ML22325A130

4 to Updated Final Safety Analysis Report, Chapter 6, Engineered Safety Features

ML22325A130
Person / Time
Site:	Fermi, 07200071
Issue date:	11/17/2022
From:	DTE Electric Company
To:	Office of Nuclear Reactor Regulation
Shared Package
ML22325A160	List: ML22325A124 ML22325A125 ML22325A126 ML22325A127 ML22325A129 ML22325A130 ML22325A131 ML22325A132 ML22325A133 ML22325A134 ML22325A135 ML22325A136 ML22325A138 ML22325A139 ML22325A142 ML22325A143 ML22325A144 ML22325A145 ML22325A146 ML22325A147 ML22325A154 NRC-22-0052, Replacement Files for Submittal of Revision 24 to the Fermi 2 Updated Final Safety Analysis Report (UFSAR) Through EIE on November 9, 2022
References
NRC-22-0052
Download: ML22325A130 (1)

Text

FERMI 2 UFSAR CHAPTER 6: ENGINEERED SAFETY FEATURES 6.1 GENERAL Engineered safety feature (ESF) systems are provided to mitigate the consequences of postulated accidents. The following ESF systems are discussed in this chapter:

a. Containment structures

1. Primary

2. Secondary.

b. Containment systems

c. Emergency core cooling system

1. High pressure coolant injection system

2. Automatic depressurization system

3. Core spray system

4. Low pressure coolant injection mode of residual heat removal system.

d. Main control room habitability systems.

In addition to the ESF systems discussed in this chapter, other ESF systems discussed elsewhere are provided to limit the consequences of postulated accidents. The ESF systems are covered in Chapter 6 and those other locations referenced in Table 6.1-1.

The information provided herein demonstrates the following:

a. The concepts upon which the operation of each system is predicated have been proven by tests under simulated accident conditions and/or by conservative extrapolations from present knowledge and experience

b. Component reliability, system independency, redundancy, and separation of components or portions of systems ensure that the feature will accomplish its intended purpose and will function for the period required

c. Provisions for test, inspection, and surveillance have been made to ensure that the feature will be dependable and effective upon demand

d. The material used will withstand the postulated accident environment, including radiation levels, and the radiolytic decomposition products which may occur will not interfere with ESF systems.

6.1-1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.1-1 ENGINEERED SAFETY FEATURES DISCUSSED IN OTHER CHAPTERS OF FERMI 2 UFSAR Engineered Safety Fearures UFSAR Location Chapter 4 Control rod velocity limiter 4.5.2 Control rod drive housing supports 4.5.3 Chapter 5 Main steam line flow restrictors 5.5.4 Main steam line isolation valves 5.5.5 Chapter 7 Main steam line monitoring system 7.3.2, 11.4.3 Chapter 8 Onsite power systems 8.3 AC power systems 8.3.1 DC power systems 8.3.2 Chapter 9 Emergency equipment cooling water and emergency 9.2.2 equipment service water systems Ultimate heat sink 9.2.5 RHR service water system 9.2.5.1 RHR complex reservoir 9.2.5.2.1 Mechanical draft cooling towers 9.2.5.2.2 ESF cooling and ventilation units 9.4.2 Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR 6.2 CONTAINMENT SYSTEMS 6.2.1 Containment Functional Design On September 9, 1992, the NRC issued Amendment 87 to the Fermi 2 operating license authorizing a change in the thermal power limit from 3293 MWt to 3430 MWt, a 4.2 percent increase in the thermal power and a 5 percent increase in steam flow. The Fermi 2 Power Uprate Program followed GE Nuclear Energy guidelines and evaluations for BWR power plants (References 1, 2, 3, and 4).

On February 10, 2014, the NRC issued Amendment 196 to the Fermi 2 operating license authorizing a change in the thermal power limit from 3430 MWt to 3486 MWt, a 1.64 percent increase in thermal power and a 1.88 percent increase in steam flow. This changed the net electrical capacity from 1150 MWe to approximately 1170 MWe. This power uprate was performed in accordance with 10 CFR 50, Appendix K and reflects the improvement in feedwater flow measurement. The Fermi 2 Measurement Uncertainty Recapture (MUR) power uprate followed the GE generic guidelines and evaluations for BWR plants provided in GEH Topical Report NEDC-32938P-A, Generic Guidelines and Evaluations for General Electric Boiling Water Reactor Thermal Power Optimization, Revision 2, May 2003 (Reference 30). The analyses performed at 102% of the pre-MUR licensed thermal power (3430 MWt) remain applicable at the MUR uprated thermal power (3486 MWt) because the 2% uncertainty factor discussed in Regulatory Guide 1.49 is effectively reduced by the improvement in feedwater flow measurements.

Short-term and long-term containment analyses results are reported in Subsection 6.2.1.3.

The short-term analysis is directed primarily at determining the drywell pressure responses during the initial blowdown of the reactor vessel inventory to the containment following a large break inside the drywell. The long-term analysis is directed primarily at the pool temperature response, considering the decay heat addition to the pool.

6.2.1.1 Design Bases The containment system design meets the following safety design bases:

a. The containment systems shall have the capability to withstand the peak transient pressures and temperatures that could occur due to a postulated design-basis accident (DBA), intermediate-break accident (IBA), or small-break accident (SBA). The assumptions and criteria used to conservatively predict the short-term pressure and temperature response of the containment system drywell and suppression chamber during these accident conditions are provided in the Mark I Owners Group Load Definition Report (Reference 5),

the Fermi 2 Plant Unique Load Definition Report (Reference 6), and in NUREG-0661 (Reference 7). The reevaluation of containment response for power uprate is provided in References 3 and 4. The long-term response of the drywell and suppression chamber is described in Subsection 6.2.1.3.3.

No one accident results in the simultaneous occurrence of the maximum values of pressure and temperature (drywell design pressure and temperature, suppression chamber design pressure and temperature) 6.2-1 REV 24 11/22

FERMI 2 UFSAR

b. The containment systems shall accommodate the effects of metal/water reactions and other chemical reactions following the postulated DBA to values consistent with Regulatory Guide 1.7

c. The containment shall have the capability to maintain its functional integrity indefinitely after a postulated DBA, IBA, or SBA

d. The containment design shall permit filling the containment system drywell with water to a level above the reactor core

e. The containment system shall be protected against missiles from internal or external sources and excessive motion of pipes that could directly or indirectly endanger the integrity of the containment

f. The containment shall withstand jet forces associated with the flow from the postulated rupture of any pipe within the containment

g. The containment shall limit leakage during and following a postulated accident to values less than leakage rates that would result in offsite doses greater than the limits established in 10 CFR 50.67 or 10 CFR 100

h. It shall be possible to periodically conduct such leakage tests as may be appropriate to confirm the integrity of the containment at calculated peak pressure resulting from the accident condition that produces the maximum pressure response (DBA)

i. There shall be means to direct the flow from postulated pipe ruptures to the pressure suppression pool, to distribute such flow uniformly throughout the pool, to condense the steam portion of the flow rapidly, and to limit the pressure differentials between the drywell and the wetwell during the various postaccident cooling modes. The hydrodynamic events of pool swell, condensation oscillation, and chugging that occur during these flow and steam condensation regimes are defined by NUREG-0661 (Reference 7) and the Mark I Owners Group Load Definition Report (Reference 5). The design basis of the containment system includes the loading conditions associated with these hydrodynamic events

j. Capability for rapid closure or isolation of all pipes or ducts that penetrate the containment shall be provided by means that provide a containment barrier in such pipes or ducts sufficient to maintain leakage within permissible limits

k. There shall be the means for stable steam condensation of safety/relief valve (SRV) discharges into the suppression pool during transient and accident plant conditions. The containment system design basis includes the SRV actuation events, associated hydrodynamic loading conditions, and pool temperature limits described in NUREG-0661 (Reference 7), NUREG-0783 (Reference 8),

and the Mark I Owners Group Load Definition Report (Reference 5)

l. During the DBA, with the minimum emergency core cooling system (ECCS) pumps operating, and the available service water at the design maximum temperature, the long-term peak pool temperature shall not exceed the design temperature.

6.2-2 REV 24 11/22

FERMI 2 UFSAR 6.2.1.2 System Design There are two passive provisions for containment of possible postaccident airborne contamination, the primary containment system and the secondary containment system. A perspective drawing illustrating these systems and their relationship is presented in Figure 5.1-4.

In addition to these two passive containment systems, the gases in either the primary or secondary containment can be exhausted through the standby gas treatment system (SGTS).

This arrangement ensures that any accident-related discharge will be filtered by the SGTS before release. The SGTS is discussed in Subsection 6.2.3.

6.2.1.2.1 Primary Containment The primary containment is a pressure suppression system. It consists of a drywell that houses the reactor pressure vessel (RPV); reactor coolant recirculating loops, and other branch connections of the reactor coolant system; a pressure suppression chamber that stores a large volume of water; a vent system connecting the drywell and the pressure suppression chamber water; a vacuum relief system; isolation valves; and service equipment.

In the event of a process system piping failure within the drywell, reactor water and steam would be released into the drywell. The resulting increased drywell pressure would force a mixture of air, steam, and water through the vents into the pool of water that is stored in the suppression chamber. The steam would condense in the suppression pool, resulting in a rapid pressure reduction in the drywell. The hydrodynamic events of pool swell, condensation oscillation, and chugging associated with the venting and steam condensation processes are described in NUREG-0661 (Reference 7) and the Mark I Owners Group Load Definition Report (Reference 5). Noncondensable gases trans-ferred to the suppression chamber pressurize the chamber and are subsequently vented back to the drywell to equalize the pressure between the two vessels. Cooling of the primary containment under accident conditions is provided by the containment cooling and spray modes of the residual heat removal (RHR) system, as discussed in Subsection 6.2.2. Appropriate isolation valves are actuated to ensure containment of radioactive materials that might otherwise be released from the primary containment.

Detailed design information of the primary containment is given in Subsection 3.8.2 and in References 9 and 10. The information given there includes the dynamic loads that could be imposed on the torus, the vent system, the torus internal structures, and the torus attached piping following a LOCA. Also given there is a description of the methods used to determine these loads and how these loads were incorporated in the structural and attached piping design. A summary of important design parameters of the primary containment is presented in Table 6.2-1. The more important features of the primary containment system are described below.

6.2-3 REV 24 11/22

FERMI 2 UFSAR 6.2.1.2.1.1 Drywell The drywell is a steel pressure vessel with a spherical lower portion, 68 ft in diameter, and a cylindrical upper portion, 38 ft 10 in. in diameter. The overall height is approximately 114 ft 8 in. The drywell design pressure is 56 psig at a temperature of 281°F. The design temperature is 340°F with a coincident pressure of 25 psig.

The design, fabrication, inspection, and testing of the drywell vessel comply with requirements of the ASME Boiler and Pressure Vessel (B&PV) Code Section III, Nuclear Vessels, 1968 Edition with Summer 1969 Addenda, Subsection B, Requirements for Class B Vessels, which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywell are fabricated of SA-5l6GR70 steel plate, firebox quality, aluminum-killed to SA-300 requirements. Thermal stress in the steel shell due to temperature gradients is considered in the design. Special procedures not required by code have been used in the fabrication of the steel drywell shell. For seams exceeding 1-1/4-in. thickness, the plate was heated to a minimum temperature of 200°F prior to welding. For seams 1-1/4 in. or less, the plate was heated to a minimum temperature of l00°F if the ambient temperature was below 40°F.

Charpy V-notch impact tests were performed on specimens of all plate and forged materials.

Plates, forgings, and pipes of the drywell have an initial nil ductility transition (NDT) temperature of approximately 0°F when tested in accordance with the appropriate code for these materials. It can be reasonably expected that the drywell will not be pressurized or subjected to a substantial stress at temperatures below 30°F.

The drywell is enclosed in reinforced concrete for shielding purposes. Resistance to deformation and buckling of the drywell is provided over areas where the concrete backs up the steel shell. Above Elevation 572 ft 1 in., the drywell is separated from the reinforced concrete by a gap of approximately 2 in. This gap is filled with a compressible polyurethane material to allow for movement between the drywell and concrete. The bottom portion of the shell is totally embedded in concrete and therefore is not subject to significant thermal stresses. The transition zone (below Elevation 572.5 ft) is backed by compacted sand to allow for thermal expansion and to aid in the drainage of condensate that may accumulate in the gap outside the drywell. Sand in the four drain lines at azimuths 0, 90, 180, and 270 degrees have been removed up to the pipe upstream of the 90 degree elbow. Sand in the sand cushion or transition zone is still intact.

Provisions for protection of the drywell against earthquakes, missiles, and pipe whip, which could damage the primary containment, are discussed in Chapter 3.

6.2.1.2.1.2 Pressure Suppression Chamber The pressure suppression chamber is a steel pressure vessel, in the shape of a torus, below and encircling the drywell. It has a major diameter of 112 ft 6 in. and a cross-sectional diameter of 30 ft 6 in. It contains a total volume of approximately 251,980 ft3. The suppression chamber is supported vertically by inside and outside columns and by a saddle support that spans the inside and outside columns. The support system transmits dead weight and seismic and hydrodynamic loading to the reinforced-concrete foundation slab of the reactor building. Space is provided outside the chamber for inspection and maintenance.

6.2-4 REV 24 11/22

FERMI 2 UFSAR The pressure suppression chamber is designed for a temperature of 281°F and a pressure of 56 psig. The suppression chamber was originally designed to the same material and code requirements as the drywell vessel. The suppression chamber has been subsequently reevaluated for the effects of LOCA-related loads and SRV-discharge-related loads defined by the NRC Safety Evaluation Report NUREG-0661, the GE Reports NEDO-21888 (Mark I Containment Program Load Definition Report) and NEDC-31897P-1 (Generic Guidelines for General Electric Boiling Water Reactor Power Uprate). The criteria set forth in NUREG-0661 have been applied as the basis for acceptance of the analysis methods and the suppression chamber design. A detailed discussion of these reevaluations and their results is provided in the Fermi 2 Plant Unique Analysis Report (References 9 and 10) and in the Power Uprate Safety Analysis (Reference 3). All materials have an initial NDT temperature of approximately 0°F.

Where safety/relief valves terminate inside the suppression chamber, T-quencher devices are provided to aid in mitigating the associated SRV discharge loads in the suppression chamber.

Reference 5 contains a description of the T-quencher design and its performance.

6.2.1.2.1.3 Vent Systems Eight vent pipes connect the drywell and the pressure suppression chamber. Each pipe has a diameter of 6 ft 0 in. The vent pipes are designed for an internal pressure of 56 psig at 281°F. They will withstand an external pressure of 2 psig. Jet deflectors are provided in the drywell at the inlet of each vent pipe to prevent possible damage from jet forces, which might accompany a pipe break in the drywell. The vent pipes are fabricated of SA-516GR70 steel plate, firebox quality, aluminum-killed to SA-300 requirements, and comply with requirements of the ASME B&PV Code Section III, Subsection B. The pipes are enclosed with sleeves and provided with expansion joints to accommodate differential motion between the drywell and suppression chamber.

These vent pipes connect to a vent header in the form of a torus located in the air space of the suppression chamber. The vent header is nominally 1/4-in. thick and has an inside diameter of 4 ft 3 in. Near the vent line-vent header intersection, the vent header has an inside diameter of 6 ft 0 in. Conical transition segments connect the smaller and larger diameter portions of the vent header.

The vent header and downcomer system inside the torus was designed, fabricated, and erected in accordance with ASME B&PV Code Section III, 1968 Edition through winter 1969 addenda, Class B requirements but it is not leak tested.

Projecting downward from the header are 80 downcomer pipes, each 24 in. in diameter and terminating below the surface of the water in the suppression chamber pool. The pool water level is maintained to ensure a 3.00- to 3.33-ft submergence of the downcomer pipes. The header is designed to meet the same temperature and pressure requirements as the vent pipes.

The vent system has also been evaluated for the effects of LOCA-related loads and SRV-discharge-related loads defined by NUREG-0661 and NEDO-21888. As with the suppression chamber discussed above, a detailed discussion of these evaluations is provided in References 3 and 9.

6.2-5 REV 24 11/22

FERMI 2 UFSAR Vacuum breakers discharge from the suppression chamber into the vent header system.

Vacuum breaker sizing is based on the Moss Landing (Reference 11) test configuration.

Both the drywell and the pressure suppression chamber can be vented to the atmosphere through the SGTS or reactor building ventilation system.

6.2.1.2.1.4 Pipe Penetrations Primary containment penetrations are designed for peak transient conditions to be expected during a LOCA. They will withstand, or are shielded from, the forces caused by impingement of fluid from the rupture of the largest local pipe or connection. Specific evaluations of the suppression chamber penetrations to address the requirements of NUREG-0661 are described in Reference 10.

These penetrations are designed to accommodate, without failure, any combination of thermal and mechanical stresses, which may be encountered during all modes of operation.

(Refer to Subsection 3.8.2.1.3.)

Primary containment system piping penetrations are enumerated in Table 6.2-2. Electrical penetrations are listed in Table 6.2-3.

Relative movement between the containment penetrations and the drywell is accommodated by using bellows-type expansion joints (Figure 6.2-1). For this type of penetration, a sleeve passes through concrete and is welded to the primary containment vessel. The process line that passes through the penetration is anchored to allow only radial thermal expansion. A guard pipe surrounds the process line to protect the bellows and maintain containment integrity should the process line fail within the penetration. Insulation and air gaps are provided to reduce radiant heating of the guard pipe and the penetration sleeve and bellows.

The dual-ply bellows arrangement permits periodic leak testing of these penetrations at a pressure equal to the primary containment DBA pressure (see Subsection 6.2.1.4) as well as continuous monitoring capability.

Figure 6.2-1 presents the containment penetration configuration for a typical process line of the reactor coolant pressure boundary (RCPB). As it passes through the drywell containment vessel and the concrete biological shield, the process line is enclosed in a guard pipe that is attached to it through a multiple head fitting. This fitting is a one-piece forging with integral flues or nozzles made to SA-105, Grade II requirements, and designed to meet all requirements of the ASME B&PV Code Section III, Class l. The guard pipe design is based on 90 percent of the material yield stress when pressurized to 1250 psi due to process line rupture. The process line penetration sleeve is welded to a bellows which in turn is welded to the guard pipe. The bellows assembly accommodates the differential thermal expansion and seismic movements between the process pipe and the drywell in the three mutually perpendicular directions.

Pipe penetrations for those applications not requiring provisions for relative movement between pipe and containment shell are illustrated in Figures 6.2-2 and 6.2-3.

The design of the penetrations takes into account the simultaneous stresses associated with normal thermal expansion, live and dead loads, seismic loads, and loads associated with LOCAs within the drywell. For all of these conditions, including appropriate combinations of these loads, the resultant combined stresses in the pipe and penetration components do not 6.2-6 REV 24 11/22

FERMI 2 UFSAR exceed design limits allowable by applicable codes. If, in addition, the jet force loadings resulting from random failures of the steam pipe are included, the resultant stresses in the pipe and penetration do not exceed allowable code stresses for fault conditions.

Cold piping and ventilation duct penetrations are welded directly to the sleeves. Bellows and guard pipes are not necessary in these applications because the thermal stresses are small and accounted for in the design of the weld joints.

6.2.1.2.1.5 Electrical Penetrations Figure 6.2-4 shows a typical electrical penetration used for transmitting electric power, and instrumentation and control signals from the reactor building into the primary containment.

Separation of divisions is obtained by locating penetrations on the semi-peripheries of the containment at Elevation 604 ft. The division boundary is the east-west diameter. Division I is on the north half; Division II, the south half.

One group of six penetrations is used to transmit power to two 7100-hp, three-phase, 3920-V reactor coolant recirculation pump motors.

