Revision 21 - 5/11 2. Condition 2

a. RHR pumps A, B, C, and D operating.

b. Recirculation loop B broken.

c. All four RHR pumps simultaneously injecting into recirculation loops A and B (cross-tie open).

3. Condition 3

a. RHR pumps A, B, and D operating.

b. Recirculation loop B broken.

c. RHR pumps A, B, and D injecting into intact recirculation loop A.

d. Recirculation loop A discharge valve fails to close.

4. Condition 4

a. RHR pumps A, B, and D operating.

b. Recirculation loop B broken.

c. RHR pumps A. B, and D injecting into recirculation loop B.

After selecting the piping configuration presenting the greatest potential for runout, the potential for cavitation was evaluated for each RHR pump with respect to conditions 1 through 4

above. The calculated net positive suction head for each case is listed in Table 6.3-3 along with RHR pump requirements. These calculations were performed in accordance with Regulatory

Guide 1.1. In each of the above cases listed in Table 6.3-3, adequate net positive suction head was maintained for each RHR pump precluding cavitation.

Each RHR pump was evaluated for potential motor overload for the four conditions listed above. For these conditions, the maximum calculated values for motor current and allowable times at current are summarized below:

Maximum Motor Current Maximum Allowable Time at Maximum Motor Current

<1.20 of rated 25 min UFSAR-DAEC-1 6.3-21 Revision 21 - 5/11 The worst case of motor current occurs in condition 2. The motor current will remain less than 1.20 times rated. The continuous motor service factor is 1.15. Design motor data allow the motor to remain at the 1.20 value for 25 min before corrective action is necessary. Motor

current loads for conditions 1, 3, and 4 are less severe.

In the above evaluation summary of potential RHR (LPCI) pump runout conditions, it was found that adequate available net positive suction head was maintained to preclude pump cavitation. It was also determined that RHR (LPCI) pump motor current would not exceed design limits for 25 min allowing sufficient time for an operator to take corrective action.

Therefore, it has been determined that the long-term cooling potential for the DAEC will not be lost or decreased from potential RHR pump runout conditions following a postulated LOCA.

This conclusion is based on a set of conservative assumptions that were used in the evaluation.

The potential runout with three pumps operating rather than four and a double-ended line break on the recirculation pump A discharge pipe has been evaluated. The same conservatisms that were used to perform previous analyses were also used in evaluating the three-pump case.

The results of the evaluation (Table 6.3-3) indicate that the RHR pumps will remain functional with three pumps operating. During runout conditions, the limiting pump (pump B), would have 1.2 ft of available net positive suction head above the approximately 13 ft that it requires.

Hence, there would be no pump cavitation. The pump B motor current would be less than 120%

of rated.

The increase in motor current would result in increased diesel-generator loading.

However, the increase would not exceed 10.5% (55 KW) per pump. This is below the 100 KW per pump increase used to evaluate the four-pump case. Therefore, the load summary previously submitted is still applicable and the diesel-generators would remain within rated conditions.

6.3.2.3 Applicable Codes and Classifications

Analytical methods, design criteria, and applicable codes and standards used for safety-related valves and pumps located outside of the reactor coolant pressure boundary are given in Sections 3.2, 3.6, and 3.7. References for analytical methods outlined in Section 3.7 for the above safety-related items are as follows:

1. RCIC Pump

a. For closure bolting and wall thickness see Table 3.7-13.

b. Nozzle Loads - Stress limits are determined from ASME,Section VIII, for normal and upset conditions and are set at 1.5 times allowable stress for emergency conditions. Pressure stresses are then deducted from allowable stress limits to UFSAR-DAEC-1 6.3-22 Revision 21 - 5/11 yield net remaining allowable stresses. This net remaining stress is then equal to F/A + M/Z (giving a super position of axial and bending stresses from elementary engineering mechanics), and the relationship is rearranged and solved for F in terms of M and the appropriate constants.

2. HPCI Pump

a. For closure bolting and wall thickness see Table 3.7-15.

b. Nozzle Loads - Method of analysis follows same procedure used for preceding item 1.b.

3. RHR Pump

a. For closure bolting and wall thickness see Table 3.7-9.

b. Nozzle Loads - Method of analysis follows same procedure used for preceding item 1.b.

4. Core Spray Pump

a. For closure bolting and wall thickness see Table 3.7-11.

b. Nozzle Loads - Method of analysis follows same procedure used for preceding item 1.b.

6.3.2.4 Material Specifications

The DAEC emergency core cooling systems have been designed with adequate margin for the expected maximum temperature, pH, and radioactivity (based on the source suggested in TID-14844) and its treatment within the containment and for degeneration of items such as filters, pump impellers, and seals that could affect the postaccident cooling system integrity.

With regard to materials, special attention has been paid in the specifications to employing compatible materials, to considering possible interaction of dissimilar metals, and to ensuring that only acceptable materials have been selected.

For further information regarding the detailed design of the emergency core cooling system, refer to Sections 7.3 and 5.4.

UFSAR-DAEC-1 6.3-23 Revision 21 - 5/11 6.3.2.5 System Reliability

6.3.2.5.1 General

Adequate emergency cooling capability is necessary whenever irradiated fuel is in the reactor vessel. For this reason, the reliability of all emergency core cooling systems components must be very high to support high availability for core cooling. To ensure that the systems will start when needed and will deliver the required quantity of coolant within specified log times, the engineered safety features are designed for identified and evaluated hazards and component failure modes. The design instituted to minimize the failure of the emergency core cooling systems to complete their specified functions are outlined in Section 6.3.1.

In addition, it should be noted that the plant Technical Specifications delineate surveillance and operational requirements that ensure that the plant is operated and maintained in a reliable, safe manner.

The intent of all NRC Design Criteria with regard to the emergency core cooling systems are met. Examination of each NRC Design Criterion has established the following:

1. NRC Design Criteria do not require Class 1 passive component failure protection for fluid systems (i.e., failure protection of pipes, valves, pumps, etc., is not required).

2. It does require the design

a. To provide safety functions assuming a failure of a single active component.

b. To provide safety systems that will not share active components and will not share other features or components unless it can be demonstrated that (1) the capability of the shared feature or component to perform its required function can be readily ascertained during reactor operation, (2) the failure of the shared feature or component does not initiate a LOCA, and (3) the capability of the shared feature or component to perform its required function is not impaired by

the effects of a LOCA and is not lost during the entire period this function is

required following the accident.

c. To perform its required function and not be impaired by the effects of a LOCA.

d. To provide heat removal systems that prevent the containment from exceeding its design pressure.

UFSAR-DAEC-1 6.3-24 Revision 21 - 5/11 The DAEC design meets all the above criteria under the single active component failure criteria. Attention to passive failures of Class 1 pressure components is not a requirement; however, provisions are made for mitigating the effects of non-Class 1 system or equipment failures upon Class 1 equipment.

6.3.2.5.2 HPCI and LPCI System Reliability

The consideration of active failures affecting high-pressure coolant injection and low-pressure coolant injection systems primarily depends on system pumps and valve availability. For this reason, single-failure analyses assuming several modes of pump failure and inadequate flow of cooling water have been made by the DAEC.

6.3.2.5.3 ECCS Power Supply Reliability

The ECCS power supply has been designed to consider single failures of dc power equipment. To maximize ECCS equipment availability, a GE study was made to identify any failures resulting from flood and the outage of electrical equipment.

Power supplies for all applicable ECCS equipment were reviewed by GE to determine

the effect of a dc power failure. Table 6.3-5 indicates which power supplies are used for this ECCS equipment. Table 6.3-6 is a listing of available equipment given a dc power failure in either Division 1 or Division 2. No equipment loss due to water spillage is expected because the recirculation line break occurs inside containment. All ECCS equipment is located outside containment. Table 6.3-6 does not distinguish between recirculation loop discharge breaks and suction breaks because this distinction does not affect equipment availability.

This review concluded that the plant design assumptions, which were used as the basis for GE's study, reflect the worst ECCS availability combinations for a dc power failure at the

DAEC. Based on these conclusions, it was agreed that the conclusions reached by GE 2 relative to a loop selection logic systems are applicable to the DAEC.

6.3.2.6 Protection Provisions

Protection provisions are included in the de sign of the ECCS. Protection is afforded against missiles, pipe whip, and flooding. Also accounted for in the design are thermal stresses, loadings from a LOCA, and seismic effects.

The ECCS is protected against the effects of pipe whip that might result from piping

failures up to, and including, the design-basis LOCA. This protection is provided by separation, pipe whip restraints, and energy-absorbing materials. These three methods are applied to provide protection against damage to ECCS piping and components that otherwise could result in a reduction of ECCS effectiveness to an unacceptable level. See Section 3.6 for the criteria on

pipe whip.

UFSAR-DAEC-1 6.3-25 Revision 21 - 5/11 Among other preventive measures, procedures are incorporated to minimize possible passive failures.

As described in Section 5.4.7, the core spray and RHR pump discharge piping is maintained sufficiently full of water by a keep fill pump that takes suction from and recirculates to the suppression pool. Accordingly, hydraulic forces that could cause system damage resulting from system initiation with the pump discharge lines not sufficiently filled with fluid are avoided.

In addition, control room display of ECCS pump suction pressure, pump discharge flow rate, and torus water level would allow the operator to become aware of any significant leakage into the ECCS pump compartment at which time remote isolation of torus suction valves in the

defective loop and startup of the other redunda nt RHR/core spray loop could be affected.

6.3.2.7 Provisions for Performance Testing

Periodic system and component testing provisi ons for the ECCS are described in Section 6.3.2.2 as part of the individual system descriptions.

6.3.2.8 Manual Actions

Following a postulated LOCA, an operator would have LPCI pump flow indication in the control room on the control panel 1C-04, flow indicators FI-1971 A and B. An operator may take manual control action as necessary prior to or after the first 10 min following a postulated LOCA (although, per the ECCS design basis, no operator action is required until 10 min. after an accident), but must act in accordance with prescribed emergency procedures.

In the evaluation of adequate ECCS pump NPSH (Section 1.8.1), it is assumed that operator action to throttle the pump flow back to rated conditions occurs at 30 minutes after

injection begins.

6.3.3 PERFORMANCE

EVALUATION

To achieve reliability, each emergency core cooling system uses the minimum feasible number of components that are required to actuate. All equipment is testable during operation.

Two different cooling methods--spray ing and flooding--provide diversity.

The evaluation of ECCS controls and instrumentation for reliability and redundancy

shows that a failure of any single initiating sensor cannot prevent or falsely start the initiation of these cooling systems. No single control failure can prevent the combined cooling systems from adequately cooling the core. The controls and instrumentation can be calibrated and tested to

ensure adequate response to conditions representative of accident situations.

UFSAR-DAEC-1 6.3-26 Revision 21 - 5/11 The performance of the ECCS is determined through the application of the 10 CFR 50, Appendix K evaluation models, and by conformance to the acceptance criteria of 10 CFR 50.46.

See Section 15.0 for the current methods used in the analysis.

The analysis of the plant LOCA was provided in accordance with NRC requirements and to demonstrate conformance with the ECCS acceptance criteria of 10 CFR 50.46.

(Section 15.2)

The objective of the LOCA analysis contained therein was to provide assurance that the most limiting break size, break location, and single-failure combination had been considered for the

plant.

Plant analyses for each reload are reported in the supplemental reload licensing submittal

for the plant and the applicable version of Reference 1.

6.3.3.1 Individual System Adequacy

6.3.3.1.1 General

The manner in which the emergency core cooling systems operate to protect the core is a function of the rate at which coolant is lost from a break in the nuclear system process barrier.

The HPCI system is designed to operate while the nuclear system is at high pressure. The core spray and LPCI systems are designed for low pressure operation only.