One group of two penetrations is used for low-voltage power, motor control three-phase, 480-V, 208-V, and single-phase 120-V, and 125-V-dc loads.

One group of two penetrations is used for 120-V signals for limit and level switches. These penetrations also contain an isolated penetration within a penetration for the reactor protection system (RPS).

One group of six penetrations is used for low-voltage instrumentation cable to transmit control and temperature signals for control rod position from reactor to recorders and computer.

One penetration is used for analog signals, to be used for vibration tests and miscellaneous primary signals.

One group of two penetrations for low-voltage shielded instrumentation thermocouple extension lead wire is used to transmit RPV and other equipment temperature signals to recording and readout equipment.

One group of four penetrations is used for neutron monitoring. The penetrations include the following coaxial and triaxial cables per penetration:

a. Three triaxial - for intermediate-range monitors

b. Two triaxial - for source range monitor

c. 48 coaxial - for local power range monitor.

All penetrations are sized for a 12-in.-diameter nozzle and are hermetically sealed, with provisions for continuous leak detection at design pressure. The penetrations are factory assembled, prewired and tested, and do not require field welding for installation due to the flange mount design. Radiation shielding is integral, thus minimizing radiation shine, and eliminating overhanging moments which would occur if shielding were mounted externally.

6.2-7 REV 24 11/22

FERMI 2 UFSAR Edison made a review of the primary containment electrical penetrations to determine that the electrical penetration assemblies were designed to withstand, without the loss of mechanical integrity, the maximum available fault current versus time conditions that could occur, given single random failures of circuit overload devices as recommended by Regulatory Guide 1.63, Revision 1.

In making the review, the following assumption was primary: The I2t characteristics of the penetration conductors as furnished by Conax Corp. were used as a basis for determining integrity. The I2t curves as furnished by Conax Corp. were conservative in nature and the I2t curve points were not necessarily the points of damage to the mechanical integrity of the penetrations.

The following positions are in line with the guidelines set forth in Regulatory Guide 1.63, which were taken by Edison, based on the results of this review.

a. For low-energy penetrations, maximum fault current does not approach the I2t of the penetration conductor. No backup or redundant protection is provided

b. On low-voltage power penetrations where maximum fault current versus time will exceed the I2t of the penetration conductor (considering single random failure of the primary protection), backup protection is provided by one of the two following methods:

1. If adequate backup protection can be obtained from the feeder position and the fault can be cleared in sufficient time to prevent reaching the I2t of the penetration conductor - no additional redundant protective devices are provided

2. Where the feeder position cannot provide adequate clearing time, an additional protective device, fuse or breaker as necessary, is provided.

There are six medium voltage power penetrations, and they are used for the reactor recirculation pump motor M-G set output from the generator to the pump motors. In these cases the primary protection is provided by tripping the main M-G set motor drive incoming circuit breaker positions. Backup protection is provided by tripping the generator field breakers. Proper relaying ensures operation of the field breaker.

Loads to the primary containment not necessary for reactor operation (i.e., lighting and welding) are maintained in a deenergized condition.

6.2.1.2.1.6 Traversing In-Core Probe Penetrations A total of five traversing in-core probe (TIP) guide tubes and two spare penetrations pass through the primary containment. Penetrations of these guide tubes through the primary containment are sealed with a Class I drywell penetration seal weld which meets the requirements of the ASME B&PV Code Section III. These seals also meet the intent of Section III of the Code even though the Code has no provisions for qualifying the procedures or performance.

6.2-8 REV 24 11/22

FERMI 2 UFSAR 6.2.1.2.1.7 Personnel and Equipment Access Lock One personnel access lock is provided for access to the drywell (Figure 6.2-5). The lock has two gasketed doors in series. The inner door has a double seal gasket and the outer door a single gasket. The doors are designed and constructed to withstand the drywell design pressure. The doors are mechanically interlocked to ensure that at least one door is locked.

The locking mechanisms are designed so that a tight seal will be maintained when the doors are subjected to either internal or external pressure. The seals are capable of being tested for leakage. Two equipment access hatches and a control rod drive (CRD) removal hatch are in the spherical portion of the drywell. These hatches have double testable seals and are bolted in place (Figure 6.2-6).

6.2.1.2.1.8 Access To the Pressure Suppression Chamber Access from the reactor building to the pressure suppression chamber is provided at two locations. These are two 4-ft-diameter manhole entrances with double-gasketed bolted covers connected to the chamber by 4-ft-diameter steel pipes. These access ports are bolted closed when the primary containment is secured.

6.2.1.2.1.9 Access for Refueling Operations The head or top portion of the drywell vessel is removed during refueling operations. This head is held in place by studs and is sealed with a double seal. It is closed when the primary containment is required and is opened only when the primary coolant temperature is below 212°F and the pressure suppression system is not required to be operational.

A double seal on the head flange is provided to permit checking leaktightness after the drywell head has been replaced.

6.2.1.2.1.10 Venting and Vacuum Relief System The primary containment is designed for an external pressure of 2 psi. It can be vented through the SGTS or the reactor building ventilation system to limit pressure fluctuations caused by temperature changes during various operating modes. For normal operation, this can be accomplished through the small dedicated lines of the containment atmospheric control system that controls the venting or makeup of nitrogen. During normal operation, the primary containment is maintained at a slightly positive pressure by the Nitrogen Inerting System as described in Subsection 9.3.6.1. Containment pressure is monitored as described in Subsection 7.6.1.12.3.1. The same penetrations that are used for makeup nitrogen are also used to vent the containment for pressure control. The large ventilation purge connections are normally closed while the reactor is at a temperature greater than 212°F, except for inerting or purging. Vacuum breakers are between the drywell and the suppression chamber.

Automatic vacuum relief devices are used to prevent the external primary containment pressure from exceeding the design value. The drywell vacuum relief valves draw gas from the pressure suppression chamber, and the pressure suppression chamber vacuum relief device draws air from the reactor building.

6.2-9 REV 24 11/22

FERMI 2 UFSAR A vacuum breaker in series with an air-operated normally closed butterfly valve is used in each of two lines from the suppression chamber to the reactor building atmosphere. One valve (a pilot-operated butterfly valve) is actuated by a differential pressure signal. The second valve is a self-actuating vacuum breaker, opening at a maximum differential pressure of 0.5 psid. The valves are sized to provide sufficient mass flow rate to equalize the pressure between the suppression chamber and the reactor building in case of an inadvertent operation of the suppression chamber spray. The flow rate calculation assumed that the vacuum breaker valves failed to open until the differential pressure reached 1.0 psid. The two separate lines are redundant in that either can provide adequate venting.

The vacuum breakers connecting the suppression chamber and the drywell are sized on the basis of the pressure suppression system test program conducted for Bodega Bay at Moss Landing (Reference 11). The vacuum breaker flow area is proportional to the flow area of the vents connecting the drywell and suppression pool. Their chief purpose is to prevent excessive water-level variation in the portion of the vent discharge line that is submerged in suppression pool water. The tests relating to vacuum breaker sizing were conducted by simulating a small system rupture, which tended to cause vent water-level variation as a preliminary step in the large rupture test sequence. The vacuum breaker capacity selected on this test basis is more than adequate (typically by a factor of four) to limit the suppression chamber-drywell pressure differential during postaccident drywell cooling operations to within containment system design values.

The Fermi 2 vacuum breakers are described in Table 6.2-4. The number of suppression-chamber-to-drywell vacuum breaker valves was chosen so that 25 percent (three of 12) could fail to open and adequate venting would still be provided.

The vacuum breaker valves are provided with a magnetic latch that holds the valve disk against the seat so that vibration does not cause the valve to chatter. The close limit switches, located near the bottom of the valve body, are actuated directly by the pallet. This design allows a precise adjustment of the limit switch setpoint to a very slight opening of the pallet. The transfer point of the switch from the closed to open position is measured electrically using an ohm meter or other continuity device. With the switch properly adjusted, the maximum distance the valve may be unseated and still indicate the closed position is 0.03 in. After limit-switch adjustment, the opening gap of the pallet at the switch is verified to be less than or equal to 0.03 in. Inspection of vacuum breaker instrumentation during reactor refueling will include verification of the opening gap for switch actuation.

The bypass opening for the suppression-chamber-to-drywell vacuum breaker corresponding to a 0.03-in. disk opening is 0.009 ft2, well within the maximum allowable leakage area of 0.25 ft2 discussed in Subsection 6.2.1.3.6.

A suppression-chamber-to-drywell vacuum breaker valve similar to the Fermi 2 vacuum breaker valves has also been tested by the Mark I Owners Group in the full-scale test facility (FSTF). During several FSTF tests, the pressure fluctuations in the vent system produced during downcomer chugging caused the vacuum breaker to cycle open and closed. The measured FSTF pressure data have been used to evaluate the expected structural perfor-mance of the Fermi 2 vacuum breaker valves. The results of this evaluation are described in the report, Mark 1 Wetwell to Drywell Differential Pressure Load and Vacuum Breaker Response for the Fermi Atomic Power Plant Unit 2, by Continuum Dynamics, Inc.,

submitted to the NRC by Edison letter NE-85-0707 (Reference 12).

6.2-10 REV 24 11/22

FERMI 2 UFSAR The secondary containment to torus vacuum breaker open and closed valve disk positions are indicated by lights on the main control room panel H11-P808. The drywell-to-torus vacuum breakers are provided with open and closed position indicators on panel H11-P808, and a second set of closed position indicators on panel H11-P817. The drywell-to-torus closed indicating circuits are powered by Class 1E power supplies and are wired to meet the requirements of IEEE 279-1971.

There is no annunciation of the valve position. The position switches and circuits do not control or affect the operation of the vacuum breakers. Any single failure of the indicating circuits or switches will not prevent proper action of the vacuum breakers.

The drywell-to-torus and the secondary containment to torus vacuum breakers are equipped with pneumatic actuators operated by pushbuttons from the main control room. The purpose of these actuators is to enable verification of the operability of the vacuum breakers by observing the response of limit switches. The operability of the vacuum breakers will be verified as required by the Technical Specifications.

The actuators are sized such that they have insufficient power to open the vacuum breakers if a backflow differential pressure exists. The drywell-to-torus vacuum breakers and test actuator supports are designed to Category I criteria. The drywell-to-torus vacuum breaker nitrogen supply components downstream of the testing actuator solenoids are designed to Category II/I criteria. The drywell-to-torus vacuum breaker test actuator solenoids meet QA1 and Category I seismic requirements and are environmentally qualified because they form part of the primary containment inboard closed boundary associated with penetrations X204A - M. The secondary containment-to-torus vacuum breakers and test actuators (including actuator supports) are also designed to seismic Category I criteria.

A negative pressure analysis was performed to demonstrate the adequacy of the containment vacuum relief system (Reference 13).

The most severe negative pressures in containment would result from events that challenge the vacuum relief system. The events are associated with operation of the containment spray mode of the RHR system under accident and transient conditions which result in high depressurization rates.

The bounding accident events involve actuation of the drywell spray following a steam leak in the drywell (small-break accident) and following a DBA. All intermediate-line break events are enveloped by these cases. The inadvertent drywell spray actuation during plant operation has been evaluated. The inadvertent drywell spray scenario is an event characterized by multiple operator errors and was not part of the original License application and review. The confirmatory evaluation of this event takes credit for both reactor building to suppression chamber vacuum breakers being operable and assumes the initial drywell ambient temperature of 145°F as described in License Amendment 20. The assumed scenarios and respective bases that lead up to the initial condition for these three cases and the analysis of these three cases are described in Reference 13.

The drywell and torus pressure/temperature responses resulting from these three cases were calculated using a computer program for the calculation of mass and energy balances at successive time intervals using basic thermodynamic, flow, and ideal gas law equations.

6.2-11 REV 24 11/22

FERMI 2 UFSAR The mass flow of spray water through each loop increases in proportion to the opening flow characteristic of the outboard drywell spray isolation valve E1150F016A(B). The model employed assumes a linear valve flow characteristic that is scaled appropriately to accurately model the actual flow as a function of valve position. A linear ramp assuming 60 sec to reach maximum flow accurately reproduces the flow characteristic for a spray isolation valve having a 98-sec open stroke time. In order to model the flow characteristic of spray isolation valves having shorter opening stroke times, the time used to calculate the linear coefficient of mass flow acceleration is based on the 60-sec value scaled by the ratio of the actual minimum value of the valve open stroke time to 98 sec.

Many conservative assumptions are made in the calculational model. The spray is not accounted for in the drywell mass balances and only serves as a heat sink. The addition of water mass to the control volume atmospheres would tend to increase pressure and some vaporization of the spray would be expected. The butterfly valve opening setpoint was arbitrarily set at 0.5 psi. The actual setpoint is 0.25 psi. Any delay in butterfly valve opening time tends to increase depressurization.

The small break accident case was determined to be the most severe of the three bounding cases considered. A resulting drywell pressure of (-1.87 psid) was predicted for this case.

This value is below the design pressure for the containment structures of (-2.00) psid.

6.2.1.2.2 Secondary Containment System The reactor building completely encloses the reactor and its pressure suppression primary containment.

This building provides secondary containment when the primary containment is closed and in service, and provides primary containment when the primary containment is open, as it is during refueling. The reactor building houses the refueling and reactor servicing equipment; new- and spent-fuel storage facilities, and reactor auxiliary and service equipment, including the reactor core isolation cooling (RCIC) system; reactor cleanup demineralizer system, standby liquid control system (SLCS), CRD system equipment, emergency core cooling system (ECCS), and electrical equipment components.

The reactor building includes the "tunnel" containing the outboard main steam isolation valves (MSIVs), the main steam lines up to the turbine building, the feedwater lines, and the outboard feedwater line isolation valves. The tunnel is equipped with hinged doors which, upon pressure buildup due to a break in one of these lines, will relieve the steam pressure to the first and second floors of the turbine building. The net volume of the secondary containment is 2.8 x 106 ft3.

The reactor building is a Category I structure designed and constructed in accordance with all applicable local and state building code requirements.

Substructures and exterior walls of the building up to the refueling floor consist of poured-in-place, reinforced concrete. The building structure above the refueling floor is a steel frame covered with insulated metal siding and is sealed against leakage. The building is designed for an external pressure of 0.295 psig and for low inleakage and outleakage (depending on wind conditions) during reactor operation.

6.2-12 REV 24 11/22

FERMI 2 UFSAR 6.2.1.2.2.1 Reactor Building Penetrations Access openings for personnel and equipment are equipped with weather-strip-type seals, except for the railroad bay entry, for airtightness to meet secondary containment negative building pressure requirements. The railroad bay entry doors have inflatable seals which provide the airtightness requirements as well as site flood protection. The railroad bay rail pockets have seals which provide the airtightness requirements as well as site flood protection. Personnel entrances to the secondary containment are at the following locations:

a. The reactor core isolation cooling system/core spray pump room at Elevation 551 ft 0 in.

b. The auxiliary building basement from the CRD pump room at Elevation 551 ft 0 in.

c. Between the turbine and auxiliary building at Elevation 564 ft 0 in.

d. Outdoor entry to the reactor building at 583 ft 6in.

e. Railroad bay entry to the reactor building at 583 ft 6 in.

f. Between the reactor building and the auxiliary building at Elevation 613 ft 6 in.

g. Between the reactor building refueling floor and the auxiliary building at Elevation 684 ft 6 in.

h. Between the reactor building refueling floor and the auxiliary building at Elevation 701 ft 0 in.

All of these entries have a vestibule with double doors to maintain secondary containment integrity. The double doors are administratively controlled to prevent both doors from being open at the same time, thus maintaining secondary containment integrity. Additionally, as an administrative aid, the doors have either interlocks to prevent the opening of one door until the other door is closed or one of the doors is key locked closed. The interlock feature is not considered QA1 safety related. Failure of these interlock circuits would not cause the doors to open on their own accord. Keys for the locked closed doors are administratively controlled by the Shift Manager. In the case of the railroad bay airlock, the doors have inflatable seals which are considered active components. Therefore, to meet single failure criteria and maintain secondary containment integrity, the inner door seal is supplied from Division I of non-interruptible control air and the outer door seal is supplied from Division II of non-interruptible control air. The railroad bay airlock doors also have low seal pressure alarms which are monitored in the main control room.

Penetrations for piping and ducts are designed for leakage characteristics consistent with containment requirements for the entire building. Electrical cables and instrument leads pass through ducts sealed into the building wall.

6.2-13 REV 24 11/22

FERMI 2 UFSAR 6.2.1.2.2.2 Reactor Building Ventilation Systems The reactor building has two ventilation systems: the normal ventilation system and the SGTS. During normal power operation, shutdown, or refueling, the normal ventilation system provides outside filtered air to all levels and building equipment rooms. This system provides a minimum of one reactor building free volume change of air per hour. Air flows from the filtered supply to uncontaminated areas, to potentially contaminated areas, and then to the release vent (a short stack) on the reactor building roof.

The fans for the normal ventilation system are automatically shut down in the event a high radiation level in the building exhaust ducts is detected by the radiation monitoring system (RMS), or if there is high pressure in the drywell, low RPV water level, or high static pressure in the building, or if high radiation is detected by the east or west fuel pool radiation monitors. The normal ventilation may be isolated manually from the control room.

Shutting down the fans closes the dual ventilation duct isolation dampers. The fans are controlled from the main control room.

During emergencies when the normal ventilation system is not operating, the reactor building is ventilated through the SGTS. The SGTS filters and exhausts the atmosphere of the reactor building via the roof vent.

6.2.1.2.2.3 Bypass Leakage Paths One purpose of the secondary containment (reactor building) is to collect and filter leakage from the primary containment prior to release to the environment and thereby reduce offsite doses after a LOCA. This purpose is accomplished by

a. Minimizing reactor building leakage

b. Maintaining the reactor building at a negative pressure

c. Passing all exhaust from the reactor building through the SGTS after a LOCA.

A study has been made to evaluate the secondary containment system and determine all potential paths that could result in a fraction of the primary containment leakage going directly to the environment (i.e., without passing through the SGTS). The study encompasses three areas

a. Lines that are connected to the primary containment and pass through the secondary containment

b. Electrical penetrations

c. Reactor building leakage.

6.2-14 REV 24 11/22

FERMI 2 UFSAR Primary Containment Lines Lines that are connected to the primary containment and pass through the secondary containment are potential paths for leakage of radioactivity directly from the primary containment to the environment, bypassing the SGTS. The containment penetrations through which potential bypass leakage paths are possible are identified in Table 6.2-2.

All the bypass leakage paths listed in Table 6.2-2 will not contribute more leakage than 10 percent LA, where LA is the maximum allowable leak rate in the Type A containment integrated leak rate test (see Subsection 6.2.4.4). The radiological impacts of MSIV leakages of up to 100 scfh per steam line, and up to 250 scfh of total MSIV leakage are analyzed separately from LA controlled leakages. Fermi 2 uses air or water sealing systems that eliminate leakage through certain valves:

a. The torus water management system suction lines (penetrations X-213A and B) are sealed with water in the torus

b. The high pressure coolant injection system suction line from suppression chamber (penetration X-225) and reactor core isolation cooling system suction line from suppression chamber (penetration X-226) are sealed with water in the torus.

The bypass leakage program will maintain a running total of leak rate measurements through all other bypass leakage paths as listed in Table 6.2-2 and will compare it with the maximum allowable. Valve maintenance will be performed when necessary.

With the exception of two leakage paths, all the valves in the bypass leakage program are containment isolation valves, and, as such, leak rates will be measured in accordance with 10 CFR 50, Appendix J, Type C tests (see Subsection 6.2.4.4). These paths accordingly are protected by redundant and diversely powered isolation valves. In the case of the reactor vessel instrument line backfill system leakage through the CRD piping when the CRD pressure is lost, certain noncontainment isolation valves are used in the program to meet criteria equivalent to those met by the other leakage paths. These valves will be tested in accordance with Section XI, Category A, of the ASME Code.

6.2-15 REV 24 11/22

FERMI 2 UFSAR In summary, the following valves are encompassed in the bypass leakage program for Fermi 2:

System Valve Test Reactor Feedwater B2100F010A Appendix J, Type C B2100F010B Appendix J, Type C B2100F076A Appendix J, Type C B2100F076B Appendix J, Type C Steam line drain B2103F016 Appendix J, Type C B2103F019 Appendix J, Type C HPCI E4150F006 Appendix J, Type C E4150F002 Appendix J, Type C E4150F003 Appendix J, Type C E4150F600 Appendix J, Type C RCIC E5150F013 Appendix J, Type C E5150F007 Appendix J, Type C E5150F008 Appendix J, Type C Drywell sumps G1154F600 Appendix J, Type C G1100F003 Appendix J, Type C G1154F018 Appendix J, Type C G1100F019 Appendix J, Type C Reactor Vessel Instrument B2100F248A Section XI, Category A Line Backfill B2100F248B Section XI, Category A B2100F249A Section XI, Category A B2100F249B Section XI, Category A Emergency Equipment P4400F282A Appendix J, Type C Cooling Water System P4400F606A Appendix J, Type C (EECW) P4400F616 Appendix J, Type C P4400F607A Appendix J, Type C P4400F282B Appendix J, Type C P4400F606B Appendix J, Type C P4400F615 Appendix J, Type C P4400F607B Appendix J, Type C Post Accident Sampling P34F403A Appendix J, Type C System (PASS) P34F404A Appendix J, Type C P34F403B Appendix J, Type C P34F404B Appendix J, Type C P34F401A Appendix J, Type C P34F401B Appendix J, Type C P34F408 Appendix J, Type C P34F410 Appendix J, Type C P34F405B Appendix J, Type C P34F406B Appendix J, Type C P34F405A Appendix J, Type C P34F406A Appendix J, Type C 6.2-16 REV 24 11/22

FERMI 2 UFSAR The EECW penetrations are normally open. The listed valves are Remote Manual Isolation valves that are closed by the Operators responding to alarm response procedures. The EECW leakage detection equipment and other EECW system indications will provide the required information to the Operators. The analysis of the available sealing water in the EECW/RBCCW systems indicate that over two hours is available prior to required Operator actions to close these valves. Closure of these valves will ensure that this path will not exceed measured bypass leakage.

Leakage through the primary containment exhaust lines is collected by the SGTS and is not discharged through the exhaust fans. The large purge/inert lines and the small "on-line" pressure control lines are tied to both the reactor building ventilation system and the SGTS.

High radiation in the reactor building heating, ventilation, and air conditioning (RBHVAC) exhaust isolates these valves and starts the SGTS. A suction line to the SGTS is connected to the inerting supply line as shown in Figure 9.3-14. This line collects any leakage past the containment isolation valve and processes it through the SGTS.

Category I design requirements are met (1) on the main steam piping from the reactor, up to and including the third set of MSIVs, and (2) on all branch piping, up to and including the first valve that is either normally closed or capable of automatic closure during all modes of normal nuclear steam supply system (NSSS) operation.

Electrical Penetrations Electrical cables exit from the primary containment via penetrations sealed at both internal and external ends; the external end is within the secondary containment. The cables leaving these penetrations run in cable trays. Thus there are no electrical wiring conduits or ducts that go directly from the primary containment to the environment, bypassing the secondary containment.

Reactor Building Leakage The reactor building, under both normal and emergency conditions, is maintained at a negative pressure so that leakage is inward. The reactor building is maintained at 0.25 in.

plus or minus 0.125 in. water gage. However, due to the kinetics of gas at high velocities, the pressure on the leeward side of the building will be negative at high wind speeds.

Consequently, above a threshold wind speed, air could be drawn from the reactor building, bypassing the SGTS.

An exfiltration/infiltration analysis has been made on the building to determine inward and outward leakage rates as a function of wind speed. The analysis was based on the following:

a. The SGTS maintains the building at l/4 in. H2O negative pressure

b. Leakage to the environment occurs only through the metal siding and only when the pressure differential across the siding is outward

c. The rate of leakage is 0.015 ft3/minute/ft2 at 1/4 in. H2O and varies as the square root of pressure differential. The leakage rate is the same for positive and negative differentials

d. The wind force acts on two sides of the building; the other two sides are at a negative pressure 6.2-17 REV 24 11/22

FERMI 2 UFSAR

e. The positive and negative pressures due to wind are based on the equation P = 0.002558 S (GV)2 where P = wind pressure (lb/ft2)

S = shape factor = 0.9 windward s G = gust factor = 1.1 V = wind velocity (mph)

The study shows the threshold wind velocity for any leakage outward from the building is 30 mph. The study also shows that the net leakage (inward) through the siding is not a strong function of wind velocity; consequently, the operating parameters of the SGTS are independent of wind velocity.

Since there is siding only above the refueling floor, this leakage path is not directly from the primary containment to the environment, but rather from the secondary containment the reactor building. The estimate of the fraction of primary leakage bypassing the SGTS will be conservative if this fraction is assumed to be equal to the fraction of building leakage to total discharge from the reactor building. This statement can be expressed by the following equation:

S B=

S+G Where:

B = fraction of primary leakage bypassing SGTS S = outward leakage rate of siding (function of wind speed) (scfm)

G = discharge rate of SGTS (scfm)

The results of this study are summarized in the following table:

Reactor Building Leakage*

Wind Velocity Fraction of Time Total Outward From Fraction of Primary (mph) per Year** Siding (scfm) Leakage Bypassing SGTS 0 0.65 0 0 10 0.34 0 0 20 0.01 0 0 30 0.001 52 0.017 40 -- 246 0.076 50 -- 370 0.110

• The radiological dose from exfiltration will result in inconsequential increases, i.e., less than 1 percent, in the total calculated doses since the fraction of time the leakage occurs is so very small. In addition, if an atmospheric dispersion parameter (/), which is inversely proportional to wind speed, is calculated for the higher wind speeds associated with exfiltration, it will further decrease the dose values.

• • Winds of 15-minute duration as measured from the 10-m level on the 60-m tower during the 12-month period from June 1, 1974, to May 31, 1975.

6.2-18 REV 24 11/22

FERMI 2 UFSAR 6.2.1.3 Design Evaluation 6.2.1.3.1 Introduction In the design of the primary containment vessel, certain extreme conditions were hypothesized; the design then proceeded so that maximum stress levels under these conditions did not exceed the maximum allowable values specified in the appropriate code.

The key parameters of stress are vessel temperature, pressure, and hydrodynamic loads. The containment vessel for Fermi 2 was designed under ASME B&PV Code Section III, Nuclear Vessels (1968), including Summer 1969 Addenda. This code specifies that the internal pressure used for design conditions shall not be less than 90 percent of the maximum containment internal pressure, and that the design temperature shall not be less than the maximum containment temperature at the coincident maximum containment pressure.

The containment vent system and suppression shell, supports, internals, and attachments have been reevaluated (References 9 and 10) to include the hydrodynamic loading events and analysis methods defined by GE Topical Report NEDO-21888 (Mark I Containment Program Load Definition Report) and the NRC Safety Evaluation Report, NUREG-0661.

The appropriate edition of,Section III of the ASME Code and service-level limits specified in NUREG-0661, have been applied in the reevaluation.

The maximum drywell pressure occurs during the reactor blowdown phase of a LOCA. It is dependent upon the rate at which primary system energy and fluid enter the drywell. The largest pipe in the primary coolant system is the 28-in.-diameter main recirculation line. The instantaneous guillotine rupture of this pipe is the DBA for the containment design pressure.

The same pressure is conservatively used for suppression chamber design.

The most severe drywell temperature condition would occur as a result of a small primary system rupture above the reactor water level that results in the blowdown of reactor steam to the drywell. Because of the nature of the blowdown process, this would produce high-temperature steam in the drywell.

The blowdown phase of an intermediate-size break was also evaluated to demonstrate that breaks smaller than the rupture of the largest primary system pipe can be accommodated safely without any of the containment design parameters being exceeded.

In Subsections 6.2.1.3.2 through 6.2.1.3.8, the various extreme conditions that have been hypothesized and analyzed as part of the original licensing basis for the containment design are described as modified by power uprate. The initial conditions, assumptions, and break flow model applied in these analyses maximize the containment temperatures and pressures that could be expected during postulated LOCAs. The discussions of the analysis results in these subsections include the conservatively predicted short-term and long-term response of the containment. However, as part of the Fermi 2 Mark I containment long-term program (References 9 and 10), and the subsequent reevaluation of limiting events for the Power Uprate Safety Analysis (Reference 3), the spectra of postulated pipe breaks have been reinvestigated to determine the worst loading conditions for each of the affected containment structural elements. The loading conditions associated with the long-term program analyses included pool swell, condensation oscillation, chugging, and safety/relief valve discharge.

To establish a conservative load basis, the initial conditions, assumptions, and models 6.2-19 REV 24 11/22

FERMI 2 UFSAR differed, in some cases, from those used in the original licensing-basis containment analyses.

The load bases and application methods used in the Mark I containment analyses are completely described in Reference 5 and have been accepted by the NRC in NUREG-0661 (Reference 7). The plant-unique load definition (Reference 6) describes the pressure and temperature responses of the drywell, vent system, and suppression chamber volumes used in the Fermi 2 containment longterm program analyses. Since the long-term program-related loads occur early in the postulated LOCA events, Reference 6 only describes the short-term containment responses (less than 1100 sec). The break flow model used in the plant-unique load definition analyses is described in Reference 14.

6.2.1.3.2 Recirculation Line Break - Short-Term Response The instantaneous guillotine rupture of a main recirculation line results in the maximum flow rate of primary system fluid and energy into the drywell. This in turn results in the maximum containment differential pressure. Figure 6.2-7 is a diagram showing the location of a recirculation line break.

Immediately following the rupture, the flow out both sides of the break will be limited to the maximum allowed by critical-flow considerations. Figure 6.2-7 shows a schematic view of the flow paths to the break. In the side adjacent to the suction nozzle, the flow will correspond to critical flow in the nozzle pipe cross section. In the side adjacent to the injection nozzle, the flow will correspond to critical flow at the 10 jet pump nozzles associated with the broken loop. In addition, there is a 4-in. cleanup line cross tie that will add to the critical flow area, yielding a total of approximately 4.1 ft2.

The short-term analysis was performed for the limiting DBA/LOCA which assumes a double-ended guillotine break of a recirculation suction line that results in the maximum flow rate of primary system fluid and energy into the drywell. The analysis predicted the peak drywell pressure at 49.9 psig which is less than the containment allowable design limit of 62 psig. The peak drywell pressure of 49.9 psig is bounded by the Technical Specification value of 56.5 psig which has not been changed.

The short-term analysis covers the blowdown period during which the maximum drywell pressure and differential pressure between the drywell and wetwell occurs. The analysis assumed 102 percent power (102 percent of 3430 MWt, 3499 MWt) and was done using the M3CPT computer code which is used to model short-term containment pressure and temperature response. The M3CPT code is based on References 14 and 15 and has been reviewed and accepted by the NRC (Reference 7) during the Mark I Long Term Program (LTP) for application to the Mark I plants, including Fermi 2. The inputs for the short-term analysis (M3CPT code) are shown in Table 6.2-1,Section II.

Figure 6.2-8 shows the blowdown flow rates from the primary system to the containment.

Table 6.2-5 shows the primary system energy distribution at the time of the break.

(Reference 31)

The calculated primary containment pressure and temperature responses to this DBA/LOCA are shown in Figures 6.2-9 and 6.2-10.

The calculated peak drywell pressure is 49.9 psig. After the discharge of primary coolant from the RPV into the drywell, the temperature of the suppression chamber water approaches 6.2-20 REV 24 11/22

FERMI 2 UFSAR 135°F and the suppression chamber pressure stabilizes at approximately 25 psig. The drywell pressure stabilizes at a slightly higher pressure, the difference being equal to the downcomer submergence. During the RPV depressurization phase, most of the noncondensable gases in the drywell initially are forced into the suppression chamber.

However, the noncondensables will redistribute between the drywell and suppression chamber via the vacuum breaker system as the drywell pressure is decreased by steam condensation.

The LPCI and/or core spray system removes decay heat and stored heat from the core, thereby controlling core heatup and limiting any metal/water reaction. The RPV is flooded to the height of the jet pump nozzles and the excess flow discharges through the recirculation line break into the drywell. This flow of water transports the core decay heat out of the RPV, through the broken recirculation line in the form of hot water that flows into the suppression chamber via the drywell-to-suppression chamber vent pipes. Steam flow is negligible. This flow, in addition to heat losses to the drywell walls, offers considerable cooling to the drywell atmosphere and causes a depressurization of the containment as the steam in the drywell is condensed.

The LPCI/RHR pumps that are used to flood the core are also used as the containment spray and cooling pumps. Prior to activation of the containment cooling mode (arbitrarily assumed at 20 minutes after the accident), all of the LPCI pump flow may be used only to flood the core. After 20 minutes, the RHR pump flow will have to be diverted from the RPV to the containment cooling mode. This is a manual operation. Actually, the containment spray need not be activated at all to keep the containment pressure below the containment peak allowable pressure. As discussed above, the peak drywell pressure is less than the containment design limit of 62 psig.

6.2.1.3.3 Recirculation Line Break Long Term Response The primary purpose of this analysis is to calculate the peak suppression pool temperature following a DBA/LOCA. The GE SUPERHEX (SHEX) code is used to predict the long-term containment response following a DBA/LOCA event.

The limiting case assumes that one RHR loop is operating in the containment cooling mode at partial pumping capacity. This includes one RHR heat exchanger, one RHR main system pump, and two service water pumps. During this mode of operation the RHR pump draws suction from the suppression pool and discharges flow through the RHR heat exchangers where it is cooled and then injected back into the suppression pool. Core cooling is provided by the core spray system and the RHR/LPCI pump prior to activation of the containment cooling mode at 20 minutes after the accident.

The long term analysis using the SHEX code with conservative input values yielded a peak post DBA/LOCA pool temperature of 196.5°F. This temperature shows margin remains to the controlling limit of 198°F which comes from NPSH requirement for pumps taking suction from the suppression pool with no credit for containment pressure per Regulatory Guide 1.1 (Subsection 6.3.2.14).

The input parameters for the long term response are shown in Table 6.2-1,Section III.

Figures 6.2-11, 6,2-12, and 6.2-13 show the drywell and wetwell airspace pressure response, 6.2-21 REV 24 11/22

FERMI 2 UFSAR the drywell and wetwell airspace temperature response, and the suppression pool temperature response, respectively. The accident chronology is shown in Table 6.2-7. The conservatisms built into some of the inputs are described below.

Service Water

a. The Technical Specification limit for cooling tower reservoir temperature is 80°F.

An energy balance calculation was used to determine the post-LOCA RHRSW temperature increase as a function of time from the initial condition of 80°F to the cooling tower maximum design temperature of 90°F. The temperature profile, which is non-linear, was conservatively bounded by a linear profile with the initial temperature of 80°F increasing in a linear way to 90°F over an 8-hour period. (Note: The current maximum analyzed service water supply temperature is below the assumed maximum 90°F).

b. The minimum technical specification RHR reservoir water level was used. This is conservative because it minimizes the heat capacity of the reservoir and maximizes the reservoir heatup.

c. Evaporative and drift losses were used to reduce reservoir inventory during the heatup period.

d. Complete mixing is assumed in the reservoir. This is conservative because hot water is discharged into the cooling towers and is sprayed down to the surface of the reservoir. Cooler water is drawn from the bottom of the reservoir where the pump suctions are located. No credit is taken for temperature stratification which lowers the reservoir discharge temperature profile.

Suppression Pool Volume A pool volume of 117,161 ft3 is used for the long-term containment analysis. The technical specification minimum value is 121,080 ft3. This lower pool volume of 117,161 ft3 adds conservatism to the calculated pool temperature, since a lower initial pool volume results in higher calculated values for pool temperature.

Initial Pool Temperature The initial pool temperature of 95°F was used in the analysis. The 95°F is the Technical Specification limit for normal operation.

Feedwater Addition For conservatism the analysis includes all water in the feedwater system that can contribute to higher calculated pool temperatures. This was achieved by adding all feedwater in the feedwater system during normal operation that has a temperature greater than the maximum expected pool temperature. This translates to all feedwater through feedwater heaters nos. 3, 4, 5, and 6.

In addition, a conservative calculation of the energy in the feedwater piping is added to the RPV/containment system. This water mass and energy addition assures that the pool temperature calculation conservatively reflects the effect of feedwater temperature on suppression pool temperature.

6.2-22 REV 24 11/22

FERMI 2 UFSAR Initiation Time for Containment Cooling The plant emergency operating procedures require that containment cooling be started for any suppression pool temperature greater than 95°F (that is within the first few minutes of a DBA/LOCA). However, the UFSAR does not take credit for operator action for the first 10 minutes into the accident. Added conservatism is built into the analysis by assuming containment cooling is initiated at 20 minutes resulting in a higher pool temperature than will be obtained with the 10 minute initiation time. Also the RHR heat exchangers providing cooling to the suppression pool water are assumed to be fouled, adding more conservatism.

Decay Heat The decay heat based on the ANS 5.1 model (Reference 16) as described in Appendix B of Reference 17 has been used for the containment long-term analysis. This decay heat includes contributions due to fission heat induced by delayed neutrons, decay heat from fission products, decay heat from actinides (heavy elements), and decay heat from irradiated structural materials. For conservatism additional margin which corresponds to two standard deviations (10%) was added to the decay heat as described in Reference 17, Appendix B.

6.2.1.3.4 Intermediate Breaks Intermediate breaks were not reanalyzed for power uprate since they were not the limiting case. The analysis presented below is based on the original power of 3358 MWt (102 percent of 3293 MWt).

The failure of a recirculation line results in the most severe pressure loading on the drywell structure. However, as part of the containment performance evaluation, the consequences of intermediate breaks are also analyzed. This classification covers those breaks for which operation of the ECCS will occur during the blowdown and which result in reactor depressurization. These breaks can involve either reactor steam or liquid blowdown. This section describes the consequences to the containments of a 0.l-ft2 break below the RPV water level. This break area was chosen as being representative of the intermediate-break-area range. Figures 6.2-15 and 6.2-16 show the drywell and suppression chamber pressure and temperature response.

Following the 0.1-ft2 break, the drywell pressure increases at 0.5 psi/sec. This drywell pressure transient is sufficiently slow so that the dynamic effect of the water in the vents is negligible and the vents will clear when the drywell-to-suppression chamber differential pressure is equal to the vent submergence pressure. For this containment design, the distance between the pool surface and the bottom of the vents is 3 ft 4 in. maximum. Thus, the water level in the vent will reach this point when the drywell-to-suppression chamber pressure differential reaches 1.5 psi, i.e., approximately 3 sec after the 0.1-ft2 break occurs. At this time, air, steam, and water will start to flow from the drywell to the suppression pool; the steam will be condensed and the air will enter the suppression chamber free space. After 3 sec there will be a constant pressure differential between the drywell and the suppression chamber. The continual purging of drywell air to the suppression chamber will result in a gradual pressurization of the latter. By approximately 300 sec, all the drywell air will have been swept over to the suppression chamber and the pressure increase terminated. After this 6.2-23 REV 24 11/22

FERMI 2 UFSAR time, the drywell and wetwell pressures will remain relatively constant and all the steam being released to the drywell will be condensing in the pool. Some continuing containment pressurization will occur because of the continued pool heatup. The ECCS will be initiated by the 0.1-ft2 break via high drywell pressure and will provide emergency cooling of the core. The operation of these systems is such that the reactor will be depressurized in approximately 600 sec.