Nuclear system pressure is automatically reduced if a break has occurred and vessel water level is not maintained. Automatic depressurization of the nuclear system reduces the vessel pressure and permits flow from the core spray and low-pressure coolant injection to enter the vessel, thus limiting the core temperature rise.

The ECCS network provides two independent phenomenological cooling methods - flooding and spraying. The entire spectrum of liquid and steam-line breaks are covered by the high-pressure coolant injection, automatic depressurization system, core spray, and low-pressure coolant injection. High-pressure coolant injection or automatic depressurization system plus the

core spray provide both spray and flooding. Th e high-pressure coolant injection plus low-pressure coolant injection or automatic depressurization system plus low-pressure coolant

injection provide core flooding.

6.3.3.1.2 High-Pressure Coolant Injection System

See Sections 6.3.2.2.1 and 6.2.1.3.

UFSAR-DAEC-1 6.3-27 Revision 21 - 5/11 6.3.3.1.3 Automatic Depressurization System

When the automatic depressurization system is actuated, the flow of steam through the valves provides a maximum energy removal rate while minimizing the corresponding fluid mass loss from the reactor vessel. Thus, the specific internal energy of the saturated fluid in the reactor vessel is rapidly decreased causing pressure reduction. The system provides backup for

high-pressure coolant injection.

Actuation of the automatic depressurization function does not require any source of offsite or onsite AC power. The relief valves are controlled by DC power from the unit batteries and are operated by pneumatic power from accumulators. Each of the four automatic depressurization system safety/relief valves is equipped with a Seismic Category I nitrogen accumulator. The accumulators have sufficient capacity to cycle the automatic depressurization system valves five times at the DAEC containment design pressure.

6.3.3.1.4 Core Spray System

The core spray system is designed to provide continuous reactor core cooling for a LOCA. It provides adequate cooling for intermediate and large line break sizes up to, and

including, the design-basis, double-ended, recirculation-line break, without assistance from any other emergency core cooling systems. The integrated performance of the core spray system in conjunction with other emergency core cooling systems is given in Section15.2.

6.3.3.1.5 Low-Pressure Coolant Injection System

The low-pressure coolant injection (LPCI) system is provided to automatically reflood the reactor core in time to limit cladding temperatures after a nuclear system LOCA when the reactor vessel pressure is below the shutoff head of the pumps. Low-pressure coolant injection cools the core by flooding. With assistance of the automatic depressurization system or high-pressure

coolant injection the low-pressure coolant injection can independently supply sufficient cooling to meet the safety objective for any rupture of the nuclear system boundary up to and including the

design-basis accident.

The maximum flow capacity is determined by the design break (instantaneous break of a recirculation line). The pumps refill the inner plenum long before excessive cladding temperatures occur. The minimum allowable time in which this must be done occurs for the

design break because the least core cooling during blowdown occurs for this break. Hence, it must be reflooded more quickly than for small breaks. However, for the design break the vessel depressurizes very quickly, improving the pump flow characteristics. Hence, a greater flow of water can be pumped into the vessel.

UFSAR-DAEC-1 6.3-28 Revision 21 - 5/11 6.3.3.2 Integrated Operation of Emergency Core Cooling Systems

The previous discussion describes the individual performance and operation of each of the emergency core cooling systems. It has been demonstrated that two different methods and at least two independent core cooling systems are provided to limit fuel cladding temperature over the entire spectrum of postulated reactor primary system breaks as required by the design bases.

Sensitivity studies have been performed (References 13 and 14) that show how peak cladding temperature (PCT) varies with changes in ECCS flowrates for the Design Basis

Accident (DBA).

For the DBA Suction Break, the HPCI and ADS systems do not have any significant effect on the overall ECCS performance. This is because the large breaks depressurize the reactor vessel before the steam-driven HPCI system has sufficient time to startup and inject coolant into the vessel (45 seconds) and the ADS time delay (125 seconds) has expired. The primary core cooling depends on the CS and LPCI systems for these large breaks. In general, the time required to reflood the core and the lower plenum depends on the total ECCS flow (CS and

LPCI). The peak in PCT occurs shortly after the core is reflooded with the predominantly liquid continuum. Figure 6.3-9 shows how both the peak PCT time (i.e., core reflood time) and the peak cladding temperature for the DBA increase as the total ECCS Flowrate decreases. When the time between ECCS initiation and core reflood is short, the PCT increase is small, since the hot bundle is continuously covered with a two-phase mixture, which provides good heat removal capability (curves 1-4). With only a single CS pump, a two-phase continuum in the hot bundle cannot be maintained and the resulting PCT increase is large (curve 5).

The foregoing discussion is intended to show generic trends only. See Section 15.2 for the current evaluation of emergency core cooling systems performance during a LOCA required

by 10CFR50.46.

6.3.4 TESTS

AND INSPECTIONS

Each active component of the emergency core cooling systems that is provided to operate

in a design-basis accident is designed to be tested during normal operation of the nuclear system.

The HPCI, LPCI, core spray, and automatic depressurization systems are tested periodically to ensure that the emergency core cooling systems will operate (see the Technical

Specifications).

6.3.4.1 ECCS Performance Tests

Preoperational tests of the emergency core cooling systems were conducted during the final stages of plant construction before initial startup (see Chapter 14). These tests ensured UFSAR-DAEC-1 6.3-29 Revision 21 - 5/11 correct functioning of all controls, instrumentation, pumps, piping, and valves. System reference characteristics, such as pressure differentials and flow rates, were documented during the preoperational tests and were used as base points for measurements obtained in subsequent

operational tests.

Specific ECCS tests were performed on the core spray system with respect to core spray distribution effectiveness and the structural integrity of the HPCI pumps with postulated water ingestion from the steam turbine steam supply line. Descriptions and results of these tests are in

Sections 6.3.4.1.1 and 6.3.4.1.2, respectively.

6.3.4.1.1 Preoperational Core Spray Tests

Core spray distribution tests on the DAEC full-scale mockup were completed. The spray distribution system described below will ensure spray distribution over the core so that each fuel bundle will receive in excess of the minimum flow necessary for adequate cooling.

The recommended nozzle pattern is a combination of 0.75-in. VNC 12/13 and SPRACO

3101 nozzles. Each spray sparger consists of 52 VNC nozzles and 52 SPRACO nozzles alternately spaced around the header. These two groups of spray discharges are aimed at different inclination angles to optimize the dist ribution of spray. Effects of flow, updraft, and inclination angle tolerances were also investigated. These tests are discussed below.

VNC Nozzle Discharges

One-half of the spray discharges on each spray header for the DAEC final core spray

configuration are 0.75-in. VNC stainl ess steel elbows of the cast pattern (ESCO, Inc.). The shaft in the center of the discharge end of the VNC nozzle holds a deflector plate that increases the

angle of the cone of spray. These VNC nozzles give a very soft spray with a wide discharge

angle and coarse droplets.

SPRACO Nozzle Discharges

The other half of the spray discharges on each spray header are SPRACO 3101 nozzles.

The SPRACO nozzles supply flow mainly to the middle fuel bundles of the core. Since the

SPRACO nozzle has a flat, rectangular fan-shaped discharge pattern, it is necessary to control the twist of the nozzle about its axis. The twist determines how the discharge rectangle intercepts the core.

Aiming Angles

The optimum aiming angles for the VNC and SPRACO nozzles on both the upper and

lower spray header are given in Table 6.3-7. These angle settings are the results of extensive

testing and ensure the adequate distribution of spray over the core.

UFSAR-DAEC-1 6.3-30 Revision 21 - 5/11 Figures 6.3-10 and 6.3-11 illustrate the spray distribution over the core at rated design flow of 3020 gpm for the upper and lower spray headers, respectively. Aiming sensitivity tests (including inclination) indicate that a variation of +/-2 degrees from the recommended case have near-negligible effects on the spray distributi on. Therefore, a tolerance of +/-1 degree was established on all aiming angles.

Flow Rate Effects

The core spray system is rated at 3020 gpm at a vessel pressure of 113 psid (i.e., the difference in pressure between the reactor vessel and the torus). All nozzle and aiming

evaluation tests were run at this flow rate. To determine system performance at other flows, tests were run at 4300 and 2500 gpm. These results are shown in Figures 6.3-12 and 6.3-13 for upper and lower headers. System flows below the design value of 3020 gpm will result in a reduction

of flow to the center of the core. At flows greater than design flow, the distribution remains adequate. A flow-restricting orifice limits core spray flow to 4300 gpm.

Updraft Effects

The test facility used to determine core spray distribution is capable of simulating updraft (air) during core spray operation. Earlier single-channel tests showed that air and steam updrafts, when compared on a mass flow basis, produced predictable effects on the amount of core spray entering a channel. These single-channel tests demonstrated that the effect of an air

updraft of 7.5 fps is representative of 380 lb/hr per channel of steam updraft. This is greater than the most conservative calculation for hot-channel updraft for the DAEC. Full-scale air updraft tests show that adequate spray distribution is maintained for both the high and low headers even

at this excessive updraft value. Figure 6.3-14 s hows the effect of updraft for the lower header.

Minimum Channel Flow Rate

The original test program (for the initial core) performed to determine the effectiveness

of the reactor core spray was conducted using a 36-rod electrically heated test section. These

tests were run using a range of coolant flow rates from 1.8 to 2.8 gpm per bundle. The effect of flow rate over this range was almost negligible, indicating that 1.8 gpm per bundle did not represent the lower limit of flow for effective bundle cooling. However, since this was the lowest flow rate tested at that time, the minimum acceptable bundle spray rate was set at 1.8 gpm per bundle or 0.05 gpm per fuel rod. Appropriately increasing the minimum flow per rod to

account for the higher linear heat generation rate of the DAEC and factoring in the 49-rod bundle design resulted in a required minimum flow of 3.25 gpm per bundle. All of the core spray distribution tests conducted with the recommended aiming angles indicate that the minimum bundle flow rate of 3.25 gpm is satisfied and that most of the core is far in excess of this value.

More recent core spray effectiveness tests are documented in Reference 6.

UFSAR-DAEC-1 6.3-31 Revision 21 - 5/11 6.3.4.1.2 Preoperational HPCI Turbine Tests

A test program with two test series was conducted to prove the structural integrity of the

HPCI unit (Terry turbine, Model type CCS) for the following cases:

1. Water ingestion during HPCI quick startup.

2. Water ingestion during HPCI normal operation.

The tests were conducted using subcooled water and steam as the driving force. The amount of water used in the test series was varied from 50 to 600 gal, which was established from the conservative assumption that the HPCI steam line was full of water. The behavior of the turbine under the test conditions was recorded through the constant monitoring of the inlet and outlet pressures and temperatures, the position of the control valve, and the rotation speed of the turbine. See Figures 6.3-15 through 6.3-17 for arrangements and results for these tests.

Following both series of tests, the HPCI turbine was completely disassembled and all parts were inspected for possible damage or deterioration. After the reassembly of the turbine, a no-load running test was conducted to detect any degradation of turbine performance.

From the results of the tests it was concluded that

1. The test conditions to which the Terry turbine were subjected were as least as severe as any that could result in an operating GE BWR; in fact, the tests represent a more severe condition than any that could occur in a GE BWR.

2. The turbine showed signs neither of damage nor any permanent performance degradation.

3. The tested turbine is typical for the type then installed in the HPCI system of the 1967 product line GE BWR.

These test results are representative for the DAEC.