This will terminate the blowdown phases of the transient. The drywell will be at approximately 25 psig and the suppression chamber at approximately 23 psig.

In addition, the suppression pool temperature will be the same as from the recirculating line break because essentially the same amount of primary system energy would be released during the blowdown. After reactor depressurization, the flow through the break will condense the drywell steam and will eventually cause the drywell and suppression chamber pressures to equalize in the same manner as following a recirculation line rupture.

The subsequent long-term suppression pool and containment heatup transient that follows is essentially the same as for the recirculation break without containment spray.

From this description, it can be concluded that the consequences of an intermediate break are less severe than a recirculation line rupture over short time periods and essentially the same over a long time period.

Additionally, as discussed in Subsection 6.2.1.3.1, the containment response due to intermediate breaks has also been calculated using the bases provided in References 5 and 7.

The corresponding short term containment response is reported in Reference 6. These predicted results also support the above conclusions.

6.2.1.3.5 Small Breaks Small breaks were not reanalyzed for power uprate since they were not the limiting case.

The analysis presented below is based on the original power of 3358 Mwt (102 percent of 3293 MWt).

This subsection discusses the containment transient associated with small primary system blowdowns. The sizes of primary system blowdowns in this category are those blowdowns that will not result in reactor depressurization due either to loss of reactor fluid or automatic operation of the ECCS equipment. The underlying assumption is that, following the manifestation of a break of this size, the reactor operators will initiate an orderly shutdown and depressurization of the plant.

The thermodynamic process associated with the blowdown of primary system fluid is one of constant enthalpy. If the primary system break is below the water level, the blowdown flow will consist of reactor water. Upon depressurizing from reactor pressure to the drywell pressure, approximately one-third of this water will flash to steam and two-thirds will remain as liquid. Both phases will be at saturated conditions corresponding to the drywell pressure.

Thus, if the drywell is at atmospheric pressure, the steam and liquid associated with a liquid blowdown would be at 212°F. Similarly, if the containment is assumed to be at its maximum allowable pressure, the reactor liquid would blow down to approximately 309°F steam and water. If the primary system rupture is located so that the blowdown flow consists of reactor steam, the resultant steam temperature in the containment is significantly higher than the 6.2-24 REV 24 11/22

FERMI 2 UFSAR temperature associated with liquid blowdown. This is because a constant enthalpy decompression of high-pressure, saturated steam will result in a superheat condition. For example, decompression of 1000 psia steam to atmospheric pressure will result in 298°F superheated steam (86°F of superheat).

The conclusion is that a small reactor steam leak will impose the most severe temperature conditions on the drywell structures and the safety equipment in the drywell. The superheat temperature for large steam-only blowdowns would be the same as for small breaks, but the duration of the high temperature condition would be less. This is because the larger breaks will depressurize the reactor more rapidly than the orderly reactor shutdown that is assumed to terminate the small break.

For drywell design evaluation, the following sequence of events was assumed to occur. With the reactor and containment operating at the maximum normal conditions defined in Table 6.2-1, a small break occurs that allows blowdown of reactor steam to the drywell. The resulting pressure increase in the drywell will lead to a high-drywell-pressure signal that will scram the reactor and activate the containment isolation system. The drywell pressure will continue to increase at a rate dependent upon the size of the assumed steam leak. This pressure increase will depress the water level in the vents until the level reaches the bottom of the vents. At this time, air and steam will start to enter the suppression pool. The steam will be condensed and the air will pass to the suppression chamber free space. The latter will result in a gradual pressurization of the containment at a rate dependent upon the air carryover rate. Eventually, the entrainment of the drywell air in the steam flow through the vents will result in all the drywell air being carried over to the suppression chamber. At this time, pressurization of the containment will cease and the system will reach an equilibrium condition with the drywell pressure at 25 psig and the suppression chamber at approximately 23 psig. The drywell will be full of superheated steam. Continued blowdown of reactor steam will be condensed in the pool.

The reactor operators will be alerted to the incident by the high-drywell-pressure signal and the reactor scram. For the purposes of evaluating the duration of the superheat condition in the drywell, it is assumed that their response is to shut the reactor down in an orderly manner using the safety/relief valves, or main condenser, and limiting the reactor cooldown rate to 100°F per hour. This will result in the reactor primary system being depressurized within 6 hr. At this time, the blowdown flow to the drywell will cease and the superheat condition will be terminated. If the plant operators elect to cool down and depressurize the reactor primary system more rapidly than at 100°F per hour, then the drywell superheat condition will be shorter.

The temperature resulting from the blowdown is determined by finding the combination of primary system pressure and containment pressure that produces the maximum superheat temperature. These are 450 psia, 35 psig, and 340°F, respectively. This temperature is assumed to exist for the initial 3 hr of the blowdown.

Additionally, as described in Subsection 6.2.1.3.1, the containment response due to small breaks has also been calculated using the bases provided in References 5 and 7. The corresponding short-term response is reported in Reference 6. Assumed operator actions that will minimize cyclic loads on suppression chamber and vent system structures are discussed in Reference 9.

6.2-25 REV 24 11/22

FERMI 2 UFSAR 6.2.1.3.6 Steam Bypass The Fermi 2 containment has been examined to determine what leakage between the drywell and suppression chamber can be tolerated as a function of primary system break area; i.e.,

what leakage will result in a peak pressure equal to the maximum allowable pressure for the system. For this calculation, the following assumptions were made:

a. Flow through the postulated leakage path is pure steam. For a given leakage path, postulating that the leakage flow consisted of a mixture of liquid and vapor would increase the total leakage mass flow rate but would decrease the steam flow rate. Since it is the steam entering the suppression chamber free space that is resulting in the containment pressurization, this is a conservative assumption

b. There is no condensation of the leakage flow on either the suppression pool surface or the torus and vent system structures. Since any condensation results in less steam being in the suppression chamber free space, this is a conservative assumption. In practice, there would be condensation, especially for the larger primary system breaks when there will be vigorous agitation at the pool surface during blowdown.

Leakage capacity is expressed in terms of A, the area of the leakage flow path, and K, the geometric loss coefficient. These terms are interrelated such that the allowable leakage capacity for a system is expressed in units of A / K .

The calculation shows that the limiting leakage capacity occurs for a primary system break area of 0.4 ft2. For this break area, the allowable leakage capacity is 0.147. Typically, the geometric loss factor K would be three or greater; thus, the maximum allowable leakage area would be about 0.25 ft2. This corresponds to a 7-in. line.

Primary system breaks greater than about 0.4 ft2 will result in rapid system depressurization, and, for the given primary allowable leakage area, would result in the containment pressure being less than the maximum allowable pressure at the end of the reactor blowdown period.

Primary system breaks less than about 0.4 ft2 will not result in rapid primary system depressurization and some operator action is required to terminate the pressure rise in the containment. The operators have several options available to them. If the source of the leakage is undefined, they would probably depressurize the primary system via either the main condenser or relief valves, or they could activate the suppression chamber or drywell sprays.

6.2.1.3.7 Small-Break Temperature Consideration The Fermi 2 containment vessel was designed in accordance with the ASME B&PV Code Section III, Nuclear Vessels (1968), including the Summer 1969 Addenda. The primary containment design parameters, as shown in Part I of Table 6.2-1, were chosen on the basis of conditions discussed in the Fermi 2 PSAR. The design-basis conditions have since changed, as discussed in Subsection 6.2.1.3.2. However, no change in design pressure was necessary.

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FERMI 2 UFSAR A small steam leak inside the primary containment, followed by an orderly shutdown and RPV depressurization, presents a different drywell atmosphere temperature transient. This situation is discussed in Subsection 6.2.1.3.5. The drywell temperature is calculated to be 340°F for 3 hr, and 320°F for 6 hr. During this period the calculated maximum drywell pressure is 35 psig, and during the following 24-hr period the temperature is 250°F with a pressure maximum of 25 psig. The containment vendor has analyzed the containment capability and found it adequate for these conditions.

6.2.1.3.8 Line Breaks in Sacrificial Shield Annulus 6.2.1.3.8.1 Description of System Configuration The sacrificial shield is approximately 49-ft high cylindrical shell, with a 25 ft 7 in. inside diameter, a 29 ft 1 in. outside diameter, and a thickness of 1 ft 9 1/4 in. It has steel liners on its exterior and interior surfaces, and is meridionally stiffened by 12 vertical steel columns.

The steel liner plates are welded to the columns, and the annular space between these plates is filled with concrete. The wall is rigidly attached to the reactor support at the bottom and attached to the drywell and RPV at the top by means of stiff leg supports and snubbers, respectively. The RPV sits inside the sacrificial shield with annular clearance of approximately 18 in. Of this 18 in., approximately 3 in. is occupied by insulation and 3 in.

by a ventilation space between the shield and the insulation. This leaves a 12-in. annular space between the insulation and the RPV.

A detailed description of the sacrificial shield is given in Subsections 3.8.3.1.1 and 3.8.3.3.1.

Openings are provided in the shield for the passage of lines from the RPV to the drywell.

Those openings which lie within an area 9 ft above and 16 ft below the centerline of the core are required to be shielded and are equipped with shielding doors; these doors are locked closed and will not open during a pipe break within the annulus. The openings above and below this band have no shielding requirements; they are covered with a light-weight rupture diaphragm designed to help relieve the annulus pressure should a break occur.

The nozzles of the RPV are connected to the main piping using a short transition piece called a safe-end. The postulated break is the weld at either end of the safe-end. There are 26 penetrations in the wall, of which 17 occur where shield doors are required. Of these 17 lines, the major ones are the two 28-in. diameter recirculation outlet lines and the ten 12-in.

recirculation inlet lines. The safe-end welds for these nozzles lie within the thickness of the shield wall or in the annular space. These two sets of lines were considered the critical cases, because the rest of the lines either are smaller, or may vent directly to the drywell because of the absence of any shield doors. One more case was considered: the feedwater line safe- end break. Because this line is located at the top of the sacrificial shield, forces generated during a postulated line break have a large moment which can lead to high stresses. The analysis requires modeling the system to predict what forces and pressures are generated following a postulated failure of safe- ends from these three lines and then using these in a structural design assessment.

Subsection 3.9.1.5 presents the GE analysis of the loads on the reactor vessel and internals due to a line break in the sacrificial shield annulus. Part of that work also includes computation of forces and moments for the RPV pedestal, RPV anchor bolts, and stabilizer 6.2-27 REV 24 11/22

FERMI 2 UFSAR truss. For these components, Sargent & Lundy used the larger of the stresses computed from their analysis or the GE analysis. This procedure has been incorporated in Revision 2 to SL-3647, dated March 14, 1980 (Reference 18).

The conclusion of Reference 18 states that the existing design of the sacrificial shield, reactor pedestal, stabilizer truss, RPV, and shield anchor bolts can safely accommodate the effects of annulus pressurization resulting from a postulated safe-end break.

6.2.1.3.8.2 Summary of Study A study was performed in 1973 using state-of-the-art methods. A detailed report of that study was filed with the AEC in response to Open Item No. 12 and Question 12.4, Amendment 11 of the PSAR (Refer to Reference 15 in Section 3.8). During the review of the original FSAR, the NRC questioned whether certain aspects of the model used to predict the pressure distribution were adequately conservative and requested that the calculation be repeated using models currently available.

The recalculation was broken down into three tasks: calculation of mass energy release, calculation of annulus pressure distribution history, and the structural design assessment.

Mass Energy Release This task was performed using a method developed by GE. The method assumes that the initial fluid velocity is zero. After the break, a finite time is required to accelerate the fluid to steady-state velocities; this is called the inventory period. The flow rate during this period is computed by two methods; one includes the effect of inventory and subcooling on flow in the pipe, the other accounts for the finite break opening time. The smaller of the two flow rates at any time is used. Both methods produce maximum flow rates based on different limiting areas. The transfer from one curve to the other represents a change in the point where the flow is choked. Following the inventory period, the flow is assumed to be choked at the limiting cross-sectional flow area. Mass flux is calculated using the Moody steady-slip flow model with subcooling. Results of this calculation are in Reference 20.

Annulus Pressurization The computation of pressure distribution in the annulus following these breaks was based on the use of the computer code COMPARE. The model for Fermi 2 used 42 nodes in the annulus and four nodes in the drywell. The analysis considered movement of insulation at penetrations and the resulting venting of fluid to the drywell. The code was modified to account for variable junction area as a function of time. A Moody multiplier of 0.6 was used for all junctions except that from the break to the annulus, where 1.0 was used. All junctions had an inertia term, and sub-critical flow was calculated on the basis of a solution to the momentum equation with constant density. Reference 20 is the report of this work.

Structural Design Assessment The structure was analyzed using the Sargent & Lundy thin-shell- of-revolution computer code, DYMAX. The Fermi 2 model for this study consisted of 76 nodes. Reference 18 is the report of this work.

The loads included in the study were:

a. Annulus pressurization 6.2-28 REV 24 11/22

FERMI 2 UFSAR

b. Jet impingement

c. Pipe-whip reaction

d. Dead load

e. Thermal effect due to accident

f. Seismic effect due to operating-basis earthquake (OBE) and safe-shutdown earthquake (SSE).

The structural components assessed were:

a. Sacrificial shield

b. Reactor pedestal

c. Stabilizer truss

d. Reactor anchor bolts

e. Sacrificial shield anchor bolts.

6.2.1.4 Inspection and Testing 6.2.1.4.1 Primary Containment The Fermi 2 containment has been designed and constructed as a Class B vessel in compliance with Section III of the ASME Code, 1968 Edition, including the Summer 1969 Addenda. The containment vent system and suppression shell, supports, internals, and attachments have also been reevaluated (References 9 and 10) to include the hydrodynamic loading events and analysis methods defined by GE Topical Report NEDO-21888 (Mark I Containment Program Load Definition Report) and the NRC Safety Evaluation Report, NUREG-0661. The appropriate edition of Section III of the ASME Code and service-level limits specified in NUREG-0661 have been applied in the reevaluation. All inspections and tests prescribed by these editions of the Code have been successfully completed.

Containment boundary integrity has been verified during the construction of the Fermi 2 plant using the reference-vessel method. This method involves measuring the pressure differential between the containment vessel and a reference system of copper vessels that are interconnected with copper tubing and located in the upper and lower portions of the drywell and in the suppression chamber. This initial test, begun March 3, 1973, was performed in accordance with 10 CFR 50, Appendix J, and ANSI N45.4-1972, "Leakage Rate Testing of Containment Structures for Nuclear Reactors." The leak rate was determined to be 0.079

+/-0.035 percent per 24 hr at 56 psig.

A preoperational, integrated leak-rate test using the absolute method was performed at the peak containment pressure calculated from DBA considerations in accordance with 10 CFR 50, Appendix J. This integrated leak-rate test was a Type A test. The test was conducted over a minimum of 8 hr with at least 20 value data points.

Type A tests will be performed periodically throughout the life of the plant in accordance with Fermi 2 Technical Specifications.

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FERMI 2 UFSAR Permanently installed piping penetrations are provided through the containment structure for both the compressor system and the pressure-indication piping required for the Type A tests.

An electrical penetration is provided for the leads to the temperature instrumentation in the containment.

Containment atmosphere-circulation fans are operable during the elevated-pressure conditions of the Type A tests to minimize local variations in temperature and humidity.

Personnel entry into the containment is not required during the Type A tests. Therefore, no provisions have been made for this kind of activity.

6.2.1.4.1.1 Penetrations Airlock doors, access hatches, and the drywell head are equipped with double seals and instrument taps which permit pressurization of the space between them to verify seal integrity.

Piping penetrations with bellows seals which allow relative movement between pipe and containment wall are provided with double bellows and a space between them which can be pressurized. These penetrations are equipped with test fittings necessary to facilitate pressurization and testing of the penetration boundaries without pressurizing the entire containment.

Electrical penetrations are equipped with double seals and test connections and are capable of being tested at containment design pressure without pressurization of the containment.

6.2.1.4.1.2 Isolation Valves Tests will be performed on isolation valves including reactor-building-to-torus vacuum breakers to verify their operability, pressure boundary integrity, and seat-and-stem leaktightness. Design provisions have been made when possible to accommodate the specific leak-test requirements of 10 CFR 50, Appendix J, Type C tests. Alternative methods are used where necessary and technically justifiable. The alternative methods are identified and discussed in Table 6.2-2.

Edison performed opening force tests on the Fermi 2 vacuum breakers during preoperational testing and will include these tests in the inservice testing. With the valve air cylinder properly adjusted using a predetermined air pressure, the pallet will close smoothly, without banging, in 2 to 5 sec. The closing time of the pallet is measured and set as part of the normal valve inspection and adjustment during refueling. This testing, along with the opening force measurement, provides assurance that the pallet is not binding and the valve will open with the proper opening time.

6.2.1.4.1.3 Pressure Suppression System Drywell-to-suppression-chamber gross-leak tests will be conducted periodically as defined in the Technical Specifications to ensure that bypass of the pressure suppression feature of the containment has not developed. The test will be based on determination of the rate of change of pressure in the suppression chamber and drywell at a drywell-to-suppression-chamber differential pressure of 1 psi. In addition, individual drywell-to-torus vacuum breakers will 6.2-30 REV 24 11/22

FERMI 2 UFSAR be inspected and their position-switch setting will be verified. During plant operation, these valves will be periodically exercised to verify the operability of the valve and the closed-position instrumentation. These tests are documented in the Technical Specifications.

6.2.1.4.1.4 Test Frequencies Test frequencies for the Type A test will be in accordance with Fermi 2 Technical Specifications. Type B and C test frequencies are based on the requirements of 10 CFR 50, Appendix J, Option B.

Data, data reduction, and test acceptability requirements for all tests are described in ANSI/ANS 56.8-2002 or other alternative testing methods that have been approved by the NRC and are based on the requirements of 10 CFR 50, Appendix J, Option B.

If the result of any test indicates that leakage exceeds the limits established in the Technical Specifications, repairs shall be made and a retest performed. In addition, for unsuccessful Type A tests, the provisions of 10 CFR 50, Appendix J, Option B, shall apply.

6.2.1.4.2 Secondary Containment The reactor building leakage rate may be tested by complete isolation of the building except for the effluent from the SGTS. The SGTS is placed in operation and the system will maintain a constant flow. The building inleakage is small enough to ensure that the building negative pressure exceeds the value required by the Technical Specifications. The rate at which air is exhausted through the system is an accurate measure of building inleakage.

Visual inspection of reactor building penetrations will be possible. Penetration leakage is determined as a part of the gross reactor building inleakage as discussed above.

Frequency of these tests and inspections as defined in the Technical Specifications is based upon expected lifetime of the various seals, components, and penetrations and anticipated failure modes. The test and inspection schedule is intended to ensure that gross failures do not occur and that such failures, should they occur, are discovered and corrected within a reasonable time.

6.2.1.5 Instrumentation 6.2.1.5.1 Primary Containment The primary containment monitoring system is designed to make available to the plant operators sufficient information to permit normal operation, to assist the operator in assessing the consequences of an accident or an incident, and to determine the effectiveness of control actions taken to mitigate the effects of the postulated event.

Functions of the primary containment monitoring system include multipoint measurement and recording of hydrogen and oxygen concentrations, gaseous radiation levels, pressure, temperatures, and water levels in the drywell and pressure suppression chamber. Suppression chamber water temperatures and drywell vessel wall and atmospheric temperatures are also measured and recorded. This system provides information for operator control of 6.2-31 REV 24 11/22

FERMI 2 UFSAR suppression pool cooling. Details of the primary containment monitoring system, its subsystems, sensors, and logic are described in Subsections 7.1.2 and 7.6.1.