6.3.4.2 Reliability Tests and Inspections

6.3.4.2.1 General

The average reliability of a standby (nonoperating) safety system is a function of the

duration of the interval between periodic functional tests. The factors considered in determining UFSAR-DAEC-1 6.3-32 Revision 21 - 5/11 the periodic test interval of the ECCS are the desired system availability (average reliability), the number of redundant functional system success paths, the failure rates of the individual components in the system, and the schedule of periodic tests (simultaneous versus uniformly staggered versus randomly staggered). For this system, the above factors are used to determine safe test intervals by the methods described in Reference 7.

All of the active components of the HPCI, core spray, and LPCI systems are designed so that they may be tested during normal plant operation (with the exception of the recirculation valves). The full-flow test capability of each ECCS injection system is provided by test lines

back to their suction sources. The full-flow test is used to verify the capacity of each ECCS pump loop while the plant remains undisturbed in the power generation mode. In addition, each individual valve may be tested during normal pl ant operation. Input jacks are provided, and by racking out the injection valve breaker, each ECCS loop can be tested for response time.

All of the active components of the automatic depressurization system, except the check valves for the ADS accumulator, and the safety relief valves and their associated solenoid valves are designed so that they may be tested during normal plant operation.

Testing of the initiating instrumentation and controls portion of the ECCS is discussed in Section 7.3. The safeguard power system, which supplies electrical power to this system if

offsite power is unavailable, is tested as described in Section 8.3. Testing is specified in the

Technical Specifications. Visual inspections of all the ECCS components outside the primary containment can be made at any time during power operation. Components inside the primary containment can be visually inspected only during periods of access to the primary containment.

When the reactor vessel is open, the spargers and other reactor vessel internals can be inspected.

6.3.4.2.2 HPCI Testing

The HPCI system can be tested at full flow with condensate storage tank water at any time during plant operation, except when the reactor vessel water level is low; when the

condensate level in the condensate storage tank is below the reserve level; or when the valves from the suppression pool to the pump are open. If an initiation signal occurs while the HPCI system is being tested, the system valves align automatically to the injection mode. However, while injection to the vessel would occur during the test, actual flowrate could be less than required by Technical Specifications, but would remain within analyzed limits.

A design flow functional test of the HPCI system over the operating pressure and flow range is performed by pumping water from the condensate storage tank and back through the full flow test return line to the condensate storage tank. The HPCI system turbine pump is driven at its rated output by steam from the reactor. The suction valves from the suppression pool and the discharge valves to the feedwater line remain closed. These two valves are tested separately to ensure their operability. The HPCI system is tested in accordance with the Technical

Specifications.

UFSAR-DAEC-1 6.3-33 Revision 21 - 5/11 In response to IE Bulletin 85-03 and Generic Letter 89-10, the capability of certain motor operated valves to open and close under conditions of maximum expected differential pressures

has been verified (Reference 9 and Reference 11).

6.3.4.2.3 ADS Testing

The ADS valves are tested in accordance with the Technical Specifications. This testing includes simulated automatic actuation of the system throughout its emergency operating sequence, but excludes actual valve actuation. Each individual ADS valve is manually actuated.

During plant operation, the automatic depressurization system can be checked as

discussed in Section 7.3.

6.3.4.2.4 Core Spray Testing

The core spray pumps and valves are tested periodically during reactor operation. With the injection valve closed and the return line open to the suppression pool, full flow pump capability is demonstrated. The injection valve and the check valve are tested in a manner similar to that used for the LPCI valves. The portion of the core spray system outside the drywell may be inspected for leaks during tests. The Core Spray system is tested in accordance

with the Technical Specifications.

The core spray spargers and the segment of core spray piping inside the reactor pressure

vessel are visually inspected during each refueling outage in accordance with IE Bulletin 80-13 or in accordance with the guidelines endorsed by the BWR Vessel and Internals Project (BWRVIP).

6.3.4.2.5 LPCI Testing

Each LPCI loop can be tested during reactor operation. The LPCI system is tested in accordance with Technical Specifications. During plant operation, this test does not inject cold

water into the reactor, because the injection line check valve is held closed by vessel pressure, which is higher than the pump pressure. The injection line portion is tested with reactor water when the reactor is shut down, and when a closed system loop is created. This prevents unnecessary thermal stresses.

To test a LPCI pump at rated flow, the test line valve to the suppression pool is opened, the pump suction valve from the suppression pool is opened (this valve is normally open), and the pumps are started using the remote manual switches in the main control room. Correct operation is determined by observing the instruments in the main control room.

UFSAR-DAEC-1 6.3-34 Revision 21 - 5/11 If an initiation signal occurs during the test, the LPCI system aligns to the operating mode. The valves in the test bypass lines close automatically to ensure that the LPCI pump

discharge is correctly routed to the RPV.

6.3.5 INSTRUMENTATION

REQUIREMENTS

Design details and logic of the instrumentation for the emergency core cooling systems

are discussed in Section 7.3.

6.3.5.1 HPCI Actuation Instrumentation

The actuation of the HPCI system is provided automatically when one of two conditions occur: reactor vessel low water level or primary containment (drywell) high pressure. Reactor vessel low-low water level is monitored by four indicating-type multicircuit level switches that sense the difference between the pressure due to a constant reference column of water and the pressure due to the actual height of water in the vessel. Primary containment pressure is monitored by four pressure switches that are mounted on instrument racks outside the drywell but inside the reactor building. Pipes that terminate in the reactor building allow the switches to

sense pressures within the drywell interior.

System controls function to provide makeup water flow to the reactor vessel until the amount of water delivered to the reactor vessel is adequate. The HPCI system then automatically shuts down. Controls for remote manual startup, operation, and shutdown are located in the main control room. Once actuated to ensure proper functioning, RPV steam must power the HPCI turbine-driven pump. Instrumentation installed to detect steam flow is necessary to indicate steam flow status.

6.3.5.2 ADS Actuation Instrumentation

The automatic depressurization system is automatically actuated by signals from instrumentation monitoring reactor water level. Reactor vessel low water level signals actuate a time-delay circuit. In addition to the time-delay circuit, core spray or RHR pumps must be running to initiate reactor vessel blowdown. The automatic depressurization system can also be manually actuated from the main control room. Automatic actuation can be prevented from the control room during the time-delay by placing the ADS timer reset switches in the override

position.

6.3.5.3 Core Spray Actuation Instrumentation

Automatic start of both pumps is initiated by the instrumentation signals generated by

either reactor vessel low ("low-low-low") water level or drywell high pressure (one-out-of-two-twice logic for either signal). In addition, the core spray can be manually actuated from the main control room.

UFSAR-DAEC-1 6.3-35 Revision 21 - 5/11 6.3.5.4 LPCI Actuation Instrumentation

Low-pressure coolant injection is automatically actuated by the RPV low water level or

high drywell pressure. In addition, low pressure coolant injection can be manually actuated from the main control room.

The low-pressure core cooling portion of the emergency core cooling systems consists of three subsystems: core spray A, core spray B, and low-pressure coolant injection. Therefore, it should be understood that the LPCI subsystem by itself is not required to meet all the requirements of IEEE 279, since it is backed up by the two core spray subsystems.

To the extent practicable, the LPCI subsystem has been designed to meet IEEE 279. The loop selection sensing instrumentation for break de tection and valve selection is arranged so that the failure of a single device or circuit to function on demand will not prevent the correct

selection of the loop for injection.

The control system reliability is compatible with, and more reliable than, the controlled equipment (injection valve). Those single failures that could cause improper loop selection (i.e., selected short circuits that pick up specific relays) will not disable the core spray function. It is concluded, therefore, that the failure of the loop selection scheme to, in itself, fully comply with reactor protection system standards does not c onstitute a violation of IEEE 279 insofar as the low-pressure core cooling function is concerned.

Refer to Section 7.3.2 and to General Electric Topical Report 8 for further discussion and details.

UFSAR-DAEC-1 6.3-36 Revision 21 - 5/11 REFERENCES FOR SECTION 6.3

1. General Electric Standard Application for Reactor Fuel - United States Supplement , NEDO-24011-P-A-US (latest approved revision).

2. Letter from R. E. Engel, General Electric Company, to P. S. Check, NRC,

Subject:

DC Power Source Failure for BWR/III and IV, dated November 1, 1978.

3. Deleted

4a. Deleted

4b. Deleted

4c. Deleted

5. Letter from Darrell G. Eisenhut, NRC, to E. D. Fuller, General Electric,

Subject:

Documentation of the Reanalysis Results fo r the Loss-of-Coolant Accident (LOCA) of Lead and Non-Lead Plants, dated June 30, 1977 (Serial No. MFN-255-77).

6. General Electric, Core Spray and Bottom Flooding Effectiveness in the BWR-6, NEDO-10801-A, 1977.

7. H. M. Hirsch, Methods for Calculating Safe Test Intervals and Allowable Repair Times for Engineered Safeguard Systems , NEDO-10739, 1973.

8. M. K. Hentschel et al., Compliance of Protection Systems to Industry Criteria: General Electric BWR Nuclear Steam System, NEDO-10139, 1970.

9. Letter from W. C. Rothert, Iowa Electric, to A. Bert Davis, NRC,

Subject:

Final Report Pursuant to IE Bulletin 85-03, dated January 15, 1988 (NG-88-0001).

10. Letter from D.L. Mineck, Iowa Electric, to Dr. T. E. Murley, NRC,

Subject:

Consideration of Postulated Electric Failu re in 10CFR50.46 ECCS Analysis, dated June 26, 1989 (NG-89-1856).

11. NRC Inspection Report 50-331/95-011, dated January 25, 1996.

12. General Electric Company, Sensitivity of the Duane Arnold Center Safety Systems Performance to Fundamental System Parameters , MDE-282-1285, February, 1986.

UFSAR-DAEC-1 6.3-37 Revision 21 - 5/11

13. General Electric Company, Duane Arnold Energy Center SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis Engineering Report , GENE-637-034-1093, October 1993.

14. General Electric Company, Duane Arnold Energy Center SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis Engineering Report, Addendum 1 (sensitivity cases), GENE-637-048-1293, December 1993.

15. Letter, R. Anderson (FPL Energy) to USNRC, "Nine-Month Response to NRC Generic Letter 2008-01, 'Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems'," NG-08-0777, October 13, 2008.

16. Letter, R. Anderson (NextEra Energy) to USNRC, "Nine-Month Supplemental (Post Outage) Response to NRC Generic Letter 2008-01," NG-09-0327, April 27, 2009.