Radiation monitors and pressure transmitters and the logic associated with the initiation of primary containment isolation as well as actuation of the ECCS and other engineered safety feature (ESF) systems are described in Subsections 7.1.2 and 7.3.2. The primary containment high-range radiation monitors are discussed in Subsection 11.4.3.

6.2.1.5.2 Secondary Containment Secondary containment pressure is normally controlled by the reactor/auxiliary building ventilation system. Pressure sensors outside the building are arranged so that the lowest pressure on the building (due to wind) is compared with the building internal pressure which is maintained at 0.25 in. of water below the lowest outside pressure. The building fans are shut down in the event that a differential pressure of approximately +/-2 in. occurs. Time-delay relays prevent spurious shutdown of the ventilation system caused by wind gusts.

The secondary containment is isolated on the same signals that actuate the SGTS; i.e., high drywell pressure, level 2 low reactor water level, reactor building ventilation exhaust radioactivity high, fuel pool area ventilation exhaust radioactivity high, or a manual pushbutton in the control room.

The SGTS is also actuated, and the secondary containment isolated, upon Loss of Offsite Power (LOOP). A LOOP causes a failure of the radiation monitors located in the reactor building ventilation exhaust system and in the fuel pool ventilation exhaust system which initiates a downscale trip signal. The radiation monitors downscale trip signal isolates the reactor building ventilation (RBHVAC) exhaust system and initiates the SGTS system.

The systems whose signals initiate secondary containment isolation are discussed in Subsections 7.3.2 and 7.6.1.

6.2.1.6 Materials Organic materials used in the Fermi 2 primary and secondary containments have been selected for extended life during normal operation and for resistance to expected accident environmental conditions. Thermal insulations used are inorganic and are not sensitive to high radiation fields, steam, or high temperature.

Table 6.2-8 lists the type of protective coatings used, their thicknesses, and their locations within the primary and secondary containments.

Table 6.2-9 lists organic materials used for wiring insulation in the primary and secondary containments.

Table 6.2-10 lists other organic materials of significant quantity and the amounts used in the primary and secondary containments.

Evaluations of these materials have been made. It has been determined that they will satisfactorily endure accident environmental conditions and that their expected products of decomposition, if any, will not adversely affect the operability of any ESF system.

6.2-32 REV 24 11/22

FERMI 2 UFSAR The following paragraphs describe the coatings and paint used within the primary containment, including pertinent information regarding the following:

a. Identification of material used, location, and function

b. Physical and chemical characteristics

c. Performance under accident conditions including washdown, radiation, steam, temperature, and jet impingement effects

d. Data on effect of any coating material that may be dissolved or carried by the fluids that flow in the spray systems of the ECCS that may affect the functioning of the systems

e. Effect of coating on core and heat exchanger heat-transfer surfaces

f. Clogging and other effects on fluid flows in Class 1 systems from coatings.

Additional information is available in Reference 21.

Reactor Vessel Support Pedestal The inside and outside surfaces of the reactor vessel support pedestal are coated with Ameron Nu-klad surfacer 110 AA primer and one finish coat of Ameron polyamide epoxy 66.

Damaged areas of Ameron Nu-klad 110 AA are repaired with Ameron Nu-klad 111. The function of this coating system is to protect and seal the pedestal surfaces against attack by either demineralized (aggressive) water or radiation contamination and to facilitate washdown.

The physical and chemical characteristics of the Ameron Nu-klad surfacer 110 AA primer are excellent adhesion to clean concrete and good adhesion to steel, resistance to attack by demineralized water or hot condensate, excellent abrasion resistance, considerable radiation resistance, excellent chemical resistance, and indefinite repairability. Both primer and finish are modified epoxy. Ameron polyamide epoxy 66 has properties similar to those of the primer. Both coatings withstand temperatures to 200°F continuously and to 300°F intermittently.

Required DBA testing has been performed, and the coating system is capable of withstanding the rigors of a LOCA. A washdown removes contamination.

The coating effect on the core and heat-transfer surfaces is negligible because the coating system is nonleachable.

No clogging or other effects on fluid flow in Class 1 systems are expected since the coating is nonleachable and has excellent adhesion.

The Ameron 66 top coat has been applied in accordance with the recommendations of Regulatory Guide 1.54 and ANSI N101.4 and the coating system has met the pull-test requirements of ANSI N5.12. The coating of the reactor vessel support pedestal and other concrete surfaces of the drywell have been designated as a QA Level 1, safety-related activity. The coating system as described above is a qualified coating.

6.2-33 REV 24 11/22

FERMI 2 UFSAR Drywell Concrete Floors and Walls The concrete surfaces of the drywell floors and walls are coated with Ameron Nu-klad surfacer 110 AA primer and a top coat of Ameron polyamide epoxy 66. The function, physical and chemical characteristics, and other properties of this coating are discussed under "Reactor Vessel Support Pedestal" above.

Sacrificial Shield Wall The exterior surface of the sacrificial shield is coated with Carboline Carbozinc 11 and repaired with Carboline Carbozinc 11 SG. This is a self-curing, zinc-filled, inorganic, two-part basic zinc silicate complex that readily accepts top coats. The function of this coating is to provide long-term protection against corrosion, attack by radiation or radioactive water, and to facilitate washdown.

The physical characteristics are a hard surface resistant to aggressive water, very good impact resistance, and a temperature use range up to 750°F continuous and 800°F intermittent.

Flexibility is fair. Chemical characteristics are insolubility in water and resistance to aggressive water and solvents. Relatively wide application temperatures (0-200°F) and humidity ranges (to 95 percent) are permissible.

Contaminants on the coated surface can be easily washed down with water. The coating has high radiation resistance, resists steam to 180°F, and has excellent temperature resistance up to 750°F.

The coating has no effect on core heat transfer or heat exchanger heat-transfer surfaces since it is not soluble.

Carbozinc 11 and Carbozinc 11 SG coatings have been subjected to extensive DBA testing for a variety of application techniques and were found acceptable for use in BWR environments under LOCA conditions.

Report DECO 12 2191 notes that some particle separation could occur under accident conditions in areas subjected to continuous scouring by water and steam spray. Such scouring would occur only in the immediate vicinity of a pipe break. In such areas, the coating is not lost in large flakes, however, but rather in particles less than 20 microns in size. ECCS suction strainer head loss calculations include the recommended Utility Resolution Guidance (NEDO-32686) for qualified paint assumed to degrade from a direct steam jet impingement.

Most of the initial Carbozinc 11 coatings in the primary containment were applied in accordance with the original 1969 specification, prior to the issuance of Regulatory Guide 1.54 and ANSI N101.4. The industry standard at that time was to apply Carbozinc 11 in accordance with the manufacturer's recommendations. This type of coating has been successfully used in operating BWRs and for years has withstood a variety of adverse conditions.

In 1984, the commercial name of the Carbozinc 11 coating was changed to Carbozinc 11 SG.

Consequently, in cases where repairs to the original Carbozinc 11 coating were needed after 1984, Carbozinc 11 SG was used.

6.2-34 REV 24 11/22

FERMI 2 UFSAR Drywell Interior Steel All exposed interior surfaces of the drywell pressure boundary, including the drywell jet deflectors and surfaces in contact with concrete, are coated with Carboline Carbozinc 11 and repaired with Carbozinc 11 SG. The function of this coating system is to protect the surfaces from corrosion, from attack by aggressive water, radioactive water, or radiation, and to facilitate washdown.

Those coatings which cover the drywell pressure boundary are maintained under Fermi 2 QA Level I criteria to ensure long-term corrosion protection for the pressure boundary. This coating is not considered to be in full compliance with ANSI N101.4.

Drywell Interior Structural Steel The primary structural steel within the drywell is coated with Carboline Carbozinc 11 and repaired with Carboline Carbozinc 11 SG. The purpose of the coating is to provide long-term protection against corrosion and to facilitate washdown.

The Drywell dado region was recoated with Carboline Carboguard 890 N, and is classified as an acceptable coating (as defined in ASTM D4538).

Substantial modifications were made to the primary structural members in two separate phases due to load reevaluations that resulted in varying degrees of surface preparation.

Welding and nondestructive examination procedures necessitated removing existing coatings at tie-ins and welded connections. Due to completed installation of equipment, generally very tight working quarters, and complex components placement, sandblasting and recoating of steel members were not routinely completed.

Surfaces of Suppression Chamber The interior surfaces of the suppression chamber, including the exterior surfaces of the downcomers and vent header, the exterior surfaces of the vent pipes, vent header supports, ring girders, catwalks, monorail, stiffeners, supporting steel, piping, hangers, and penetration nozzles, are coated with the Wisconsin Protective Coating Plasite 7155 system above elevation 558-2 and with the Carboline Carboguard 6250 N system below elevation 558-

2. The Carboguard coating overlaps the Plasite coating at the intersection of the coatings.

The interior surface of the downcomers is coated with Plasite 7155. The Plasite coating is a water-resistant phenolic coating cross-linked with epoxy resin and polymerized with an alkaline curing agent. The Carboguard coating is a solventless epoxy novolac coating designed to handle exposures inside nuclear containment facilities. The function of these coatings is to provide long-term protection from corrosion and radiation, and to facilitate washdown.

These coatings resist temperatures up to 400°F intermittently, develop good hardness and abrasion resistance, can withstand cyclic thermal shock, and provide a broad range of long-term chemical resistance.

The Plasite coating was applied in accordance with Regulatory Guide 1.54, ANSI N101.4, meets pull-test requirements of ANSI N5.12, Section 6.4, has been DBA tested, and is considered a fully qualified coating capable of withstanding accident conditions. Its application is a safety-related, QA Level 1 activity.

6.2-35 REV 24 11/22

FERMI 2 UFSAR The Carboguard tie-in band that overlaps the Plasite coating is considered unqualified. There are additional minor areas in the wetwell with unqualified Carboguard coating. The unqualified coatings are tracked as indicated in Table 6.2-8. The unqualified coating amounts have been evaluated and are within established limits for unqualified coatings inside containment. The remainder of the Carboguard 6250 N coating is in accordance with Regulatory Guide 1.54 and ANSI N101.4 except that later ASTM standards endorsed by Revision 2 of Regulatory Guide 1.54 were used for test panel preparation, radiation qualification testing, chemical resistance qualification testing, and test panel evaluation. The coating, except for the tie-in band, is considered a fully qualified coating capable of withstanding accident conditions. Its application is a safety-related, QA Level 1 activity.

The interior surface of the vents from the drywell shell down to a transition point approximately 20 in. from the vent header is coated with Carboline Carbozinc 11 SG coating system. The remainder of the interior surface of the vents (from the transition point to the vent header) and the interior of the vent header are coated with a qualified Carboline Carboguard 6250 N coating system. A small qualified overlap band of Carboguard 6250 N over Carbozinc 11 SG exists at the transition point between the two coating systems. The interior surface of the vacuum breaker extensions and downcomers are coated with Plasite 7155 coating system described above in this section. The Carboline Carboguard 6250 N coating overlaps the Plasite 7155 coating on the inside surface of each downcomer and vacuum breaker penetration in the vent header. The Carboguard 6250 N coating in this overlap band is classified as an acceptable coating (as defined in ASTM D4538).

Touch-up repairs to the suppression chamber interior coating under submerged or dry conditions are made using compatible safety-related coatings complying with the original requirements and standards.

Miscellaneous Coatings Coatings on miscellaneous equipment and components in the drywell are discussed below.

These coatings were included in the evaluation of the Fermi 2 primary containment coatings, and will not impair plant operation under normal or abnormal conditions.

a. Galvanized Surfaces The drywell cooling system ducting and dampers are completely galvanized without any further coatings. At welded joints, the galvanized surface was ground off to clean metal, and in some locations these ground areas were touched up with Galvanox I or Galvanox V, zinc-rich coatings similar in properties to Carboline Carbozinc 11. In addition, all electrical conduit, terminal boxes, cable trays, and supporting unistruts are galvanized. The only exceptions are some large flexible conduits made of stainless steel

b. Hangers and Supports Hanger and support components, including clamps, rods, spring cans, snubber attachments, pipe-whip restraint components, and secondary support steel, were originally coated with Carboline Carbozinc 11. Significant changes in the hanger and support design resulted in addition of secondary support steel, change-out of hanger components, and welding of attachments. Coating repair and touch-up of these areas is not safety related 6.2-36 REV 24 11/22

FERMI 2 UFSAR

c. Piping Most of the piping within the drywell is insulated with reflective metallic insulation panels (Mirror Insulation), consisting of removable sections and having an outer cover of stainless steel. Encapsulated NUKON or encapsulated silicon (Min-K) is used where clearance restrictions exist, i.e., drywell penetrations and spaces between pipe whip restraints and pipe. Normally, cold fluid system piping is not insulated or coated. The uninsulated carbon steel piping was shop coated with a protective varnish. Tight mill scale and some rust is apparent on the piping surfaces. The varnish and mill scale are considered unqualified coatings

d. Unidentified and Unqualified Coatings These coatings consist largely of manufacturer's shop coatings and primers such as red lead, aluminum base, enamels, polymer, and phenolic paints. These coatings are present on valve bodies, yokes and bonnets, motor and air operators, handwheels, electric motors, etc. Another category of unqualified coatings consists of identification marking and banding of electrical conduit, terminal boxes, and trays.

Coatings of this category that have thicknesses of 3 mils or less are postulated to fail in small particles and will not clog strainers.

Unqualified coatings greater than 3 mils DFT have either been removed, and the surfaces have been recoated with Carbozinc 11 where appropriate (see Reference 21 for additional information); or have been evaluated for use in the primary containment. Design calculations have been prepared to evaluate the addition of materials to the primary containment. These are updated as necessary as part of the plants response to NRC Generic Letter 98-04.

6.2.2 Primary Containment Heat Removal System 6.2.2.1 Design Bases Containment heat removal is provided by operating the RHR system in the suppression pool cooling mode or the containment spray mode. The system meets the following safety design bases:

a. The source of coolant inventory shall be located within the containment so as to establish a closed cooling water path

b. A closed-loop flow path between the suppression pool and the RHR heat exchangers shall be established so that the heat-removal capability of these heat exchangers can be utilized

c. This system, in conjunction with other ESF systems, shall have diversity and redundancy such that no single failure can result in its inability to cool the containment adequately

d. Each active component shall be testable during operation of the nuclear system.

Testing is described in Section 5.5.7.5.

6.2-37 REV 24 11/22

FERMI 2 UFSAR 6.2.2.2 System Design The containment cooling subsystem is an integral part of the RHR system, as described in Subsection 5.5.7. Redundancy is achieved by having two complete containment cooling systems.

Consideration of the fouling of heat exchangers and the selection of temperatures for heat exchanger design is discussed in Subsection 5.5.7.

6.2.2.3 Design Evaluation The discussion in this subsection has been updated for power uprate conditions.

In the event of the postulated LOCA, the short-term energy release from the reactor primary system will be dumped to the suppression pool. Subsequent to the accident, fission product decay heat will result in a continuing energy dump to the pool. Unless this energy is removed from the containment system, it will eventually result in unacceptable suppression pool temperatures and containment pressures. The containment cooling mode of the RHR system is used to remove heat from the suppression pool, the suppression chamber, and the drywell.

When the RHR system is in the containment cooling mode, the pumps draw water from the suppression pool, pass it through the RHR heat exchangers, and inject it back into the suppression pool or into the containment via sprays.

The adequacy of the RHR system has been evaluated considering, two sequences of events with different assumed single active failures. Both scenarios assume the occurrence of a LOCA coincident with a loss of offsite power with the reactor initially at maximum power.

The original licensing and design basis scenario assumes a loss of offsite power occurs and the single failure of one divisional power supply for the duration of the accident.

Immediately following the accident, the ECCS initiates automatically as designed in response to the accident initiation signals.

Under the original scenario, due to the assumed loss of offsite power and one division of onsite power, two core spray pumps and two RHR pumps will be operating. (Section 6.3 describes the ECCS equipment.) Twenty minutes later the plant operators activate one RHR heat exchanger in order to start containment heat removal. This involves shutting down one of the two LPCI pumps and starting up the service water pumps for the heat exchanger.

Once containment cooling has been established (including RHR cooling towers), no further operator actions are required.

Subsequent to the original plant analysis it was determined that a single failure of an RHRSW isolation valve to open would result in the same available suppression pool cooling capability (namely one RHR heat exchanger) but would result in additional operating ECCS pumps - four RHR pumps and four core spray pumps; thus, resulting in additional ECCS pump heat to the suppression pool. Consistent with the original containment analysis, this scenario assumes plant operators activate the remaining operable RHR heat exchanger and the associated division of the Ultimate Heat Sink [See Section 9.2.5] twenty minutes after the initiating event.

6.2-38 REV 24 11/22

FERMI 2 UFSAR The evaluations of both scenarios use the SUPERHEX (SHEX) code to calculate the long-term containment response for Fermi 2 with power uprate (Reference 22). SUPERHEX evolved from two previously approved codes (Reference 14 and 15) and was shown to give equivalent pool temperature response to the predecessor code. The long-term analysis for Fermi 2 with the SUPERHEX computer code using conservative inputs yields a peak post DBA/LOCA pool temperature of 196.5°F. This temperature shows margin remains to the controlling limit of 198°F which comes from NPSH requirement for pumps taking suction from the suppression pool with no credit for containment pressure per Regulatory Guide 1.1.

The input parameters used for SUPERHEX for the long-term containment response analyses for Fermi 2 with power uprate are identified in Table 6.2-1.

Service Water Temperature The original containment analysis used a constant RHR service water (RHRSW) temperature of 90°F which is the maximum design cooling tower outlet temperature. The Technical Specifications prohibit operation with the cooling tower reservoir temperature above 80°F.

An energy balance calculation was used to determine the post LOCA RHRSW temperature increase as a function of time from the initial condition of 80°F to the cooling tower maximum design temperature of 90°F. The temperature profile, which is non-linear, was conservatively bounded by a linear profile which was used in the containment analysis (Table 6.2-1). The following are the important assumptions used in the energy balance.

(Note: The current maximum analyzed service water supply temperature is below the assumed maximum 90°F).

a. The maximum Technical Specification reservoir temperature of 80°F was used as an initial condition.

b. The maximum design cooling tower outlet temperature of 90°F was used.

c. The minimum Technical Specification RHR reservoir water level was used.

This is conservative because it minimizes the heat capacity of the reservoir and maximizes the reservoir heatup.

d. Evaporative and drift losses were used to reduce reservoir inventory during the heatup period.

e. Complete mixing was assumed in the reservoir. This is conservative because hot water is discharged into the cooling towers and is sprayed down to the surface of the reservoir. Cooler water is drawn from the bottom of the reservoir where the pump suctions are located. No credit was taken for temperature stratification which would have lowered the reservoir discharge temperature profile.

Suppression Pool Volume The initial suppression pool volume used for the power uprate long-term containment analysis was 117,161 ft3 which is less than the pool volume of 121,080 ft3 that corresponds to the Technical Specification minimum value. The lower pool volume of 117,161 ft3 adds conservatism to the calculated pool temperature since a lower initial pool volume results in higher calculated values for pool temperature.

6.2-39 REV 24 11/22

FERMI 2 UFSAR Initial Pool Temperature The initial pool temperature for the containment analysis was set at 95°F which is the Technical Specification limit for normal operation.

Feedwater Addition All water in the feedwater system which could contribute to higher calculated pool temperatures was added to the RPV and containment system for the power uprate analysis.

This was achieved by adding all feedwater which is in the feedwater system during normal operation that has a temperature greater than the maximum expected pool temperature. This translates to all feedwater through Feedwater Heaters Nos. 3, 4, 5, and 6.