°°

°°

+/-°+/-°

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 16}}NOTE 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 6.3-3, SHEET 1 PROCESS FLOW DIAGRAM RESIDUAL HEAT REMOVAL SYSTEMS, UPDATED FINAL SAFETY ANALYSIS REPORT NEXTERA ENERGY DUANE ARNOLD, LLC DUANE ARNOLD ENERGY CENTER

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"*z(l)encoenIE1:ell0.0-en(l).=!ell>oC-ell:Jt5ell'0en"iii>.mcellco:g(l)C/)(l)(l)C/)ozoUlJ..Jen-o...i:'SoII>-g...8oruo+uJ51I()ruo+8<r,-,!...J,-'-II!-1],III,II'II1:1:IIIII<fI/',////////I\II,////////'---'t/)\\\\\\\\\\,\"'\OJ\'inL'\rrirIe-...8II>8+8.,;U93m3C:lnlVcBdW31DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTEmergencyCoreCoolingSystemsPerformanceCapabilityFigure6.3-9.Revision17-10/03 9r------------------------------,878"[.!!!itCOl........5wzz<<:I:<J...w::>..4..0w"z<<*32UI'ORAFTVELOCITY0.0It/...FLOW3020_7080oL.-L.-.L-..L.....L..-'-..........Io,02030RADIUSFROMCENTEROFCOREUn.)DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTBaseCaseDataRangeUpperHeaderFigure6.3-10 9,...-----------------------------,876E..;:0oJU.oJ5w'"'"<<:I:UoJw::l4u.u.0wOJ'"<<.II:32UPDRAFTVELOCITY0.0It/...FLOW3020gpm1o10203040506070RADIUSFROMCENTEROFCORE(in.)DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTBaseCaseOataRangeLowerHeaderFigure6.3-11 9,.--------------------------------,87iI\/\.6\IE\I*e.!!J;:/0\*/..../""5....//wz.'-.../z00:----:I:U...'"/....w\/::l4...w"\..-,,/00:a:w.......->00:3UPDRAFTVELOCITY0.0ft/sec---25OOgpmFLOW2BASECASE-3020gpmFLOW_.___4300gpmFLOW170605040302010O'--.....................................L.....IoRADIUSFROMCENTEROFCORE(;n.1DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTEffectofFlowUpperHeaderFigure6.3-12 9,------------------------------,8l.........wZz<<:I:(J...w::>...w"<<a:w765432,*\\.""",'-.""-./'-'-'-----/',--/./..........,//----2500gpmFLOWBASECASE-3020gpm----_4300gpmFLOWUPDRAFTVELOCITY0.0"Is**0'--__......L.......L-__--l......L....L...__---lo10203040506070RADIUSFROMCENTEROFCORElin.)DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTEffectofFlowLowerHeaderFigure6.3-13 9..------------------------------.,S7\\\6\E0-\.g;::0\....u.5....w\zZ<l\:I:<J....w4\,/:Ju.w"<la:w'-_/><l32SASECASE-SASECASE--_9ft/secUPDRAFTFLOW3020gpm0l...----I':---......I.:----....l.....J......!.:'o10203040506070RADIUSFROMCENTEROFCORElin.)DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTEffectofUpdraftLower"HeaderFigure6.3-14 TURBINESTOPVALVE"'('EF7E9tIADPTURBINEIIGEAR6in.(600IblSTEAMINLET-YI.......,-----1I6in.(900IblIII,60.01.WATERTANK1j+-1--1-900lb!INSULATED)IBin.EXHAUSTTOATMOSPHEREDUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTHPCITurbineWaterInjectionTestLoopFigure6.3-15 10j-----,---::;:;oo,...----.----r-----,---,r----,98715...-_--=2:.:0....:2:.:5303_5..10POSITIONINPERCENTPRESSUREINHUNDREDS(pliO)5EXHAUSTPRESSUREINTENS(psiO)o2524RPMINTHOUSANDSI9.8766DUANEARNOLDENERGYCENTERIOWAELECTRICLIGHT&POWERCOMPANYUPDATEDFINALSAFETYANALYSISREPORTHPCITurbineWaterInjectionTests600GallonStartupTestFigure6.3-16

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.-TurbulentPenetrationConductionThroughNaturalConvectionM02312ValveDisc,,=::j..SteamBubble'--..-...--..--.....--'tConductionThroughV23-0049ValveDisctHPCIPumpDischargeLineDUANEARNOLDENERGYCENTERFPLENERGY,LLCUPDATEDFINALSAFETYANALYSISREPORTEnergyTransportMechanismsforEquilibriumHPCIsteamBubbleFigure6.3-18Revision19-9/07 UFSAR/DAEC - 1 6.4-1 Revision 22 - 5/13 6.4 HABITABILITY SYSTEMS

The Control Room habitability system is discussed in Sections 6.4.1 through 6.4.6. Section

6.4.7 discusses

the Technical Support Center habitability systems.

6.4.1 DESIGN

BASIS

The DAEC control room and control building designs were licensed before the issuance of

NRC Standard Review Plan sections and Regulatory Guides dealing specifically with control room habitability criteria. The DAEC control room design was governed by General Design Criterion 19, "Control Room," which addresses radiation protection of control room personnel, but does not specifically address protection from hazardous-chemical releases.

A comparison of the DAEC design to the criteria found in Regulatory Guides 1.78 and 1.95 and Standard Review Plan Section 2.2 and 6.4 is described in Section 6.4.4.4. The comparison, originally submitted as Attachment 8 to Reference 3, revealed the following significant facts:

1. The DAEC control room is adequately designed to protect the control room occupants from radiological hazards. Automatic detection and f iltration of airborne radioactivity is provided, and the control room is adequately shielded for design-basis accident conditions.

2. Chlorine was the only hazardous chemical stored within 5 miles of the plant site that presented a potential toxic threat to control room habitability.

3. Regulatory Guides 1.78 and 1.95 require that the detection of hazardous-chemical releases be followed by automatic initiation of systems designed for the protection of the control room.

The DAEC control room/control building ventilation system is presently designed for manual initiation of an emergency filtration ventilation mode and relies on operator detection of hazardous-chemical releases.

4. Regulatory Guides 1.78 and 1.95 contain assumptions and analysis techniques for hazardous-chemical releases that are more conservative than the DAEC FSAR analysis for a

chlorine release.

5. DAEC emergency procedures do not presently address hazardous-chemical- release conditions.

The overall conclusion of the above review was that design changes to the DAEC control room/control building ventilation system are needed to bring the DAEC design into conformance with the current NRC licensing requirements related to control room habitability under chlorine-release

conditions.

UFSAR/DAEC - 1 6.4-2 Revision 22 - 5/13 The evaluation of DAEC control room habitability is discussed in Section 6.4.4, which contains the information to support the above conclusions. Also included in that section is an item-by-item response to the information requested in Attachment 1 to NUREG-0737, 1 Item III.D.3.4 (see Section 6.4.4.5).

The potential impact of a Cable Spreading Room Cardox actuation on Control Room Habitability has been analyzed. Analysis and testing were performed subsequent to the DAEC response to NUREG-0737. The evaluation was performed in response to a CARDOX System spurious actuation incident that occurred in the Cable Spreading Room in September, 1990 and the adverse impact it had on the Control Room habitability.

6.4.2 SYSTEM

DESIGN

6.4.2.1 Definition of Control Room Envelope

The control building houses the control room and associated auxiliaries, essential switchgear rooms, battery rooms, cable spreading room, computer room, and HVAC equipment room. It does not include the battery room corridor. The location of the control building is shown in the site plan, Figure 1.2-1. The control building arrangement is shown in the arrangement drawings: Figur es 1.2-4, 1.2-5, 1.2-7, 1.2-8, 1.2-10, and 1.2-11.

6.4.2.2 Ventilation System Design

The DAEC control room is located in the control building at elevation The ventilation system that provides control room airflow also supplies the remainder of the control building, including the essential switchgear and battery rooms (elevation ), the cable spreading areas above and below the control room, and the HVAC equipment room (elevation ). Makeup air for the control building comes directly from the outside air. A diagram of the control building

airflow is shown in Figure 9.4-7.

Because the source of control room air is presently common with the air distributed to the remainder of the control building, no special means of isolating just the control room is provided (see also Section 6.4.4.5, item 2a). The present design includes a HEPA and charcoal filtration train in the emergency makeup air duct through which emergency makeup air is automatically diverted when a predetermined level of airborne radioactivity is detected. The HEPA filters are discussed in Section 6.4.4.5, items 2e and 5b. This detection also isolates the normal control building makeup air supply

and exhaust ducts. These actions of isolating the control building and filtration of the emergency makeup supply protect the control building inhabitants from high levels of airborne radioactivity.

The ventilation air returning from each essential switchgear room can be isolated by bubble tight smoke dampers installed in each room's return duct. The smoke dampers automatically close upon detection of smoke by the duct mounted smoke detector or on a loss of power event. This isolation function will prevent the propagation of smoke from an essential switchgear room to the control room.

UFSAR/DAEC - 1 6.4-3 Revision 22 - 5/13 6.4.2.3 Leaktightness

See Section 6.4.4.5, item 2d.

6.4.2.4 Shielding Design

The shielding of the main control room has been designed to limit the dose rate to operating personnel within the control room to less than 0.5 mrem/hr during normal plant operations.

In addition to normal operations, the radiation conditions resulting from the design-basis accidents have been evaluated. Adequate shielding has been provided to permit access and occupancy of the control room for a 30-day period without personnel receiving radiation exposures in excess of 5-rem Total Effective Dose Equivalent (TEDE).

See also Section 6.4.4.5, item 2h, and Section 12.3.2.6.1.

6.4.3 SYSTEM

OPERATIONAL PROCEDURES

See Section 9.4.1 for a discussion of control room HVAC operations.

6.4.4 DESIGN

EVALUATIONS

6.4.4.1 Radiological and Toxic Gas Protection

The evaluation of DAEC control room habitability during toxic-releases, radioactive-gas releases, and direct radiation resulting from design-basis accidents is discussed in this section. The evaluation was intended to satisfy the requirements for nuclear power plant control room habitability review found in Item III.D.3.4 of NUREG-0660.

2 This item of NUREG-0660 was implemented by the May 7, 1980, letter from D. Eisenhut of the NRC to all operating reactors. Further clarification of Item III.D.3.4 is presented in NUREG-0737. The response to the NRC request for specific information required for control room habitability evaluation found in Attachment 1 to NUREG-0737, Item III.D.3.4, is also included in Section 6.4.4.5. The DAEC responded to NUREG-0737, Item III.D.3.4, by submitting an evaluation of the DAEC control room habitability as Attachment 8 to Reference 3, and committed to eliminate the onsite storage of chlorine by Reference 4. By Reference 5 the NRC issued a Safety Evaluation which found that the DAEC design with the elimination of the chlorine storage meets the criteria identified in Item III.D.3.4 of NUREG-0737 and is acceptable.

An additional request for information from the NRC regarding Control Room Habitability was forwarded to the DAEC in Reference 6. DAEC's response to this request is documented in

References 7 and 8.

Radiation protection for operating personnel in the control room under accident conditions is provided by the operation of either of two high-efficiency air filtration trains in conjunction with the installed control room shielding. Two 1000-cfm singl e-pass high-efficiency filter trains are provided in parallel with the normal outside air inlet duct. Each filter train consists of inlet and outlet isolation UFSAR/DAEC - 1 6.4-4 Revision 22 - 5/13 dampers, a heating coil, a prefilter, a HEPA filter, a charcoal filter (2-in. bed, tray type), and a final HEPA filter. Should fission products leaving the main stack reach ground level during a brief atmospheric fumigation, outside air radiation monitors will isolate the normal ventilation path and initiate high-efficiency filtration of incoming outside air. Control room air is recirculated through dust filters and heated or cooled as necessary to maintain comfortable working conditions. Power for the filtration-recirculation system may be supplied from the emergency bus. The filtration-recirculation system is Seismic Category I and is located in a Seismic Category I structure.

See Section 9.4 for further description.

The control room design-basis dose criteria of 5-rem TEDE or its equivalent to any part of the body resulting from access and occupancy for the duration of the accident condition are consistent

with10 CFR50.67.

The design of the main control room shielding and the main control room ventilation system has been evaluated using a hypothetical LOCA that results in the assumed release into the primary containment of 100% of the noble gases, 50% of the halogens, and 1% of the solids in the core fission product inventory (TID-14844 source). In addition, the thyroid and whole-body radiation exposures of control room personnel resulting from the periodic need for personnel to leave the main control room were evaluated.

The degree of compliance of the DAEC control room habitability design to the applicable

NRC Standard Review Plan sections and Regulat ory Guides listed in NUREG-0737 are discussed in Section 6.4.1. Included in Section 6.4.4.3 are the results of a survey of potential onsite and offsite sources of chemical hazards that could jeopardize control room habitability. Descriptions of modification options to improve the DAEC control room habitability were presented in Reference 3.

6.4.4.2 Control Room Radiological Analysis from the Main Steam Isolation Valve Leakage Treatment Path

As a resolution to the MSIV-LCS concerns, as described in Section 6.7, the BWROG proposed to use the main steam piping and main condenser as a method for MSIV leakage treatment.