In addition, a conservative calculation of the energy in the feedwater piping is added to the RPV/containment system. This water mass and energy addition assures that the pool temperature calculation conservatively reflects the effect of feedwater addition on suppression pool temperature.

Initiation Time for Containment Cooling The long-term containment response analysis has assumed that the containment cooling is initiated at twenty minutes.

Decay Heat The original analysis identified decay heat values used for the long-term containment analysis which correspond to the May-Witt decay heat model values after 60 seconds. For the power uprate analysis a more realistic decay heat has been included. This decay heat is based on the ANS 5.1 model (Reference 16) and is described in Appendix B of Reference 17.

This decay heat includes contributions due to fission heat induced by delayed neutrons, decay heat from fission products, decay heat from actinides (heavy elements), and decay heat from irradiated structural materials. For conservatism additional margin which corresponds to two standard deviations (10%) was added on the decay heat as described in Reference 17, Appendix B, for the Fermi 2 long-term containment power uprate analysis.

Suppression Pool Temperature Response The suppression pool temperature response has also been evaluated following several other plant transient events in which steam is discharged to the suppression pool. General Electric Report NEDC-24388-P (Reference 23) describes transient events, the assumed RHR system modes of operation, and the predicted pool temperature results. The report concludes that the peak pool temperatures in the vicinity of SRV discharge quencher devices are below the limit established to ensure stable steam condensation.

6.2.2.4 Testing and Inspections The preoperational and operational testing and the periodic inspection of components of the containment heat removal system are described in Subsection 5.5.7.5.

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FERMI 2 UFSAR 6.2.2.5 Instrumentation Requirements The containment spray and the suppression pool cooling modes of the RHR system are manually initiated. Once initiated, containment cooling performance is monitored by monitoring pump performance, flow and pressure, and coolant temperature.

6.2.2.6 Materials Materials used are reviewed and evaluated with regard to radiolytic and pyrolytic decomposition and attendant effects on safe operation of the system. For example, fluorocarbon plastic (Teflon) is not permitted in environments that attain temperatures greater than 300°F, or radiation exposures above l04 rads. Only inorganic thermal insulation, which does not decompose due to radiation or temperature, is used in these environments.

An inorganic zinc primer is used on all exterior surfaces of carbon steel components that are treated. All paints used are suitable for the temperature conditions expected.

6.2.3 Secondary Containment Air Purification and Cleanup System The SGTS is designed to minimize the release-related offsite dose rates by permitting the venting and purging of both the primary and the secondary containment atmospheres under accident or abnormal conditions, and at the same time containing any airborne particulate or halogen contamination that might be present.

6.2.3.1 Design Bases Under postaccident conditions, it is possible that the primary containment atmosphere could become contaminated with radioactive particulates and halogens. Any air from this volume finding its way to the secondary containment is therefore likely to be similarly contaminated.

The SGTS is designed to permit controlled ventilation of this area by maintaining it under slightly negative pressure with respect to the outside atmosphere to ensure that any air leaving is filtered to remove particulates and halogens. The system is also capable of filtering gases exhausted from the primary containment and the HPCI barometric condenser.

The system is designed to function under postaccident conditions of high radiation levels, temperatures, and relative humidity.

The SGTS flow rate is sufficient to provide a secondary containment air volume change at least once per day and to maintain the reactor building at approximately negative 1/4-in.

water pressure for accident and abnormal conditions.

Particulate- and halogen-removal capability permits venting of the primary and secondary containment volumes following an accident while maintaining offsite dose rates well within the guidelines set by 10 CFR 100. For those design basis accidents reanalyzed per Regulatory Guide 1.183, SGTS limits offsite dose within the limits of 10 CFR 50.67.

The SGTS is designed to operate with influent air temperatures up to 135°F and relative humidity up to 100 percent. The system is periodically tested such that a decontamination efficiency of 99 percent can be assumed for removal of all forms of gaseous and particulate iodine. System retention capacity, originally based on the requirements of Regulatory Guide 1.3 and TID-14844, and amounts of up to 1300 gm (Reference 24), is currently evaluated 6.2-41 REV 24 11/22

FERMI 2 UFSAR against the 2.5 mg/g Regulatory Guide 1.52 limit for 30-day post-accident iodine accumulation based on the Regulatory Guide 1.183 Alternative Source Term. (Reference 26)

The SGTS is a Quality Level I, Category I ESF system meeting all applicable portions of IEEE 344; IEEE 308; ORNL-NSIC 65; UC-80 Reactor Technology, "Design, Construction and Testing of High Efficiency Air Filtration Systems for Nuclear Application;" ASME B&PV Code Section IX, "Welding Qualifications" (1971); Air Moving and Conditioning Association (AMCA), "Standard Test Code for Air Moving Devices" and "Standards Handbook;" and Savannah River Laboratory Report DP-812, "Application of Moisture Separators and Particulate Filters in Reactor Containment."

The SGTS meets the intent and functional objective requirements of Regulatory Guide 1.52.

Some detail design requirements of this guide, however, are not met because system fabrication was commenced before the guide was issued. All areas of noncompliance have been reviewed and in each case it has been determined that design and hardware changes required to bring these areas into compliance would not improve the system performance or capability to meet the design objectives. (See Appendix A, Subsection A.1.52.)

6.2.3.2 System Design The SGTS is a 100 percent-redundant ESF system and is shown schematically in Figure 6.2-

20. Major system components are listed and briefly described in Table 6.2-11. The system is designed to meet reactor building containment tests.

The SGTS consists of two separate and parallel 100 percent capacity trains. In addition to its associated ducts, controls, instrumentation, isolation valves, and protection systems, each train consists of the following items listed sequentially and in the direction of air flow:

a. A moisture separator to remove entrained water droplets, thus minimizing water loading of the prefilter. The moisture separator meets design requirements specified in Savannah River Laboratory Report DP-812

b. A prefilter to reduce the loading on the absolute filter. The prefilter is fire resistant and capable of operation at temperatures up to 250°F

c. An electric heater to reduce the relative humidity of the influent air to 70 percent or less under the "worstcase" conditions

d. A high-efficiency particulate air (HEPA) filter with a design DOP filtration efficiency of 99.97 percent for particles 0.3 µm in diameter or larger. Four parallel filter elements, each rated at 1000 scfm, are provided. These elements meet the intent of Military Specification MIL-F-51068-C. They are Underwriters Laboratories (UL) approved, fire resistant, and suitable for service under the temperatures, mass, and heat loading expected. The filters are mounted and sealed in a welded steel frame to ensure against possible bypass flow. The filters are tested periodically for bypass leakage such that a 99 percent decontamination efficiency can be assumed for removal of particulate iodine

e. A deep-bed, gasketless, all-welded construction adsorber containing activated carbon 6.2-42 REV 24 11/22

FERMI 2 UFSAR

f. A HEPA filter identical to the one described above to trap charcoal fines and decay daughters entrained by the air stream

g. An exhaust fan designed for 4000 ft3/minute

h. A cooling air fan installed in parallel with the exhaust fan, designed and built to the same standards and codes as the exhaust fan. The purpose of this blower is to provide cooling air flow to the charcoal filter in order to maintain charcoal temperature below 310°F under design loading conditions, in the event of high charcoal adsorber bed temperature.

Piping connections and valving exist between the SGTS and the secondary containment building ventilation system, the primary containment drywell, the suppression chamber, and the HPCI turbine barometric condenser vacuum pump discharge.

When the cooling air fan is in use, suction is taken from a roof vent. Discharge under both modes is to a vent located on the reactor building roof.

Full access and interior compartment lights with external light switches are provided for the spaces between filter train components where required to facilitate inspection, testing, and replacement of components.

Injection nozzles, sample points, and pressure taps are provided to facilitate periodic inservice inspection tests.

6.2.3.3 Design Evaluation 6.2.3.3.1 General The SGTS is designed to permit controlled venting of the primary or secondary containment following an accident or abnormal occurrence which might cause abnormally high airborne contamination in these areas.

Achievement of acceptable offsite dose rates following a DBA depends on the proper functioning of the SGTS. Therefore, the system, along with its power supplies and surrounding structures, has been designed to meet ESF system standards. All necessary equipment and surrounding structures are of Category I design. The equipment is powered from essential buses which will supply power to the SGTS in the event of a loss of offsite power. All power and control circuits meet the requirements of IEEE 279. Redundant active components are provided where necessary to ensure that a single failure does not impair or prevent system operation. An SGTS failure analysis is presented in Table 6.2-12.

The SGTS removal efficiency was successfully tested (Reference 24) for radioactive and nonradioactive forms of iodine and for particulate matter 0.3 mm or larger. The thyroid dose at the site boundary and low-population zone has been calculated on the basis of iodine-removal efficiency of 99 percent. Credit for 99 percent removal efficiency is dependent on in-place testing per Regulatory Guide 1.52, as stated in the Technical Specifications.

6.2-43 REV 24 11/22

FERMI 2 UFSAR 6.2.3.3.2 Secondary Containment Pressurization During Design Basis LOCA The pressure of the secondary containment volume after a LOCA has been studied. The analysis included infiltration and thermal loads from the primary containment, operating equipment, and emergency lighting.

The SGTS is designed to maintain a secondary containment pressure of -0.25 in. of water, thus ensuring that any airborne radioactive material in the secondary containment is not released to the surrounding atmosphere without passing through the SGTS filters. In the event of a design-basis LOCA, loss of offsite power is assumed; consequently, there is a delay from the start of the event to the activation of the SGTS and the emergency area coolers.

During the delay, the secondary containment pressure increases because of heat generated by emergency equipment and other sources. Upon initiation of the SGTS and emergency area coolers, a short time is required to reduce the secondary containment pressure to a negative pressure at or below -0.25 in. of water.

The purpose of the calculation was to generate the secondary containment pressure response during a design-basis LOCA and to determine the period of time when the secondary containment pressure is above -0.25 in. of water. The method of analysis and the assumptions and results are described in the following paragraphs.

Method of Analysis and Assumptions The computer code GOTHIC (Reference 25) was used to generate the secondary containment pressure response.

All major assumptions are given below:

a. No credit was taken for exfiltration from the secondary containment

b. Infiltration to the secondary containment was included in the pressure response analysis

c. No heat transfer was allowed to the outdoor atmosphere

d. Heat transfer to interior secondary containment walls, floors, and ceilings was included

e. Heat transfer from the torus room to the secondary containment is based on flow through the pressure relieving doors in the corner room basement walls

f. Only one SGTS filter train is available with a minimum volumetric flow rate of 3800 cfm

g. Offsite power is lost at the start of the design-basis LOCA event

h. The activation of the SGTS is delayed by 33 sec and the activation of the emergency area coolers is delayed by 38 sec (see Table 8.3-5)

i. The RHR, core spray, and RCIC pump rooms in the reactor building subbasement are treated separately from the main secondary containment volume. These rooms have their own emergency coolers to handle emergency equipment and lighting heat loads. Because the heat loads and cooling are 6.2-44 REV 24 11/22

FERMI 2 UFSAR confined to partially enclosed volumes at the very bottom of the secondary containment, the area coolers will absorb the heat loads within the confines of the corner rooms

j. The heat loads from the RHR, core spray, and RCIC pump rooms will not affect the main secondary containment volume before the initiation of the area coolers. The RHR pumps are activated 13 sec after the start of the design-basis LOCA event (see Table 8.3-5). The emergency coolers are activated at 38 sec.

For the heat loads to affect the main volume, the pumps, piping, and subsequently the corner room atmospheres must heat up. After the corner room atmospheres have heated up, the only mode of heat transfer to the main volume is natural convection. Considering that natural convection is a rather slow process, no significant heat transfer to the main secondary containment volume from the corner rooms is expected during the 25 sec from the initiation of the RHR pumps to the initiation of emergency cooling

k. An outdoor temperature of 95°F was used in the analysis

l. The reactor building closed cooling water system is inoperable and both divisions of the emergency equipment cooling water system are operating

m. All ECCS equipment starts

n. The fuel pool cooling and cleanup system, the reactor water cleanup system, and the recirculation pump motor-generator set cooling system are shut down

o. The fuel pool is at an operating temperature of 125°F.

Any increase in fuel pool temperature in the range of 125°F to 130°F will have negligible effects on the results of the analysis

p. An initial secondary containment pressure of 0.0 in. water gage was assumed.

Results The secondary containment response due to a design-basis LOCA is shown in Figure 6.2-21.

During the first 33 sec, the pressure increases to a slightly positive value. With the activation of the SGTS at 33 sec and the activation of the area coolers at 38 sec, the pressure decreases slightly.

At approximately 50 seconds, pressure-relieving doors on the common wall between the torus room and the corner rooms open and allow heated torus room air to enter the rest of the secondary containment. This step input of heat into the secondary containment appears as a sharp pressure spike in Figure 6.2-21.

The pressure then decreases past -0.25 in. of water to a steady-state secondary containment pressure. Less than 1020 sec elapses from the start of the design-basis LOCA event to the point where the secondary containment pressure decreases to and subsequently stays below -

0.25 in. of water. For conservatism, the 1020 sec (17 minutes) is maintained for the LOCA dose assessment (Subsection 15.6.5.5.2).

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FERMI 2 UFSAR 6.2.3.4 Tests and Inspections The SGTS and its components are thoroughly tested in a program consisting of the following classifications:

a. Predelivery and component qualification tests

b. Onsite preoperational acceptance tests

c. Operational surveillance tests.

Written test procedures establish acceptance criteria for all test results. Operational test results are recorded and compared with previous performance records, thus enabling early prediction of end of component life and appropriate corrective action.

For the various components of the system, the following predelivery qualification tests were applied:

a. Equipment Train Housing - Leak tests at +20 in. of water internal pressure.

Magnetic-particle or liquid-penetrant testing of all welds and discontinuities which could cause bypass leakage around the HEPA filters or adsorber beds

b. Demister - Qualification test or objective evidence to demonstrate compliance with requirements specified in Savannah River Laboratory Report DP-812

c. HEPA Filters - Qualification test to demonstrate a minimum of 99.97 percent efficiency when measured using a 0.3 mm DOP aerosol in conformance with MIL-STD-282

d. HEPA Filter Frames - Soap-bubble leak test across filterless covered bank

e. Adsorber Beds - Available objective evidence demonstrates acceptable flow-pressure characteristics and channeling effects

f. Adsorbent -

1. Ignition test

2. Methyl iodide removal test

3. Hardness test

4. Impregnant content test.

To demonstrate the integrity of the potassium iodide impregnated charcoal, required factory tests have been performed by the manufacturer prior to acceptance

g. Fans - Fan tests in accordance with the latest revision of AMCA Standard 210, "Air Moving and Conditioning Association Test Code for Air Moving Devices," to establish characteristic curves

h. Prefilter - Objective evidence and certification that NBS efficiency specified is attained

i. Valves, Dampers, and Actuators - Shop tests demonstrating seal effectiveness and ability to perform intended functions under the anticipated conditions.

6.2-46 REV 24 11/22

FERMI 2 UFSAR Onsite preoperational tests for the SGTS are listed in Subsection 14.1.3.2.47.

Onsite periodic testing will be performed. Items such as design conditions of flow, drawdown time, and differential pressure will be verified during these routine tests performed in compliance with the Technical Specifications.

6.2.3.5 Instrumentation and Controls Each SGTS unit and its controls, power supplies, valves, dampers, and auxiliary equipment are designed and installed so that they are both physically and electrically independent. The system conforms to single-failure criteria outlined in IEEE 279.

A separate control system is provided for each SGTS unit, including all items necessary for control and for determining the status of all components. The SGTS instrumentation is presented in Figure 6.2-20, a brief summary of which is presented below.

Differential pressure indicators are provided to measure the pressure drop across each filter and charcoal bed. Differential pressure switches are provided to signal abnormal conditions.

Each adsorber bed is equipped with the following controls:

a. Charcoal adsorber bed high-temperature-detection temperature element to actuate CO2 injection

b. Charcoal adsorber bed overheat temperature element to actuate standby cooling fan

c. Charcoal adsorber bed temperature controller to operate dryer (heater).

Fire protection for the adsorber bed is provided by a CO2 system which is actuated automatically by adsorber bed high temperature. Actuation of the system is signaled in the main control room.

Every isolation valve is supplied with position switches to provide positive indication of valve status.

High-temperature cutouts are provided as an integral part of the single-stage electric heaters.

Local temperature indication is provided upstream and downstream of the electric heaters.

Flow signals are transmitted to the main control board for indication and record. The flow transmitter directly controls the flow-control valve.

Manual switches are provided on the main control panel for each fan.

A continuous isokinetic sample is taken from the discharge of the operating filter train and processed through radiation detectors, a particulate filter, and an adsorber bed, and is returned to the SGTS roof vent.

High radiation levels are indicated by audible and visible alarms in the main control room.

The SGTS electrical equipment and instrumentation required to function in a postaccident harsh environment are environmentally qualified and in compliance with NUREG-0588.

When the SGTS filter units are shut down (auto standby mode with no actuation signal), all valves are closed and exhaust fans are deactivated. The charcoal adsorber blanket heater may or may not be on, depending on the charcoal temperature.

6.2-47 REV 24 11/22

FERMI 2 UFSAR Standby cooling fans and associated valves will automatically be activated on high charcoal bed temperature. The system is actuated and put into service automatically in response to any one of the following signals:

a. Auto standby mode

1. High drywell pressure

2. Low reactor water level

3. Reactor building ventilation exhaust radioactivity high

4. Fuel pool area ventilation exhaust radioactivity high.

b. Manual mode.

On actuation in the auto standby mode, both trains are started. The SGTS can be manually started by placing the control switch for the selected train in the run position.

The exhaust fans start, associated isolation valves open, normal reactor building ventilation system is tripped, and valves are automatically realigned to exhaust into the SGTS.

Adsorber-blanket heaters are automatically shut down if they were operating prior to system startup.

Activation of the SGTS in either mode is accompanied by audible and visible alarms in the main control room. The operator would then manually shut down one of the operating trains, leaving the other to perform as intended.

In the event of failure of the operating train for any reason, that train would be shut down and isolated by the operator in the main control room, and the redundant filter train would manually be put into service.

Main control room visible and audible alarms include the following:

a. Both SGTS trains "Auto Start"

b. High relative humidity ahead of charcoal bed

c. Low system flow rate (interlocked with primary blower "Run" signal)

d. High airborne contamination at the roof vent

e. Failure of either train to start up and operate on signal

f. Cooling fan "Auto Start"

g. Carbon dioxide fire protection system actuation.

Functions that can be accomplished manually from the main control room include the following:

a. Startup or shutdown of either or both SGTS trains

b. Startup of alternative SGTS train upon failure of operating train

c. Startup or shutdown of either standby cooling air fan 6.2-48 REV 24 11/22

FERMI 2 UFSAR

d. Isolation of SGTS train upon manual shutdown command from main control room.

Automatic functions include the following:

a. Startup of both SGTS trains and proper alignment of isolation valves

b. Activation of adsorber heater on low temperature

c. Startup of standby cooling air fan system when adsorber temperature exceeds its setpoint

d. CO2 injection on high adsorber bed temperature

e. CO2 shutoff when adsorber bed temperature is below its setpoint.

6.2.3.6 Materials Materials for fabrication, coating, and sealing the SGTS are chosen because of their capability for a satisfactory normal service life of 40 years, and 6 months of service under post-LOCA conditions at the maximum cumulative radiation exposure, without any adverse effects on service, performance, operation, or appearance. All materials of construction, including metal components, seals, gaskets, lubricants, and finishes, such as paints, are compatible with these objectives and are capable of satisfactory service under the expected radiation exposure.

Gaskets and seal pads are unicellular, ozone-resistant, oil-resistant neoprene or silicone-rubber sponge, Grade SCE-43, in accordance with ASTM Dl056.

Only adhesives listed and approved in AEC Health and Safety Bulletin 306, dated March 31, 1971, or Military Specification MIL-F-5l068C, dated June 8, 1970, are used.

Organic compounds included in the filter train are as follows.

a. Charcoal

b. HEPA filter media binder - The total weight of media binder per filter element is approximately 4 lb, or a total of 32 lb per equipment train

c. Filter adhesive - Approximately 1 liquid qt of fire-retardant neoprene adhesive is used to manufacture each HEPA filter

d. HEPA filter, pre-filter and coverplate gaskets - Filter and coverplate gaskets are unicellular neoprene per ASTM Dl056, Grade SCE-43

e. Door and access port gaskets - Door and access port gaskets are unicellular neoprene per ASTM D735-SCE-516, or ASTM D2000-BC-516

f. All painted metals (inside and out) are coated with 0.003-in. MOBIL 13R56B primer and 0.003-in. MOBIL VALCHEM Series 89 white top coat. Stainless components are not painted

g. Wire Coatings and Insulation - Approximately 15 lb of Cerro Products "Rockbestos" silicone rubber is used. Of this amount, less than 0.5 lb is inside the SGTS. Approximately 10 lb of EPR neoprene is used, none of which is inside the SGTS.

6.2-49 REV 24 11/22

FERMI 2 UFSAR 6.2.4 Containment Isolation System 6.2.4.1 Design Bases The containment isolation system consists of valves and controls required for the isolation of lines penetrating the primary containment. The primary objective of this system is to provide protection against release of radioactive materials to the environment as a result of accidents occurring to the nuclear steam supply system (NSSS), auxiliary systems, and support systems. This objective is accomplished by automatic isolation of appropriate lines that penetrate the primary containment. The containment isolation system is actuated automatically when specific limits are reached.

The containment isolation system, in general, closes fluid penetrations that support those systems not required for emergency operation. Fluid penetrations supporting ESF systems have remote manual isolation valves which may be closed from the main control room, if necessary. The automatic isolation valves close on receipt of an isolation signal from a sensor. For example, the main steam isolation valves (MSIVs) may be closed by signals indicating low water level in the reactor, main steam line tunnel high temperature, high steam flow, low steam line pressure, or low condenser vacuum. Isolation signals for each valve are specified in Table 6.2-2.

It is neither necessary nor desirable that every isolation valve close simultaneously with a common isolation signal. For example, if a process pipe were to rupture in the drywell, it would be important to close all lines that are open to the drywell and some effluent process lines, such as the main steam lines. However, under these conditions it would be essential that the containment and core cooling systems be operable. Therefore, several specific signals are used for isolation of various process and safety systems.

The design of isolation valving for lines penetrating the containment conforms to the intent of 10 CFR 50, Appendix A, General Design Criteria (GDC) 54, 55, 56, and 57. Redundancy and physical separation are provided in the electrical and mechanical design to ensure that no single failure in the containment isolation system prevents the system from performing its intended functions.

Where a penetration is part of a redundant train in an ESF system, isolation valves for that train may receive power from a single electrical division. This is desirable so that a single failure of an electrical division cannot disable both trains of the ESF system. In these cases a redundant mechanical barrier (i.e., closed systems beyond the isolation valves) exists so that containment isolation is not lost as a result of a single electrical failure.

Protection of primary containment isolation system components from missiles, and the integrity of these components to withstand seismic occurrences without loss of operability, was considered in the design of this system. The containment isolation system is Category I.

On signals of high drywell pressure or low water level in the reactor vessel all isolation valves that are part of systems not required for emergency shutdown of the plant are closed.

The same signals initiate the operation of systems associated with the emergency core cooling system (ECCS). Isolation valves that are part of the ECCS may be closed remote manually from the control room.

6.2-50 REV 24 11/22

FERMI 2 UFSAR Criteria for the design of the containment isolation control system are listed in Subsection 7.1.2.1.2. The bases for assigning certain signals for primary containment isolation are listed and explained in Chapter 7.

6.2.4.2 System Design The containment isolation system is designed to provide a minimum of one protective barrier between the reactor and the environs under all postulated conditions. A detailed discussion of the controls associated with the containment isolation system is included in Subsection 7.3.2. Table 6.2-2 specifies the plant protection system signals that initiate closure of the containment isolation valves.

6.2.4.2.1 Design Requirements Containment isolation valves were designed in accordance with the requirements of the ASME B&PV Code Section III, in effect at the time of purchase as required by 10 CFR 50, Section 50.55. Where necessary, a dynamic system analysis, which includes the impact effect of rapid valve closure under operating conditions, is included in the design specifications of piping systems that require containment isolation valves. Quality Assurance (QA) procedures are followed to ensure compliance with these specifications.

All containment isolation valves are located inside either the drywell or the secondary containment. Both structures are of Category I design and are protected against damage from missiles. The primary containment vessel is enclosed completely in a reinforced-concrete structure having a thickness of 4 to 7 ft. This concrete structure provides a major mechanical barrier for protection against missiles that may be generated external to the primary containment. Protection against damage from missiles is provided for isolation valves, actuators, and controls. Refer to Section 3.5 for a discussion of missile protection. Section 3.6 contains a discussion of protection provided against the dynamic effects of pipe whip, while Section 3.7 contains a discussion of the design analyses performed on containment penetration piping.

Each containment isolation valve is designed to ensure its performance under all anticipated environmental conditions including maximum differential pressure, extreme seismic occurrences, steam-laden atmosphere, high temperature, and high humidity. Section 3.11 presents a discussion of the environmental conditions, both normal and accident, for which the containment isolation system is designed.

Closed systems used as an isolation barrier, either inside or outside the primary containment, meet the following requirements:

a. The systems are protected against postulated missiles and pipe whip

b. The systems are designed to Category I

c. The systems are at least Quality Group B, except for specific instrument line applications noted in Table 6.2-2 (Note 12)

d. The systems are designed to at least the maximum temperature and pressure of the containment.

In addition, closed systems inside the containment meet the following requirements:

6.2-51 REV 24 11/22

FERMI 2 UFSAR

a. They are designed to withstand external pressure from the containment structural acceptance test

b. They are designed to withstand the design-basis accident and accompanying environment

c. They do not communicate with either the reactor coolant system or the containment atmosphere.

Power-operated containment isolation valves have limit switches that indicate valve position in the main control room. Containment isolation valves are designed to fail in the safe position. Containment isolation valves are either automatically actuated by the signals shown in Table 6.2-2 or are remote manually operated. Some containment isolation check valves inside containment are provided with supplemental air operators to verify free disk movement during opening and closing and zero pressure differentials across the valves. This arrangement provides a means by which to periodically verify valve operability.

Containment isolation valves that are remote manually operated are required to be provided with a leakage detection capability or be administratively closed (Standard Review Plan

[SRP] 6.2.4). Table 6.2-13 lists the remote manual containment isolation valves that have a leak detection capability.

Remote manual containment isolation valves that are locked closed (and are thus under administrative control) are as follows.

Penetration Valve X-12 V8-3407 X-21 V5-2006 V5-2007 The only other containment isolation valves with a remote manual primary actuation mode are the N2 supply to the drywell-to-torus vacuum breakers, penetrations X-204A-M (valves V4-2036, V4-2065, V4-2075, V4-2077, V4-2082, V4-2084, V4-2086, V4-2088, V4-2090, V4-2092, V4-2094, and V4-2096). (Table 6.2-2 provides the F valve numbers.) These valves are locked closed to comply with Technical Specification 3.6.1.3.2 and are opened during the testing of the drywell-to-torus vacuum breakers. These valves are under administrative control and considered locked closed as defined in SRP 6.2.4 to preclude the possibility of their being inadvertently opened during normal reactor operations. Thus, as all remote manual containment isolation valves are either provided with leak detection capability or locked closed, Fermi 2 meets the guidance set forth in SRP 6.2.4.

6.2.4.2.2 Conformance To General Design Criteria As stated in Subsection 6.2.4.1, the design of isolation valving for lines penetrating the containment follows the intent of GDC 54 through 57. Isolation valving for instrument lines that penetrate the containment follows the guidance of Regulatory Guide 1.11. Those cases where literal interpretation of GDC 54 through 57 has not been followed are included in the discussions in the following subsections.

6.2-52 REV 24 11/22

FERMI 2 UFSAR 6.2.4.2.2.1 General Design Criterion 54 General Design Criterion 54 in 10 CFR 50 states Piping systems penetrating primary reactor containment shall be provided with leak detection, isolation, and containment capabilities having redundancy, reliability, and performance capabilities which reflect the importance to safety of isolating these piping systems. Such piping systems shall be designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits.

Criterion 54 Conformance All piping penetrations meet the intent of GDC 55, 56, or 57. In doing so, they also conform to the intent of GDC 54 to the extent that all piping systems penetrating the primary containment are provided with leak detection, isolation, and containment capabilities which reflect the importance to safety of isolating these piping systems. In addition, each piping penetration is designed to be tested periodically in accordance with 10 CFR 50, Appendix J, as described in Table 6.2-2. Specifically, the following systems have containment isolation provisions consistent with the provisions of GDC 54.

Traversing In-Core Probe (TIP) System (Penetrations X-35B, C, D, E, F The TIP system detector signal and drive cable neither comprise a portion of the reactor coolant pressure boundary nor directly communicate with the primary containment atmosphere. Thus, GDC 55 and 56 are not directly applicable to this specific class of lines.

The basis on which TIP system lines are designed is described more closely in GDC 54, which states, in effect, that systems penetrating the primary containment are to be provided with isolation capabilities commensurate with the importance of isolating the system. Thus, even though the failure of TIP system lines presents no safety hazard, additional conservatism is provided in TIP system isolation capabilities, which reflects the intent of GDC 55.

The TIP system detector signal and drive cable are stored outside the primary containment behind a normally closed ball valve and an explosively actuated shear valve. The valves are located outside the containment for inspection and maintenance accessibility, and the position of each is indicated in the control center. The ball valve remains closed at all times except during operation of the associated TIP system channel. Prior to use of the TIP system, the ball valve is manually opened. All five TIP machines may be used simultaneously, however any one guide tube is used, at most, only a few hours per year.

After TIP system cable retraction, the ball valve is manually closed. Should a containment isolation signal be received while the TIP system cable is inserted, the cable will withdraw automatically, and this will be followed by automatic closure of the ball valve.

The function of the shear valve is to ensure the integrity of the containment in the unlikely event that the ball valve should fail to close or the drive cable should fail to retract from the guide tube during the time containment isolation is required. The valve is designed to shear the TIP drive cable and seal the drive tube upon command from the control center. In addition to valve position, the condition of each shear valve dc firing circuit is monitored 6.2-53 REV 24 11/22

FERMI 2 UFSAR continuously in the control center. Additional testing requirements are discussed in Note 17 to Table 6.2-2.

Control Rod Drive Insert and Withdrawal Lines (Penetrations X-37A, B, C, D and X-38A, B, C, D)

Control rod drive (CRD) insert and withdrawal lines penetrate the primary containment, but they neither directly communicate with the containment atmosphere nor comprise part of the reactor coolant pressure boundary. Thus, GDC 55 and 56 are not directly applicable to this class of lines. The basis on which the CRD lines are designed is described more closely in GDC 54, which requires such systems to have isolation capabilities commensurate with the importance of isolating the system. Since these lines are necessary for the scram function, the reliability of their operation is of utmost concern. Thus, isolation valves should not be incorporated in the design of this system. The probability of reliable and timely operation is enhanced by simplicity of design and by minimizing, where possible, the introduction of possible failure mechanisms. Even though multiple breaks postulated and analyzed in Section 4.0 pose no threat to public health and safety, CRD insert and withdrawal isolation capabilities were designed to reflect the conservative intent of GDC 55.

Both the CRD insert and withdrawal lines are provided with normally closed, fail-closed, solenoid-operated directional control valves, which open only during routine movement of their associated control rod. The normally closed, fail-open, air-operated scram inlet and exhaust valves open only when required to effect a rapid reactor shutdown (scram). In addition, manual shutoff valves are provided for positive isolation in the unlikely event of a pipe break within a hydraulic control unit. (These units and the valves described above are located outside the containment to satisfy testing, inspection, and maintenance requirements.)

In addition, each CRD insert line is provided with an automatically actuated flange ball check valve inside containment; the flange ball check valve is part of the CRD mechanism.

During post-LOCA, the scram inlet and outlet valves will remain open if the scram cannot be reset. Therefore, due to CRD seal leakage, the scram discharge volume (SDV) could experience reactor vessel pressure. To ensure the integrity of the SDV, it will be included in the Type A tests.

6.2.4.2.2.2 General Design Criterion 55 General Design Criterion 55 in 10 CFR 50 states:

Each line that is part of the reactor coolant pressure boundary and that penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines such as instrument lines, are acceptable on some other defined basis:

(1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or 6.2-54 REV 24 11/22

FERMI 2 UFSAR (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment.

Isolation valves outside containment shall be located as close to containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety.

Other appropriate requirements to minimize the probability or consequences of an accidental rupture of these lines or of lines connected to them shall be provided as necessary to assure adequate safety. Determination of the appropriateness of these requirements, such as higher quality in design, fabrication, and testing, additional provisions for inservice inspection, protection against more severe natural phenomena, and additional isolation valves and containment, shall include consideration of the population density, use characteristics, and physical characteristics of the site environs.

Criterion 55 Conformance The reactor coolant pressure boundary (RCPB) (as defined in 10 CFR 50, Section 50.2[v])

consists of the reactor pressure vessel (RPV), pressure-retaining appurtenances attached to the RPV, and valves and pipes that extend from the RPV up to and including the outermost isolation valve. The lines of the RCPB that penetrate the primary containment are capable of isolation, thereby precluding any significant release of radioactivity. Similarly, lines that do not penetrate the primary containment but form a portion of the RCPB (such as connecting lines up to and including the second isolation valve) are designed to ensure that isolation of the reactor pressure boundary can be achieved.

6.2.4.2.2.2.1 Influent Lines Influent lines that penetrate the primary containment and connect directly to the RPV are equipped with two isolation valves: one inside the containment, the other outside the containment. Both valves are located as close to the containment as practical. Influent lines which comprise part of the RCPB are listed below and discussed in detail in the remainder of this section.

Penetration No. System X-9A Feedwater HPCI supply Feedwater X-9B RCIC supply RWCU return X-13(A, B) RHR pump discharge to recirculation loops X-16(A, B) Core spray pump discharge to core spray spargers 6.2-55 REV 24 11/22

FERMI 2 UFSAR Penetration No. System X-42 Standby liquid control system X-49A and X-51A Recirculation pump seal purge Feedwater System The feedwater line penetrating the primary containment is part of the RCPB. This penetration is supplied with one automatic isolation valve inside and one automatic isolation valve outside the containment. The isolation valve inside the containment is a check valve.

The isolation valve outside the containment is an air-operated, spring-to-close, positive-acting check valve.

Should a break occur in the feedwater line, the valves will prevent significant loss of fluid inventory and offer immediate isolation. During the postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply. For this reason, the outer containment isolation valve does not automatically isolate on a signal from the containment isolation system. However, the valve is capable of remote closure from the control room to provide long-term leakage protection when, based on operator judgment, continued makeup from the feedwater system is no longer necessary. A second check valve is located outside the containment--between the air-operated isolation valve and the containment wall--for added isolation capability.

RWCU, HPCI, and RCIC Systems Influent lines that use the feedwater piping and penetrations in order to transfer fluid to the RPV consist of the reactor water cleanup (RWCU) return, and reactor core isolation cooling (RCIC), high-pressure coolant injection (HPCI) supply, and standby feedwater. Each of these lines can be isolated by the feedwater check valve inside the containment. The RCIC and HPCI supply lines each have an isolation valve outside the containment. These valves are normally closed, dc power-operated, remote manually actuated gate valves. The RWCU return line has a motor operated, normally open, ac power-operated gate valve as its isolation valve outside the containment. This valve is capable of remote closure from the control room. Two check valves are provided between the isolation valve and the containment wall.

Should a break occur in the RWCU line, these check valves will prevent significant loss of fluid inventory from the feedwater side.

RHR and Core Spray Systems The residual heat removal (RHR) pump discharge lines to the recirculation system (low-pressure coolant injection and shutdown cooling modes) and the core spray pump discharge lines have testable check valves inside the containment that provide for immediate isolation in the event of a break upstream of these valves. The outer containment isolation valves are remote manually actuated gate valves. However, no licensing credit is taken for the containment isolation feature of the RHR inboard check valves (see Reference 25a). Each valve will receive an automatic opening signal in the event of the postulated LOCA.

Standby Liquid Control System 6.2-56 REV 24 11/22

FERMI 2 UFSAR The standby liquid control line uses a check valve as the isolation valve inside, as well as outside, the primary containment. General Design Criterion 55 states that a simple check valve may not be used as the automatic isolation valve outside the containment; however, should insertion of the liquid poison become necessary, it is imperative that the injection line be open. In the design of this system, it has been accepted practice to omit an automatic valve that opens on signal, as this introduces a possible failure mechanism. As a means of providing assurance for reliable and timely actuation, an explosive valve is used.

In this manner, the availability of the line is ensured. Because the standby liquid control line is a normally closed and non-flowing line, rupture of this line is a very remote possibility.

Recirculation Pump Seal Purge System The recirculation pump seal purge lines use two air-operated globe valves, one inside the containment and one outside the containment. The valves isolate automatically on high drywell pressure or low vessel water level (level 2).

6.2.4.2.2.2.2 Effluent Lines With the exception of the postaccident pressurized reactor coolant sample lines, effluent lines that form part of the RCPB and penetrate the primary containment are equipped with two isolation valves, one inside the containment and the other outside the containment. Both valves are located as close to the containment as practical. Effluent lines that comprise part of the RCPB are listed below, and are discussed in detail in the remainder of this section.

Penetration No. Section X-7(A,B,C,D) Main steam lines X-8 Main steam line drains X-10 Steam to RCIC turbine X-11 Steam to HPCI turbine X-12 RHR pump suction for recirculation piping (shutdown cooling mode)

X-28Cf Postaccident pressurized reactor coolant sample X-29A Reactor water sample line Postaccident pressurized reactor X-40Dd coolant sample X-43 Reactor water cleanup suction 6.2-57 REV 24 11/22

FERMI 2 UFSAR Main Steam System The MSIVs are air-operated, automatically actuated, Y-pattern globe valves. Two valves are provided in each line: one inside and one outside the containment. There is a third valve in each line outside the containment that is a gate valve.

The main steam drain line is provided with two automatic, motor-operated gate valves: one inside and one outside the containment. These valves are closed during normal reactor operation.

RCIC System Both isolation valves in the RCIC steam supply line are normally open, remote manually actuated gate valves. These valves close automatically on indication of an RCIC system piping failure.

HPCI System The isolation valves in the HPCI steam supply line consist of two gate valves and a 1-in.

globe valve. All are remote manual motor-operated valves. The isolation valve inside the containment is open normally. The normally open, 1-in. globe valve bypasses the normally closed system supply valve outside the containment to keep the HPCI steam supply line warm. All HPCI steam supply line valves close automatically on indication of an HPCI system piping failure.

6.2-58 REV 24 11/22

FERMI 2 UFSAR RHR System The RHR shutdown cooling suction line is provided with two normally closed, automatically actuated, motor-operated gate valves and a locked-closed bypass valve. The bypass valve provides assurance that the normal shutdown cooling method will be available if the normally used valve fails. There is also a 3/4-in. bypass line with two check valves in series, which allows heated water trapped inside the RHR line to be relieved to the reactor vessel.

Reactor Coolant Sample System (Non-Postaccident)

The reactor water sample line is provided with two automatic, air-operated, fail-closed isolation globe valves: one inside and one outside the containment. These valves are closed during normal reactor operation, but receive an automatic closure signal in case they are open when containment isolation is required.