Based upon the studies and recommendations mentioned in that section, DAEC has chosen to eliminate the MSIV-LCS and take credit for MSIV leakage utilizing the main steam drain lines and the main condenser. The allowable MSIV leakage rate limit has been increased to 100 scfh per valve, 200 scfh total for the Main Steam pathway. The bases for this approach and guidelines for implementation are contained in NEDC-31858P, Revision 2, BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems (Reference 1 to Section 6.7).

To demonstrate the adequacy of the DAEC engineered safety features, an analysis was performed of the radiological consequences that could result from the occurrence of design-basis-accidents (DBAs) with a leakage rate of 100 scfh per MSIV with a total leakage rate of 200 scfh through four main steam lines (including the inboa rd MSIV drain line) and without the MSIV-LCS (Reference 15.2). This analysis demonstrates that doses remain within the guidelines of 10CFR50, Appendix A, (General Design Criterion 19) for the control room and 10CFR 50.67.

6.4.4.3 Survey Results UFSAR/DAEC - 1 6.4-5 Revision 22 - 5/13 The survey of chemicals stored in quantity on the DAEC plant site identified chlorine as the only chemical that presented a potential hazard to control room habitability. This potential hazard was eliminated in 1982 by eliminating the onsite storage of chlorine gas and using sodium hypochlorite to chlorinate the circulating and service water systems.

The survey of offsite chemical storage within a 5-mile radius of the DAEC site identified no additional chemicals that present a potential hazard to control room habitability. The survey also

included a review of offsite fire and explosive h azards, and no hazards in this category were found. A more detailed discussion of the offsite survey results is provided in Section 6.4.4.3.2.

The effects on Control Room habitability from a carbon dioxide discharge into the Cable Spreading Room are discussed in Section 6.4.4.5.

6.4.4.3.1 Survey of Onsite Chemical Hazards

A survey of potentially toxic and explosive chemicals stored on the DAEC site in quantities exceeding 100 lb was conducted in 1980. The following chemicals in this category were identified:

1. Hydrogen.

2. Chlorine.

3. Nitrogen.

4. Carbon dioxide.

5. Sulfuric acid.

6. Circulating water treatment chemicals (three types).

The evaluation of the survey results is presented below.

1. Hydrogen can be both an ashphyxiant and explosive hazard. At the DAEC, hydrogen gas is used to cool the turbine-generator windings and is injected into each reactor feedpump suction line to aid in Intergranular Stress Corrosion Cracking (IGSCC) mitigation. The hydrogen is supplied from vendor supplied tube trailers. Tube trailer capacities are approximately 125,000

ft 3. Additionally, six hydril tubes are permanently stored in the same location and represent approximately 51,000 ft 3 of reserve capacity. Because the density of hydrogen is less than 1/14 the density of air, the hydrogen cloud will rise and dissipate too rapidly to draw a combustible concentration (4% by volume in air is the hydrogen lower flammable limit) into the control building. Similarly, the

hydrogen concentration will be too low to present an asphyxiation hazard.

2. Chlorine was judged to be a potential threat to control room habitability and had been identified in the FSAR as such. Chlorine was used as a biocide in the circulating and service water systems. The DAEC chlorine storage consis ted of nine 1-ton tanks of liquefied chlorine in the pump house. The tanks were manifolded in three groups of three tanks each.

2011-016 UFSAR/DAEC - 1 6.4-6 Revision 22 - 5/13 An analysis of the three-chlorine-tank rupture accident was performed using Regulatory Guide 1.78, Appendix B criteria. A calculation of the maximum chlorine concentration that could exist inside the control room for this rupture size showed that a chlorine concentration exceeding 670 ppm (by volume in air) could occur. This calculation assumed that no operator action was taken to isolate the control building ventilation following operator detection of the chlorine gas and also assumed Regulatory Guide 1.78 criteria for meteorological assumptions.

On the basis of the calculated high concentration of chlorine that could occur in the control room under the existing DAEC design with no operator action, chlorine was evaluated as a potential threat to control room habitability. As a result, the system was replaced by a liquid sodium hypochlorite system in 1987.

3. Nitrogen is stored in liquid form in a 9300-gal cryogenic tank located The nitrogen is used principally for containment inserting. Pure nitrogen is an asphyxiant if allowed to displace the oxygen in the control room atmosphere. A puff release of nitrogen from the cryogenic tank could release an estimated 800,000 scf. An analysis of nitrogen-cloud dispersion around the reactor building was performed to determine if nitrogen storage represents a threat to control room habitability.

The analysis concluded that the increase in nitrogen level within the control room as a result of the cryogenic tank rupture would be approximately 1.5% by volume in air. Because air is normally at a 79% nitrogen level, this increase in total nitrogen content is small. The nitrogen increase would cause a corresponding decrease in oxygen level from approximately 21% to 19.5%. The decrease in oxygen concentration will have no adverse effect on control room

habitability for the duration of the nitrogen release condition.

4. Carbon dioxide is stored in a 10-ton tank inside the turbine building adjacent to the control building. The carbon dioxide is used for fire protection and as a purge for the turbine-generator hydrogen coolant. A rupture of the carbon dioxide tank could release a puff of approximately

186,000 scf. An analysis of the carbon dioxide tank rupture was conducted, and it was concluded that the increase in carbon dioxide level in the control room would not exceed the threshold limit value (9000 mg/m

3) because of this event. The turbine building would effectively dilute and contain most of the carbon dioxide release; in addition, the higher density of carbon dioxide relative to air would contribute to minimizing the amount reaching the control building air intake outside and 15 m above the release point in the turbine building. Therefore, carbon dioxide stored onsite does not represent a threat to control room habitability. The

potential for intrusion of CO 2 into the Control Room via pathways other than the CO 2 tank rupture have been identified. These pathways include infiltration from the Cable Spreading Room penetrations and associated ductwork.

Infiltration could occur due to a Cable Spreading Room CARDOX actuation. Details of this event and actions taken to mitigate the consequences are discussed in Section 6.4.4.5.

5. Sulfuric acid is used to treat the circulating and service water systems and is stored in a 20,000-gal tank. Sulfuric acid is a liquid at 100°F and has a vapor pressure UFSAR/DAEC - 1 6.4-7 Revision 22 - 5/13 of less than 10 torr. Regulatory Guide 1.78 states that any chemical that has a vapor pressure of less than 10 torr and is a liquid at a temperature of 100°F can be excluded from the control room habitability analysis. Therefore, the sulfuric acid storage at the DAEC is not a threat to control room habitability.

6. Chemicals used in the circulating water chemical addition system are stored in four chemical tanks on

All of the chemicals are liquids at a temperature of 100°F, non-volatile and do not represent a threat to control room habitability.

Oxygen can also be an explosive hazard. At the DAEC, a It is injected into the offgas system and condensate pump suctions. The location meets NFPA separation criteria for proximity to combustibles. The effects of increased oxygen concentration entering safety related air intakes was evaluated and the results show that separation distances are extremely conservative. Therefore, oxygen does not impose a threat to control room habitability.

6.4.4.3.2 Survey of Offsite Chemical Hazards

A survey of potentially toxic and explosive chemicals stored within 5 miles of the DAEC plant was conducted. The following chemicals in this category were identified:

1. Anhydrous ammonia.

2. Propane.

3. Gasoline/fuel oil/diesel oil.

4. Dynamite (TNT).

Anhydrous ammonia has toxic properties. The latter three chemicals are principally fire and

explosive hazards.

Section 2.2 describes industrial, transportation, and military facilities and lists local farms and

industries, locations of bulk storage facilities, and local transportation of potentially hazardous chemicals within 5 miles of the DAEC.

The evaluation of the survey results is presented below.

1. The only chemical stored offsite that presents a potential toxicity threat to control room habitability is anhydrous ammonia (ammonia gas). Ammonia is used as a fertilizer during a 2-week period of spring planting in central Iowa. The anhydrous ammonia storage nearest to the site is a 2-ton tank on the Stodola farm 1.8 miles from the plant.

Table C-2 of Regulatory Guide 1.78 permits relief from considering hazardous chemicals as a threat to control room habitability if the chemical is stored in quantities below a given weight at a given distance from the plant site. Using this weight-distance criterion of Regulatory Guide 1.78 and also considering the infrequent storage of ammonia at the Stodola farm, anhydrous ammonia does not present a threat to DAEC control room habitability.

UFSAR/DAEC - 1 6.4-8 Revision 22 - 5/13

2. The remaining chemicals listed in this section are fire and explosive hazards and would not pose a toxicity threat to control room inhabitants. Although a review of explosive hazards in the site vicinity is not specifically related to control room habitability, Standard Review Plan

Sections 2.2.1, 2.2.2, and 2.2.3 require the evaluation of potential offsite accidents that could present a hazard to the plant. A summary of potentially explosive chemicals within 5 miles of the site is therefore included for completeness in responding to NUREG-0737, Item III.D.3.4.

A review of the storage quantities and distances from the site of potential fire and explosive chemicals was conducted using the review crite ria of Regulatory Guide 1.91, Evaluations of Explosions Postulated To Occur on Transportati on Routes near Nuclear Power Plants. This guide describes the concept of "TNT equivalence" as a method of standardizing the blast effect of various chemicals at various distances from the plant. Briefly, solid and liquid chemicals with explosive properties are assumed to have a 1:1 weight equivalence to TNT unless the chemical is known to have a greater explosive force than TNT. For gaseous chemicals with explosive properties, a 1:2.4 weight equivalence is assumed, such that 1 lb of

gas is equivalent to 2.4 lb of TNT.

Each of the fire and explosive chemicals listed in this section is stored in either the liquid or solid state within 5 miles of the DAEC site. A 1:1 weight equivalence to TNT was assumed for gasoline, and a 2.4:1 weight equivalence was assumed for propane, assuming the propane is vaporized on release. The chemicals, quantities, and distances from the site are as follows:

Chemical Amount Stored or Transported Distance from the DAEC (miles)

Liquid propane 1,900 gal 0.9 (Bull farm)

Liquid Propane 30,000 gal 3.2 (Palo)

Gasoline 30,000 gal 3.2 (Palo)

Dynamite 10,000 lb (in truck) 3.2 (Palo) The TNT equivalency of each of the above chemicals was calculated and entered into Regulatory Guide 1.91, Figure 1, along with the distance value, to determine if any explosive risk to the site existed as a result of the detonation of these materials at their storage location.

The conclusion reached using this approach is that none of the chemicals present an explosion hazard to the DAEC from their storage locations.

The second aspect to consider for a fire and explosive hazard is the potential transport of these chemicals through the atmosphere to the plant site. All explosive chemicals except propane have vapor pressures under 10 torr and are therefore excluded from further evaluation per the criteria of Regulatory Guide 1.78 for toxic chemicals.

UFSAR/DAEC - 1 6.4-9 Revision 22 - 5/13 In the case of propane, the analysis concluded that a cloud release of propane at a distance of 3.2 miles would result in a propane concentration at the control building air intake of 0.13%

by volume in air. At this concentration, propane is neither a fire nor asphyxiant hazard to the control room.

6.4.4.3.3 Survey Conclusions

The original surveys in Sections 6.4.4.3.1 and 6.4.4.3.2 concluded that chlorine was the only hazardous chemical within 5 miles of the DAEC that might present a threat to control room

habitability.

As a result of the conclusion that onsite chlorine releases pose a potential threat to control room habitability at the DAEC, the onsite storage of chlorine has been eliminated.

Subsequent to the original survey of onsite and offsite hazardous chemicals, an evaluation of the effects of a CARDOX system actuation into the Cable Spreading Room has been performed and is discussed in Section 6.4.4.5.

6.4.4.4 Comparison with NRC Licensing Criteria

NUREG-0737, Item III.D.3.4, states that the following NRC licensing documents address control room habitability:

1. General Design Criterion 19, "Control Room."

2. Regulatory Guide 1.78, Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release.

3. Regulatory Guide 1.95, Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release.

4. Standard Review Plan, Section 6.4, "Habitability Systems."

5. Standard Review Plan, Sections 2.2.1, 2.2.2, and 2.2.3.

6. Murphy and Campe paper of August 1974, Meeting General Design Criterion 19.

A review was conducted to determine the degree of conformance of the DAEC design to each of the above documents. The results of this review are summarized below:

1. General Design Criterion 19, Control Room.

The DAEC design satisfies General Design Criterion 19. Section 3.1 describes General Design Criterion 19 compliance and refers to Section 12.3.2 for a description of control room radiation protection.

UFSAR/DAEC - 1 6.4-10 Revision 22 - 5/13 2. Regulatory Guide 1.78 (see also Section 1.8). The DAEC design does not fully meet the positions of Regulatory Guide 1.78. Principal differences between the plant design and this guide include the following:

a. Chlorine was the only hazardous chemical analyzed in the FSAR, whereas the guide requires that all hazardous chemicals that could exist in quantity within 5 miles of the plant site be evaluated for potential impact on control room habitability. (See Section 6.4.4.5 for a discussion of the effects of a CARDOX system actuation on Control Room Habitability.)

b. Equipment to detect the presence of hazardous chemicals in the control room air supply and a means of automatically initiating systems designed for the protection of the control room on detection are required by the guide. The DAEC presently has no equipment for automatic protection of the control room or control building following the detection of hazardous chemicals.

c. DAEC emergency procedures do not presently address hazardous chemical releases, as required by the guide.

3. Regulatory Guide 1.95 (see also Section 1.8). The DAEC design does not fully meet the positions of Regulatory Guide 1.95. Principal differences between the plant design and this

guide include the following:

a. The guide defines six types of control rooms, with corresponding maximum chlorine storage requirements for each type. Each of the six control room types includes chlorine detectors located in the fresh air inlets for the initiation of control room isolation. Because the DAEC design does not provide for automatic control room isolation, the DAEC control room meets none of the defined control room types in the

guide.

b. The guide requires periodic control room leakage testing by the pressurization of the control room. Because the DAEC control room is not separately isolable, the pressurization of the room is not possible.

c. As in Regulatory Guide 1.78, this guide requires emergency procedures for chlorine releases. These are not presently developed for the DAEC.

4. Standard Review Plan, Section 6.4. The DAEC design differs from the acceptance criteria in Standard Review Plan Section 6.4. Principal differences between the plant design and the Standard Review Plan include the following:

a. The DAEC "emergency zone" includes not only the control room elevation of the control building, but also the remaining three building elevations not requiring operator occupancy under accident conditions. The Standard Review Plan limits the emergency zone to those spaces requiring operator occupancy.

UFSAR/DAEC - 1 6.4-11 Revision 22 - 5/13 b. As in Regulatory Guides 1.78 and 1.95, the Standard Review Plan assumes that automatic isolation of the control room occurs on the detection of hazardous chemicals in the inlet air and evaluates a design according to infiltration rate and makeup airflow.

The DAEC design does not presently meet the isolation requirement to satisfy this

Standard Review Plan criterion.

5. Standard Review Plan Sections 2.2.1, 2.2.2, and 2.2.3 were used in the identification of potential offsite hazards discussed in Section 6.4.4.3.2.

6. The paper prepared by Murphy and Campe to address methodology for meeting General Design Criterion 19 control room ventilation design requirements was reviewed for applicability to the DAEC design. The paper presents a methodology for calculating control room radiation doses for particular plant geometries, source terms, meteorological conditions, etc. The calculations performed to support this control room habitability study employed calculational methods and assumptions consistent with the methodology promoted in the Murphy and Campe paper.

6.4.4.5 NRC-Requested Information Required for Control Room Habitability Evaluation

Regulatory Position Habitability Evaluation

The following information is listed in the same order as requested in Attachment 1 to NUREG-0737, Item III.D.3.4.

Item Response

1 The control building ventilation system mode of operation for the detection of high airborne radioactivity is automatic isolation of the normal control building makeup and

exhaust ducting and pressurization of the control building with once-through filtered makeup air through emergency charcoal filters.

The control building ventilation system mode of operation for a hazardous- chemical release is operator detection followed by manual initiation of the same isolation and filter alignment described above for the radiological accident.

Figure 9.4-7 shows the control building airflow.

Item Response 2 a. The control room is supplied air from the ventilation system common to the entire control building. The air volume of the control building is 155,000 ft

3. b. The "control room emergency zone" at the DAEC envelopes the entire control building air space. This space includes the essential switchgear and battery rooms, the cable spreading room, the control room, and the HVAC equipment room.

UFSAR/DAEC - 1 6.4-12 Revision 22 - 5/13 c. Figure 9.4-7 shows normal and emergency airflow rates for the control building.

d. The control building air infiltration leakage rate has not been determined at the DAEC. The emergency filtration mode continues to supply outside makeup air to maintain a positive control building pressure such that infiltration is minimized.

e. The HEPA filters in the emergency filtration trains are rated at 99% efficiency in removing particulates. The charcoal filters in each emergency filtration train are rated at 90% efficiency for radioactive methyl iodide removal.

f. The control building air inlet is

g. The site layout showing the location of the control building in relation to the reactor building, turbine building, and pump house is shown in Figure 1.2-1.

The control room elevation of the control building is shown in Figure 6.4-1.

The control building air intake location is shown in Figure 6.4-2.

Item Response

2 h. The control room is shielded by concrete and high-density blockwall. The (cont.) wall design and radiation dose rates under design-basis accident LOCA conditions are described in Section 12.3.2. No streaming of radiation will occur in the control room.

i. The control building isolation dampers are rectangular. The inlet dampers are approximately 38.5 by 68.5 in. OD (35.5 by 59.5 in. ID) ; the design leakage rate at a pressure differential of 0.5-in. water gauge is 67.5 scfm. The exhaust dampers are 40 by 46 in.; the design leakage rate at a pressure differential of 0.5-in. water gauge is 57 scfm. No periodic leakage testing is presently performed.

j. The DAEC design presently includes one detector for chlorine located in the chlorine storage area of the pump house. The detector is not safety grade and alarms on detection both locally and in the control room. No toxic gas

detectors are provided to initiate control building isolation.

k. Seven self-contained breathing apparatus units are provided in the DAEC control room.

l. Each self-contained breathing apparatus is provided with a 1-hr reserve of bottled air supply.

UFSAR/DAEC - 1 6.4-13 Revision 22 - 5/13 m. The DAEC control room is not presently provisioned with food for the operators and supervisor for a 5-day period. Adequate potable water and a medical kit are provided.

n. The control room personnel capacity is only limited to seven persons by the number of self-contained breathing apparatus units. If the control room air is breathable, the capacity is only limited by shift supervisor control of access to the room, as discussed in DAEC's response to NUREG-0578, Item 2.2.2.a.

o. Potassium iodide drugs are not presently available in the DAEC control room.

UFSAR/DAEC - 1 6.4-14 Revision 22 - 5/13 Item Response 3 a. The quantities and volumes of storage containers for potentially hazardous chemicals on the DAEC site are as follows:

Storage Container Chemical Quantity Size Hydrogen 2 (tube trailers) 176,000 ft 3

Nitrogen 1 9300-gal cryogenic tank

Carbon dioxide 1 10-ton tank

Sulfuric acid 1 20,000-gal tank

Circulating water treatment chemicals

(3) 2 1 1 2000-gal tank 2000-gal tank

1000-gal tank

Subsequent to the above response, two additional storage containers were found on the DAEC site and moved to the south warehouse area. Tank capacity is 1000 gallons for the gasoline and 500 gallons for the fuel oil tank.

The review of control room habitability has determined that, of the above chemicals, none represents a threat to control room habitability.

b. There is no onsite chlorine storage.

4 The survey of offsite manufacturing, storage, and transportation facilities of hazardous chemicals documented in Section 2.2 provides each of the requested items listed in NUREG-0737, Item III.D.3.4.

5 a. Because the DAEC design does not provide for a safety-grade chlorine detection/isolation system, no technical specifications exist to address chlorine detection.

b. The Technical Specifications for control building ventilation include surveillance testing to verify HEPA filter and charcoal adsorber bank efficiencies, to verify system flow isolation/filter system operability periodically and to verify system flow rate. Although there is no Technical Specification requirement to measure system isolation time, it is believed the intent of this requirement is met in that unusual damper closure time would be recorded as a problem in the Surveillance Test Procedure, reported as a deviation, and hence corrected via maintenance.

2011-016 UFSAR/DAEC - 1 6.4-15 Revision 22 - 5/13 Item Response 6 Carbon dioxide intrusion into the control room has the potential to impact control room habitability. CO 2 infiltration into the control room can occur during CARDOX discharge. Pathways into the control room include Cable Spreading Room-Control Room penetrations and HVAC ductwork. Modifications to the ventilation system have been performed and are discussed below.

The modifications included 1) the elimination of a direct vent path from the Cable Spreading Room to the control room area, 2) modifications to the Cable Spreading Room exhaust damper to provide for better venting and limit the internal pressure buildup of the Cable Spreading Room, 3) the addition of secondary Cable Spreading Room vent path, and 4) incorporation of a scent into the CARDOX system to alert control room personnel of any CO 2 intrusion.

The post-modification test results indicate that the cable spreading room is adequately vented during a CARDOX actuation which thereby limits CO 2 intrusion and maintains normal oxygen levels in the control room. A more detailed description of the modifications and test results are included in Reference 8.

6.4.5 TESTING

AND INSPECTION

Section 9.4.4.4 contains inspection and testing requirements for the control room HVAC system, including, the control room ventilation HEPA filters and charcoal adsorbers.

6.4.6 INSTRUMENTATION

REQUIREMENT

The control room habitability instrumentation and logic are discussed in detail in Section

6.4.4.4.

6.4.7 TECHNICAL

SUPPORT CENTER

The Technical Support Center (TSC) is provided with shielding and an air cleanup system to

assure habitability under postulated accident conditions, as discussed in Sections 12.3.2 and 9.4.9.

Area radiation monitors are also provided and are described in Section 12.3.3.3.3. Evaluation of radiological dose to TSC personnel during accident conditions is discussed in Chapter 15.2.

No toxic gas protection features are require d, as discussed in the preceding sections.

Radiological analysis similar to the analysis described in Section 6.4.4.2 for the control room

was used to calculate the effects of the allowable MSIV leakage rate in terms of TSC doses. Table 6.7-1 shows that calculated TSC doses exposure for the BWROG radiological analysis for the DAEC. Regulatory limits and the calculated doses from radiological analysis from above, are also included for comparison purposes. This analysis demonstrates that a leakage rate of 100 scfh per MSIV, with a maximum leakage rate of 200 scfh for all four main steam lines (with the elimination of the LCS)

UFSAR/DAEC - 1 6.4-16 Revision 22 - 5/13 results in an acceptable increase in the dose exposure previously calculated for the TSC. The revised LOCA doses remain within the guidelines of 10CFR50, Appendix A, (General Design Criterion 19) for the TSC and 10CFR 50.67.

UFSAR/DAEC - 1 6.4-17 Revision 22 - 5/13 REFERENCES FOR SECTION 6.4

1. U.S. Nuclear Regulatory Commission, Clarification of TMI Action Plan Requirements, NUREG-0737, Washington D.C., 1980.

2. U.S. Nuclear Regulatory Commission, NRC Action Plans Developed as a Result of the TMI-2 Accident, NUREG-0660, Washington, D.C., 1980.

3. Letter from Larry D. Root, Iowa Electric, to Harold R. Denton, NRC,

Subject:

Responses to NUREG-0737 Items Requiring Response by January 1, 1981, dated December 31, 1980 (Serial No. LDR-80-393).

4. Letter from Larry D. Root, Iowa Electric, to Harold R. Denton, NRC,

Subject:

NUREG-0737, Item III.D.3.4, dated March 24, 1982 (Serial No. LDR-82-082).

5. Letter from Domenic B. Vassallo, NRC, to Duane Arnold, Iowa Electric,

Subject:

NUREG-0737, Item III.D.3.4, Control Room Habitability, dated April 19, 1982.

6. Letter from Clyde Y. Shiraki, NRC, to Lee Liu, Iowa Electric,

Subject:

Control Room Habitability Evaluation, dated August 2, 1991

7. Letter (NG-91-3254) from Daniel L. Mineck, Iowa Electric, to Thomas E. Murley, NRC,

Subject:

Response to Request for Additional Information Regarding DAEC's Control Room

Habitability Evaluation, dated October 28, 1991

8. Letter (NG-92-2091) from David Wilson, Iowa Elect ric, to A. B. Davis, NRC, Licensee Event Report 92-004, dated April 21, 1992 UFSAR/DAEC-1 T6.4-1 Revision 17 - 10/03 Table 6.4-1 Deleted

1

° 1

°

UFSAR/DAEC-1 6.6-1 Revision 18 - 10/05

6.6 INSERVICE

INSPECTION OF CLASS 2 AND 3 COMPONENTS

Inservice inspection of Class 2 and 3 components will comply with the requirements of 10 CFR 50.55a(g) and ASME B&PV Code,Section XI. The edition and

addenda of the Code will be as agreed on by the DAEC and the NRC for each inspection

period. The 1989 Edition is applicable for the current inspection interval scheduled to

end on October 31, 2006.

The engineering and design effort associated with the DAEC predates the availability of Section XI of the ASME Code. However this Code, including addenda through the Winter 1972 Addenda, was used as a guide in the preparation of the DAEC inservice inspection plan for Nuclear Class 2 components, and maximum access has been provided within the limits of drywell design.

A preservice inspection was not performe d at the DAEC on Nuclear Class 2 and 3 components because it was not required at the stage of DAEC construction when it would have been used. For these components, shop and in-plant examination records of components and welds serve as a basis for comparison with inservice inspection data.

The initial inservice inspection of Class 2 components for the DAEC was

conducted in accordance with the plant Technical Specifications that were based on the ASME Code,Section III, 1971 Edition through the Winter 1972 Addenda, as approved

by the NRC. Inservice inspections before June 1, 1978, were conducted in accordance

with these Technical Specifications since Iowa Electric received Facility Operating License DPR-49 before May 1, 1976. This course of action was in full compliance with the amended inservice inspection requirements (10 CFR 50.55a(g)(4)(v)). Inservice inspection of Class 3 components was commenced on June 1, 1978.

Documentation and records of examination procedures, schedules, and inspection reports concerned with preoperational and inservice inspection will be 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 of the preservice base examination data and inservice inspection records of tests performed. Documentation

includes corrective action reports and repair procedures where required. Originals of all inservice inspection records are maintained in a central location.

Reporting will be in accordance with the ASME Code,Section XI, Article IWA-6000. References 5.2-10 and 5.2-11 summarize the first ten-year ISI interval.

UFSAR/DAEC-1 6.6-2 Revision 13 - 5/97

6.6.1 COMPONENTS

SUBJECT TO EXAMINATION

The Nuclear Class 2 pressure-containing components and piping that are

considered for inservice inspection include the two RHR heat exchangers and their appurtenances, and RHR piping, pumps, and valves, major portions of the ECCS, CRD hydraulic system, and main steam lines from the outermost containment isolation valves

up to but not including the turbine stop and bypass valves.

Components and appurtenances that are to be subjected to non-destructive examination in and around the RHR heat exchangers include the following:

1. Circumferential butt welds.

2. Nozzle-to-vessel welds.

3. Integrally welded support welds.

4. Longitudinal seam welds.

The examination program assumes that examinations can be performed without unloading the reactor core solely for the purpose of conducting examinations.

Class 2 components or systems to be inspected are identified in the Duane Arnold Energy Center third 10-year inservice inspection plan submitted to the NRC by Reference 2. The inservice inspection plan is based on Table IWC-2500-1 of ASME Code Section XI.

The DAEC will submit a report to the NRC at the end of each 10-yr inspection interval defining the examination categories that could not be completed because of scheduling. Examination categories that could not be completed because of accessibility/limitations require an approved relief request from the NRC.

The Nuclear Class 3 inservice inspection program includes the following systems:

1. RHR service water.

2. Steam lines from six main steam safety relief valves to the torus.

3. Emergency service water system.

4. River water supply system.

UFSAR/DAEC-1 6.6-3 Revision 13 - 5/97

6.6.2 ACCESSIBILITY

Access for inspection has been provided within the limits of the plant and system design. For many areas, volumetric and surface examinations will require the removal of a portion of the permanent insulation.

6.6.3 EXAMINATION

TECHNIQUES AND PROCEDURES

6.6.3.1 Class 2 Components

The examination procedures used for inservice inspection will include ultrasonic, magnetic particle, liquid penetrant, and visual techniques. All examinations will be conducted in accordance with ASME Code Section XI. Examining personnel will be qualified in accordance with Subarticle IWA-2300.

The type of inservice inspection planned for each component depends on location, accessibility, and type of expected defect. Direct visual examination is planned wherever possible since it is fast and reliable. Surface inspections are planned where practical, and

where added sensitivity is required. Ultrasonic testing or radiography are used where

defects can occur in concealed surfaces.

Visual examinations will be used to determine the general condition of the part, component, or surface examined, including such conditions as scratches, wear, cracks, corrosion, erosion, or evidence of leakage.

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.

6.6.3.2 Class 3 Components

The Class 3 inservice inspection program requires visual examination of components for evidence of leakage, structural distress, or corrosion when the system is undergoing either a system inservice test, component functional test, or a system pressure test. Supports and hangers for components exceeding 4-in. nominal pipe size will be examined visually to detect any loss of support capability and evidence of inadequate restraint. Inspection requirements will be in accordance with the Inservice Inspection Plan.

UFSAR/DAEC-1 6.6-4 Revision 18 - 10/05

6.6.4 INSPECTION

INTERVALS

The inservice inspection interval for the examination program is 10 yr. The extent of Nuclear Class 2 examinations during the third 10-yr interval is as indicated in the

DAEC Inservice Inspection Plan

2. The actual individual inspections will generally be performed during refueling outages and will be adjusted to the load factor of the unit to minimize outage time directly required for inspection.

The first 40-month inspection period ended June 1, 1978, based on commercial

operation beginning on February 1, 1975.

The first 10-yr inservice inspection interval ended October 31, 1985, having been extended 9 months as a result of a continuous refueling and repair outage that lasted 9 months from June 1978 to March 1979.

The second 10-yr inservice inspection interval ended on November 1, 1996. The

interval was divided into three inspection periods ending on March 1, 1989; July 1, 1992; and November 1, 1996.

The third 10-yr inservice inspection interval commenced November 1, 1996 and

is scheduled to end on October 31, 2006.

The inspection schedule for Class 2 components will be in accordance with Subarticle IWC-2400 and for Class 3 components in accordance with Subarticle IWD-

2400.

6.6.5 EXAMINATION

CATEGORIES AND REQUIREMENTS

Examination categories and requirements for Class 2 components are indicated in Reference 2, which are correlated with Table IWC-2500-1 of Section XI of the ASME Code. Exempted Class 2 components are in accordance with Subarticles IWC-1220.

Examination requirements for Class 3 components are in accordance with Subarticle IWD-2500 of Section XI of the ASME Code.

Requests for relief are submitted where it is impossible or impractical to examine or test an applicable Class 2 or 3 component or system.

6.6.6 EVALUATION

OF EXAMINATION RESULTS

The results of the examinations are evaluated in compliance with the appropriate portions of ASME Code,Section XI. Repairs, if required, will also comply with Section

XI or NRC-approved alternate.

UFSAR/DAEC-1 6.6-5 Revision 14 - 11/98

6.6.7 SYSTEM

PRESSURE TEST

Near the end of each inspection interval, the following will be subjected to a

pressure test in accordance with the Inservice Inspection Plan.

1. RHR and RHR service water systems.

2. Core spray system.

3. HPCI system.

4. CRD hydraulic system.

5. Emergency service water system.

6. River water supply system.

Components will be subjected to normal operating pressure by the operation of system pumps or by remote pressurization. During the pressure test, components will be inspected for leakage without the removal of insulation.

6.6.8 AUGMENTED

INSERVICE INSPECTION TO PROTECT AGAINST POSTULATED PIPING FAILURES

The use of augmented inservice inspection as related to the prevention of pipe rupture at the containment boundary is discussed in Section 5.2.4.

UFSAR/DAEC-1 6.6-6 Revision 13 - 5/97 REFERENCES FOR SECTION 6.6

1. Letter from Richard W. McGaughy, Iowa Electric, to Harold Denton, NRC,

Subject:

Duane Arnold Energy Center Second 10-Year Inservice

Inspection Plan, dated May 1, 1985.

2. Letter from J. Franz, IES Utilities, to W. Russel, NRC,

Subject:

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

UFSAR/DAEC-1 6.7-1 Revision 21 - 5/11 6.7 MAIN STEAM ISOLATION VALVE LEAKAGE TREATMENT PATH

6.

7.1 BACKGROUND

OF MSIV-LEAKAGE CONTROL SYSTEM

During DAEC's construction permit stage, the NRC identified their concern regarding radiological exposures which could result from leakage from the primary containment which might bypass the secondary containment and the associated filtering systems in the event of an accident. Of particular interest was the possible leakage paths through the Main Steam Isolation Valves (MSIVs). This particular concern was based on BWR plants observing variances with

MSIV leakage rates.

The DAEC addressed the concern with a complete study evaluating the path of the fission products from the reactor vessel through the main steam lines to the turbine stop valves. The study also encompassed effects such as diffusion, natural convection and condensation, with respect to the transportation mechanism. The results of the study concluded that the two hour radiological exposure (as defined in 10 CFR 100) from the MSIV leakage was indeed nonexistent and that the

thirty day low population zone dose was well below the 10 CFR 100 Guidelines. (The plant's

original licensing basis. The current licensing basis is 10CFR 50.67).

The Main Steam Isolation Valve Leakage Control System (MSIV-LCS) was proposed

and installed. The MSIV-LCS was designed to collect MSIV leakage following a design basis loss of coolant accident (LOCA) and process it through the Standby Gas Treatment System. The system provided additional assurance that the radioactivity, which may leak from the primary containment as a consequence of MSIV leakage, would not bypass the secondary containment in

the event of an accident

In 1982 the BWR Owners Group (BWROG) formed a Main Steam Isolation Valve Leakage Committee to identify and resolve the causes of high MSIV leakage rates. The BWROG then formed a follow-on MSIV Leakage Closure Committee in 1986 to address alternate actions to resolve on-going, but less severe MSIV leakage problems and to address the limited capability of MSIV-LCS.

As a resolution to the MSIV-LCS concerns, the BWROG proposed to use the main steam piping and main condenser as a method for MSIV leakage treatment. Based upon the studies and recommendations mentioned, the DAEC has chosen to eliminate the MSIV-LCS and take credit for MSIV leakage utilizing the main steam drain lines and the main condenser. The allowable MSIV leakage rate limit has been increased to 100 scfh per valve, and the total main steam pathway, which includes the 4 main steam lines and the inboard MSIV drain line, is limited to 200 scfh. The bases for this approach and guidelines for implementation are contained in NEDC-31858P, Revision 2, BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems (Reference 1).

UFSAR/DAEC-1 6.7-2 Revision 21 - 5/11

6.7.2 DESIGN

BASES

The design bases of the MSIV Leakage Treatment Path are established to ensure safe and efficient operation and to fulfill the NRC's requirements of minimizing radiological releases

under accident conditions. The design bases are as follows:

The MSIV Leakage Treatment Path is established after a design-basis LOCA, with MSIVs isolated and indications of fuel damage.

The leakage path and isolation boundaries are established from the Control Room, by manual operator action.

MSIV leakage rate limits are 100 scfh per valve, and the total main steam pathway, which includes the 4 main steam lines and the inboard MSIV drain line, is limited to 200 scfh per Technical Specifications.

Offsite power is unavailable.

The leakage treatment path and isolated boundary systems shall be "seismically rugged" and will remain functional during and after a seismic event.

Radiological releases shall be limited by 10 CFR 50.67 and 10 CFR 50 Appendix A (General Design Criterion 19) guidelines.

The MSIV Leakage Treatment Path shall comply with the applicable requirements of the ASME Section XI and Augmented Programs.

Equipment will comply with requirements of the Environmental Qualification Program (10 CFR 50.49)

6.7.3 LEAKAGE

TREATMENT PATH DESCRIPTION

The MSIV Leakage Treatment Path is designed to mitigate the release of fission products following a LOCA. This is accomplished by directing MSIV leakage to the main condenser via the outboard main steam drain line. The volume and surface area of the condenser provides holdup time and plate-out surface for fission products. Other steam systems connected to Main Steam are isolated to ensure that leakage is processed through this path. The leakage treatment path and isolation boundaries are shown in Figure 6.7-1. The MSIV Leakage Treatment Path is

established by operator action following a design-basis LOCA, with MSIVs isolated and indications of fuel failure. All operations are performed from the Control Room.

MO1043 and MO1044 are opened to establish the primary leakage path to the main condenser. Both MOVs are provided with essential power from 1B37 to assure that they can be

opened with a coincident loss of offsite power. An alternate drain path is available to convey UFSAR/DAEC-1 6.7-3 Revision 21 - 5/11 MSIV leakage to the isolated condenser if either MOV fails to open. The alternate drain path consists of the bypass line around MO1043 via CV1064, and the bypass around MO1044 via FO1051. CV1064 is a "fail open" valve and FO1051 is a normally open path. Consequently, if either primary MOV failed to open as required, the second drain path would be available to convey MSIV leakage to the main condenser.

The steam systems connected to Main Steam are isolated to ensure that leakage is directed to the main condenser. MO1362A and MO1362B are closed to isolate the offgas and steam jet air ejector systems. MO1169 and MO1170 are closed to isolate the turbine steam seal system. MO1054 and MO1055 are closed to isolate the second stage reheat system. These six MOVs are provided with essential power from 1B37.

6.7.4 SAFETY

ASSESSMENT

6.7.4.1 Safety Evaluation

The implementation of the new leakage treatment path required revision of the DAEC

Technical Specifications (TS). The allowable leak rate specified in TS was increased from 11.5 scfh for any one MSIV to 100 scfh for any one MSIV with a total maximum pathway leakage of 200 scfh through all four main steam lines (including the inboard MSIV drain line). The MSIV leakage control system (LCS) requirements have been deleted from the TS. This TS change has been evaluated and documented in accordance with 10 CFR 50.90 and 50.59, and reviewed and

approved by the NRC (Reference 2).

6.7.4.2 Seismic Verification

The MSIV Leakage Treatment Path uses the main steam piping, main steam drain lines, and main condenser as an alternate method of processing MSIV leakage. Because certain main steam piping and components were not designed as Seismic Category I items, detailed evaluations and seismic verification walkdowns were performed to demonstrate that the main steam system piping and equipment that constitute the alternate treatment path are seismically rugged and meet General Design Criterion 2 of A ppendix A to 10 CFR Part 50 with regard to seismic adequacy. The seismic adequacy of these piping and equipment systems at the DAEC was confirmed by comparing them to a detailed earthquake experience database as discussed in

Section 6.7 of NEDC-31858P Revision 2 (Reference 1), and performing engineering walkdowns and evaluations using seismic capability engineers.

Seismic evaluations for piping, supports, and equipment associated with the MSIV leakage treatment path were based on new floor response spectra generated for the turbine building. The seismic response of the turbine building design basis earthquake (DBE) was based on the original seismic building model, a NUREG 0098 ground response spectrum, and a soil-

structure interaction(SSI) analysis.

UFSAR/DAEC-1 6.7-4 Revision 21 - 5/11 The purpose of the SSI analysis was to obtain a more realistic seismic response for the turbine building due to the ground motion of the DAEC DBE. The DAEC DBE is a "Housner" type spectrum with a peak ground acceleration of 0.12g. The methodology for determining the new floor response spectra for the turbine building and performing seismic evaluations of non-seismic piping supports and equipment was consistent with the seismic margins assessment methodology described in Reference 1 of EPRI Report NP-6041-SL. That is, seismic evaluations of non-seismic components were based on 1) a conservative design ground motion, 2) realistic (median centered) response, and 3)conservative allowables or capacities. This approach results in a high confidence of low probability of failure. The methodology used for this application is not an endorsement for the use of the experienced-based methodology for other applications at

the DAEC.

The DAEC has concluded that the main steam lines, main steam drain lines, condenser, and applicable interconnecting piping and equipment are well represented by the earthquake experience data demonstrating good seismic performance, are confirmed to exhibit excellent resistance to damage from a DBE, and have been shown to have substantial margin for seismic capability. Therefore they are seismically adequate to withstand the DAEC DBE and maintain pressure retaining integrity. This capability of the alternate MSIV leakage treatment system to

withstand the effects of the safe shutdown earthquake and continue to perform its intended function (treatment of MSIV leakage) satisfies the intent of the seismic requirement of Appendix A to 10 CFR 100. The DAEC therefore concluded that the proposed method for MSIV leakage treatment is seismically adequate to serve as an acceptable alternative to the previously installed

LCS.

6.7.4.3 Radiological Analysis

To demonstrate the adequacy of the DAEC engineered safety features, an assessment was performed of the offsite radiological consequences that could result from the occurrence of

design-basis-accidents (DBAs) with a leakage rate of 100 scfh per MSIV with a total leakage rate of 200 scfh through the four main steam lines (including the inboard MSIV drain line) and without the MSIV LCS. The radiological dose methodology developed by GE for the BWROG is documented in Appendix C of Reference 1. This analysis was updated during DAEC implementation of the Alternative Source Term Methodology defined in 10CFR 50.67 and

guidelines of RG 1.183. See Chapter 15.2.1 for details of the MSIV leakage path contribution to total dose consequences.

UFSAR/DAEC-1 6.7-5 Revision 21 - 5/11 References for Section 6.7

1. NEDC-31858P Revision 2 BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems, September 1993.

2. NG-94-2629, RTS-232: Increase in Allowable MSIV Leakage Rate and Deletion of the MSIV Leakage Control System, dated August 15, 1994.

3. Amendment No. 207 to Facility Operating License No. DPR-49, Duane Arnold

Energy Center (TAC No. M90155), dated February 22, 1995.

4. NG-94-4632, DAEC, Docket No. 50-331, Operating License No. DPR-49, Response to NRC RAI on MSIV Leakage Control System Technical Specification Amendment Request (RTS 232), dated December 21, 1994.

5. NG-95-0089, DAEC, Docket No. 50-331, Operating License No. DPR-49,

Request for Technical Specification Change , RTS 232, Increase in Allowable MSIV Leakage Control System, dated January 20, 1995.

6. Amendment No. 276 to Facility Operating License No. DPR-49, Duane Arnold Energy Center (TAC Nos. ME0873/0874, dated March 31, 2010 (ADAMs ACCESSION NO.: ML100621169).

UFSAR/DAEC-1 Table 6.7-1 T6.7-1 Revision 17 - 10/03 Deleted UFSAR/DAEC-1 Table 6.7-1 Sheet 2 of 2 T6.7-2 Revision 17 - 10/03

OFFGASSYSTEMIBECH-MI4))1------STEAMJETAIREJECTOR,lE008BIBECH-M105)M01362AVPRIMARYINO)CONTAINMENT1------STEAMJETAIREJECTOR,lE008AIBECH-MI05)ITM01362BINO)NOTES:1.ESSENTIALPOWERISPROVIDEDTOTHEFOLLOWINGVALYES:M01362A,M013628,M01169,M01170,1'101043,M01044,M01054.M010552.LINEUPDEPICTSAPOSTLOCALINEUP,OPERATORACTIONISREQUIREDTOPOSITIONTHEFOLLOWINGVALVES:M01362A,M013628,M01169,M01043,1'101044,CV1064,M01054,M010553.MAINSTEAMLINESBETWEENTHEMSIVUPTOTHESTOPVALVE,INCLUDINGBRANCHLINES3"ANDLARGERHAVEBEENSEISMICALLYANALYZED.4.ALLCONNECTINGBRANCHLINESSUCHASHPCI.RCIC.EQUALIZINGHEADERDRAIN.(2"ANDUNDER).VENTSANDINSTRUMENTATIONTAPSARENOTDEPICTEDBUTWEREINCLUDEDINTHEEOESEISMICADEOUACYEVALUATION.REFERENCEDRAWINGS:1.BECH-M103<1>.<2>2.BECH-M104<l>3.BECH-M105<1>4.BECH-M1145.BECH-M1226.BECH-M1247.BECH-M1418.BECH-M14Cj9.OI-646.683,69210.IP0I-3NO"NORMALLYOPENNC"NORMALLYCLOSEDFC"FAILEDCLOSED'4SEISMICADEQUACYWALKDOWNBOUNDARY'*'"PRIMARYDRAINPATH:::ALTERNATEDRAINPATHM04424FROMM04423INC)INBOAROMAINORAINTOCONOENSERIFC)20"-EBD-2MAIN'420"-EBD-2STEAMSTOPVALVESTOPCONDENSER&8EFORESEATDRAINlE007A/BCONTROL20"-EBD-2VALVE!--IFC)20"-EBD-2!--8YPASSCONTROLVALVESA'--_---'-D10"-E8D-6F01064E"M0l043INC)AL,L6"-E8D-3INC)F0l043'INC>,I2/1IL--i__JF0l051MOl170INC)4"-EBo-63"3"MOl169INO)IMAINDRAINTOCONDENSER)3"-E8D-3"0,,lC213B00Q)Q)TURBINEBUILDINGwwSAMPLESYSTEM,,MMV12"-E8D-6A.'LLLM01055INO)10"-E80-6'---0-TOM04424M01054'JjINO)L\AINSTEAMLINESCV4412CV44131"-E80-2'A-.__--=--'==-=--1C:4415II'8'--ff..---ICV441BCV44192"-T';-iI6"'C'----,r-....,--'CV4420CV4421,,1",6"'0'----,r-....,'-L--:--------,---""'---="--=---IIt,2"-EBD-2L_M04423INC)2NDSTAGEREHEATIBECH-MI03<l))TURBINESTEAMSEALSIBECH-MI04<l>)DUANEARNOLDENERGYCENTERNEXTERAENERGYDUANEARNOLD,LLCUPDATEDFINALSAFETYANALYSISREPORTMSIVLEAKAGETREATMENTPATHANDISOLAnONBOUNDARIESFIGURE6.7-[REVISION20-08/09