Postaccident Pressurized Reactor Coolant Sample The two postaccident reactor coolant sample lines are connected to jet pump instrumentation lines outside the containment. Each line is provided with a solenoid-operated globe isolation valve outside the containment. These valves are closed during normal reactor operation and are opened only during postaccident conditions.

RWCU System The RWCU suction line is provided with two normally open, automatic, motor-operated gate valves. These valves will close on receipt of a containment isolation or RWCU system piping failure signal.

Leak detection is provided for each line that has remote manual containment isolation valves and is evaluated against GDC 55.

6.2.4.2.2.3 General Design Criterion 56 General Design Criterion 56 in 10 CFR 50 states Each line that connects directly to the containment atmosphere and penetrates primary reactor containment shall be provided with containment isolation valves as follows, unless it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis:

(1) One locked closed isolation valve inside and one locked closed isolation valve outside containment; or (2) One automatic isolation valve inside and one locked closed isolation valve outside containment; or (3) One locked closed isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment; or (4) One automatic isolation valve inside and one automatic isolation valve outside containment. A simple check valve may not be used as the automatic isolation valve outside containment.

6.2-59 REV 24 11/22

FERMI 2 UFSAR Isolation valves outside containment shall be located as close to the containment as practical and upon loss of actuating power, automatic isolation valves shall be designed to take the position that provides greater safety.

Criterion 56 Conformance The lines that penetrate the primary containment and communicate with the containment atmosphere can be grouped into two categories: (1) pipes that penetrate the primary containment and connect directly to the suppression pool; and (2) pipes that penetrate the primary containment and connect directly to the drywell atmosphere.

6.2.4.2.2.3.1 Lines Connecting To the Suppression Pool Lines in this category are listed below:

Penetration No. System X-205(A,B) Torus to secondary containment vacuum breakers X-205C Suppression pool N2 and air purge inlet X-205D Suppression pool exhaust and N2 inlet X-206(A, B, C, D, E, Suppression pool water level and pressure F) instrumentation X-210(A, B) RHR minimum flow line RHR heat exchanger thermal relief RHR test line Torus water management return RHR suction thermal relief RHR heat exchanger discharge header thermal relief Postaccident liquid sample return RHR warmup and return X-211(A, B) RHR to suppression pool spray X-212 RCIC turbine exhaust line X-213(A, B) Torus water management supply X-214 RCIC vacuum breaker line X-215 HPCI vacuum breaker line Combustible gas control suction Postaccident gaseous sample return 6.2-60 REV 24 11/22

FERMI 2 UFSAR Penetration No. System X-217 Grab sample line X-218 Combustible gas control return X-219 Combustible gas control suction X-220 HPCI turbine exhaust line X-221 HPCI turbine exhaust drain X-222 RCIC vacuum pump discharge X-223(A, B, C, D) RHR pump suction RHR pump suction header thermal relief X-224(A, B) Core spray pump suction X-225 HPCI pump suction X-226 RCIC pump suction X-227(A, B) Core spray pump suction thermal relief Core spray pump discharge header thermal relief Core spray pump minimum flow line Core spray pump test line Torus water management return HPCI minimum flow line RCIC minimum flow line X-230 Primary containment monitoring system Post accident suppression pool atmosphere sample X-231 Primary containment monitoring system X-231 Postaccident suppression poolatmosphere sample As stated in GDC 56, two isolation valves--one inside and one outside the containment--are required in lines that penetrate the primary containment and connect directly to the containment atmosphere. However, GDC 56 allows for alternatives to these explicit isolation requirements where the acceptable basis for each alternative is defined. The following are alternatives to explicit conformance with GDC 56. Notes in Table 6.2-2 identify the alternative basis to which each penetration is designed.

Two Isolation Valves Outside Containment The primary containment radiation monitor system (PCRMS) is associated with Division I of the primary containment atmosphere monitoring system (PCAMS). The nonessential 6.2-61 REV 24 11/22

FERMI 2 UFSAR PCRMS has two isolation valves on the inlet and two isolation valves on the outlet. These isolation valves are a normally open spring-to-close solenoid operated globe valve and an air operated ball valve. These inlet and outlet lines are connected to the containment atmosphere via PCAMS piping during normal operation. The isolation valves receive a containment isolation signal on a LOCA (see Subsection 6.2.4.2.2.3.2).

For lines that connect to the suppression pool, an isolation valve located inside the containment would necessitate placement of the valve either under water or in a high-humidity, nonaccessible area. Such placement would subject these valves to an extremely hostile environment, which could compromise their reliability and prevent routine inspection and maintenance. Thus, as an alternative to the explicit requirements of GDC 56 for lines in ESF or ESF-related systems, both isolation valves are located outside, and as close to, the containment wall as practical.

Relief Valves as Isolation Valves Relief valves are provided in the RHR, core spray, HPCI, RCIC, and combustible gas control (CGC) systems as overpressureprotection devices. These valves are required for the design of Class B systems according to the ASME B&PV Code, Subsection NC-7000. The valves are installed in a manner that ensures their correct operation and reliability. Further, the Code requires that no stop valves or other devices be placed (in relation to a pressure relief device) so that it could impair the overpressure protection offered by the relief valve itself.

Relief valves installed in these lines provide this required level of protection, and, if required to operate, would route the diverted fluid to the suppression pool.

Because of the orientation required, each of these relief valves is an isolation valve for the applicable penetration. The piping and valve designs are Quality Group B, Category I, and will withstand temperatures and pressures at least equal to the containment design pressure and temperature. Should the postulated LOCA occur, containment pressure would be felt on the downstream side of the relief valve, and would act in conjunction with the spring pressure setting of the relief valve to further enhance seating.

Remote Manual Isolation Valves Remote manual valves are used as containment isolation valves in ESF and ESF-related systems. These systems include RHR, core spray, HPCI, RCIC, and reactor building closed cooling water (RBCCW) Emergency Equipment Cooling Water (EECW) systems. In each case, leak detection is provided.

Closed Systems Outside the Containment The RHR, core spray, HPCI, and RCIC systems are closed-loop systems outside the containment. These systems can accommodate a single active failure and still maintain containment integrity. The systems are designed to Category I standards, are classified as Quality Group B, and will maintain their integrity should the containment experience its design temperature and pressure transient. Thus, as an alternative to the explicit requirements of GDC 56 for such lines in ESF or ESF-related systems, a single isolation valve is used outside the containment to enhance system reliability.

6.2-62 REV 24 11/22

FERMI 2 UFSAR Lines that are not Quality Group B but that connect to these closed-loop systems are itemized in Table 6.2-14. By necessity, some of the valves in these lines are located near system pumps and are subject to missile damage should the pump fail. Should this occur, the system would be isolated either manually or automatically, and, therefore, failure of these valves as a result of missile damage would not constitute a breach of the primary containment.

Other Systems The CGC, purge and inerting systems each use two isolation valves in series outside the suppression pool. Installing one of these valves inside the suppression pool could compromise reliability and prevent routine inspection and maintenance. These systems are built to the same quality standards as the primary containment and are protected against postulated missiles and pipe whip. The CGCS PCIVs are permanently de-energized and locked-closed.

The vacuum breakers to the secondary containment are essential for primary containment integrity. Isolation is provided through a power-to-close, spring-to-open butterfly valve and a testable check valve. Power from divisional electrical buses is applied to the butterfly valve to keep the valves closed, except when air is required to relieve a vacuum inside the primary containment. The butterfly valve will open on loss of power or degraded voltage but closes automatically once power is restored or voltage recovers. During a LOCA concurrent with a Loss of Offsite Power (LOP), the butterfly valves will de-energize and open until power is restored to the divisional electrical buses. Upon restoration of power, the butterfly valves will re-energize and reposition, closing the valves. During a LOCA concurrent with a low grid voltage, insufficient voltage during the time Core Spray and RHR pumps start may cause the Division I butterfly valve to pen. Once nominal voltage is restored after RHR and Core Spray pump starts, the butterfly valve will close. In either scenario, the time the butterfly valve is open is less than the 108 second allowed stroke time for containment isolation valves established in the accident analysis. The vacuum breaker testable check valves provide containment isolation and remain closed during the accident unless negative differential pressure exists. These lines and valves are Category I, Quality Group B and are located in missile-free areas.

6.2.4.2.2.3.2 Lines Connecting To the Drywell Lines in this category are listed below and discussed in the remainder of this section. The lines are Category I and Quality Group B at least through the outermost containment isolation valve.

Penetration No. System X-15 CGC suction X-17 Abandon RHR head spray X-18 Drywell floor drain sump pump discharge X-19 Drywell equipment drain sump pump discharge X-20 Demineralized service water to drywell 6.2-63 REV 24 11/22

FERMI 2 UFSAR Penetration No. System X-22 Control air and N2 to drywell X-23 RBCCW/EECW supply X-24 RBCCW/EECW return X-25 Drywell exhaust X-26 Drywell N2 and air inlet X-27(a, b, c, d, e) Containment atmosphere sample and postaccident drywell atmosphere sample (X-27b only)

X-27f Drywell pressure instrumentation X-29B (b,c) Reactor protection system X-29Be Drywell instrumentation X-31Ba Drywell on line pressure control X-34(A, B) RBCCW/EECW supply and return X-36 N2 to dry X-39(A, B) RHR to containment spray header X-44 CGC suction X-47(a,b) Reactor protection system X-47e Drywell instrumentation Nitrogen inerting instrumentation X-48(a,b,c,d,e,f) Containment atmosphere sample and postaccident drywell atmosphere sample (X-48f only)

Regulatory Guide 1.7 was revised in March 2007 to reflect the amended 10 CFR 50.44. The Combustible Gas Control System (CGCS) has been retired in place with its electrical circuits de-energized and fluid process piping isolated from primary containment with redundant locked-closed isolation valves. The valves are located external to the primary containment, and are accessible for inspection and testing during normal reactor operation.

Penetration X-17 for the abandoned RHR head spray line now conforms to the requirements of GDC-56 since the line is no longer directly connected to the RPV. Two normally closed motor operated valves are located in this line, one inside containment and one outside containment.

The drywell equipment and floor drain sump pump discharge lines each have a motor-operated, normally open gate valve inside the containment, and an air-operated, normally closed gate valve outside the containment. These valves receive containment isolation 6.2-64 REV 24 11/22

FERMI 2 UFSAR signals on the postulated LOCA. Rupture disc overpressure protection is installed to limit the pressure rise from LOCA heatup of the isolated penetrations per GL 96-06. The rupture disc discharges into a small discharge tank which provides a sealed closed barrier for containment isolation.

Demineralized service water line has an isolation valve inside containment and a spectacle flange assembly with blank installed outside containment. Control air and nitrogen lines have isolation valves inside and outside the drywell. The demineralized service water isolation valve is the only manual valve in this group. The valve remains locked closed at all times during reactor operation.

The drywell exhaust and air purge lines have isolation valves inside and outside the containment. The valves are either automatically or remote manually actuated. Leak detection is provided to inform the control room operator when closure of the remote manual valves is required.

The RHR pump discharge to the containment spray lines contains two isolation valves outside the containment. Since the spray header is integral to the drywell wall, placing an isolation valve inside the containment could compromise the structural integrity of the containment spray headers.

The RBCCW/EECW supply lines each have a check valve inside the containment and a motor-operated gate valve outside the containment. These motor-operated gate valves are remote, manually actuated and close on a high drywell pressure EECW initiation signal. The RBCCW/EECW return lines each have a remote, manually actuated, diverse electrically powered motor-operated gate valve inside and outside the containment.

The drywell instrumentation, nitrogen-inerting instrumentation, reactor protection system, and containment atmosphere sample systems are closed-loop systems outside the containment. These systems can accommodate a single active failure and still maintain containment integrity. The systems are designed and installed as Quality Group B, up to and including the isolation valves. The balance of the instrument piping is designed to meet Quality Group B design criteria. These design criteria include stress analysis with consideration given to deadweight, thermal, and seismic conditions. The systems are seismically supported.

Nuclear-grade materials are used throughout the fabrication of the piping system. They will maintain their integrity should the containment experience its design temperature and pressure transient. Thus, as an alternative to the explicit requirements of GDC 56 for such lines in ESF or ESF-related systems, a single air-operated isolation valve or solenoid-operated isolation valve is used outside the containment to enhance system reliability.

The lines that connect the nonessential PCRMS to Division I of the closed outside containment loop of the PCAMS have two isolation valves outside containment for both the inlet and outlet of the PCRMS. The PCRMS utilizes common piping of PCAMS; therefore, the valves are outside containment and placed as close as practical to the PCAMS piping loop. All other requirements of GDC 56 are met.

The drywell postaccident atmosphere sample lines contain two solenoid-operated globe isolation valves outside the containment. These lines are connected to the normal 6.2-65 REV 24 11/22

FERMI 2 UFSAR containment atmosphere sample system lines outside the containment. These valves are closed during normal reactor operation and are opened only during postaccident conditions.

6.2.4.2.2.4 General Design Criterion 57 General Design Criterion 57 in 10 CFR 50 states Each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere shall have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote manual operation. This valve shall be outside the containment and located as close to the containment as practical. A simple check valve may not be used as the automatic isolation valve.

Criterion 57 Conformance Penetrations X-204 (A through M) for the drywell-to-torus vacuum breaker nitrogen supply and their associated isolation valves conform to the locked closed requirements of GDC 57 to comply with Technical Specification 3.6.1.3.2. A locked closed, air-operated globe valve as defined is SRP 6.2.4 is located in each line outside the containment.

6.2.4.2.3 Containment Isolation Dependability Fermi 2 meets the NRC requirements developed for reliable containment isolation as follows.

a. The containment isolation design complies with the recommendation of SRP 6.2.4 in that there is diversity in the parameters sensed for the initiation of containment isolation. Safety-grade signals are provided for the detection of abnormal conditions in the reactor coolant system and containment; these are low reactor vessel water level and high drywell pressure Several lines are not isolated on the high-drywell- pressure signal in order to retain system availability for small breaks or leaks. Justification for these cases is given under Comments in Table 6.2-15

b. Essential and nonessential systems containing piping systems that penetrate the containment are identified in Table 6.2-16. Those systems identified as essential are regarded as indispensable or are backup systems in the event of a LOCA. The nonessential systems have been judged to be not required in LOCA situations

c. Nonessential lines that are a possible open path out of the containment are automatically isolated by the containment isolation signals, by check valves that prevent flow out of the containment, or by manual valves that are normally closed. Normally closed valves are under administrative control to ensure that valves are closed during startup, power, hot-standby, and hot-shutdown modes of operation For instrument lines connected to the RCPB, each line is equipped with a flow-restricting orifice located as close as practical to the point of connection to the RCPB. A manual shutoff valve is located outside the containment and is 6.2-66 REV 24 11/22

FERMI 2 UFSAR located as close as practical to the containment wall. An excess-flow check valve is provided immediately downstream of the manual valve. This design and installation follows the guidance of Regulatory Guide 1.11

d. The resetting of containment isolation signals does not result in the automatic reopening of containment isolation valves. Deliberate operator action is required to reopen a containment isolation valve once the containment isolation signals are reset

e. Drywell high pressure initiates the containment isolation of nonessential systems and lines. The Technical Specifications specify the drywell high-pressure trip-point setting

f. The Fermi 2 purge valves satisfy the operability criteria set forth in Branch Technical Position (BTP) CSB 6-4, Revision 1, and Staff Interim Position dated October 23, 1979. The Fermi 2 position relative to BTP CSB 6-4 is provided in Subsection 6.2.5.2.5. Fermi 2 complies with the Staff Interim Position as follows: (1) the purge valves are intended to be operated only for inerting, deinerting, or pressure control in accordance with the Technical Specifications; and (2) the Fermi 2 valves are operable for DBA flows

g. Containment purge and ventilation isolation valves close automatically upon the detection of high airborne radiation in the reactor building exhaust line.

This high-radiation isolation signal is in addition to the diverse containment isolation signals.

6.2.4.2.4 Valve Closure Times Proper valve closing time is achieved by appropriate selection of valve type, operator type, and operator size. Isolation valve closing times were verified during the functional performance tests prior to reactor startup and are periodically retested at intervals specified in the Technical Specifications. The design of piping systems penetrating the reactor containment includes provisions for operability and leakage testing of isolation valves.

Motive power for the valves on process lines that require two valves is supplied from physically independent power sources to provide a high probability that no single event could interrupt power to both closure devices. Loss of valve actuation power is detected and annunciated in the main control room.

In general, isolation valves located outside the primary containment receive dc power from the Division II power supply, or alternate division ac power, while those located inside the primary containment receive ac power from the Division I power supply.

6.2.4.2.5 Instrument Lines Penetrating the Primary Containment All instrument lines connected to the reactor coolant pressure boundary are Category I and Quality Group A. Physical separation is provided for redundant instrument lines to the extent practical, so that the failure of one line will not induce failure in another. The response time for all sensors connected to instrument lines is not affected by the valves or orifices in the line. The design and installation of instrument lines follows the guidance of Regulatory Guide 1.11 (Safety Guide 11).

6.2-67 REV 24 11/22

FERMI 2 UFSAR The instrument-sensing lines listed below penetrate the primary containment and connect to the RCPB.

Number of lines Instrument Description 24 Jet pump flow 1 Jet pump 14 RPV level/pressure*

8 Recirculation inlet to RPV DP 2 Recirculation system pressure 8 Recirculation system flow 4 Recirculation Pump DP 4 Recirculation pump seal pressure 4 Steam flow to HPCI turbine 4 Steam flow to RCIC turbine 16 Main steam flow 2 Feedwater pressure**

• The portion of the instrument line passing through the containment is part of a penetration assembly that is part of the containment and thus is Quality Group B, consistent with the Containment Quality Group.

Two check valves are provided in series for the isolation of each division of the reactor vessel instrument-sensing line backfill system from the RPV level/pressure instrument reference legs.

• • These lines do not penetrate the containment. They tap in between the containment and the outer isolation valve.

Each line, except for the feedwater pressure-sensing line, is equipped with a flow-restricting orifice located as close as practical to the point of connection to the RCPB. No such device is necessary for the feedwater pressure-sensing lines because they tap in outside the containment, and the isolation valve inside the containment (check valve) serves the function of the restricting orifice. A manual shutoff valve is located outside the primary containment and is installed as close as practical to the containment wall or pipe (in the case of feedwater). An excess-flow check valve is provided immediately downstream of the manual valve. The excess-flow check valve will close automatically in the event of a line break downstream. Indicating lights on a control room panel monitor excess-flow-check-valve position. These valves may be reopened by actuation of a solenoid valve, which is operated 6.2-68 REV 24 11/22

FERMI 2 UFSAR from a local control panel, after repairs are made. This design and installation follows the guidance of Regulatory Guide 1.11. There are no instrument lines that penetrate both the primary and the secondary containments.

The postulated break of an instrument line attached to the RCPB is discussed and evaluated in Subsection 15.6.2. Leakage from such a rupture upstream of the excess-flow check valve is minimized by the restricting orifice in the line. The integrity and functional performance of the secondary containment and standby gas treatment systems are not impaired by this event, and the calculated potential offsite exposures are substantially below the guidelines of 10 CFR 100.

Each instrument line except the jet pump instrument lines is provided with a 0.25-in.-

diameter orifice in addition to the excess-flow check valve. The jet pump lines are 0.25 in.

diameter from the RPV nozzles to the jet pump taps. This orifice will restrict the coolant loss to a value whose equivalent steam volume is much less than the capacity of one standby gas treatment system (SGTS) train. Therefore, pressurization of the secondary containment will not result from an instrument line break and a failure of the associated excess-flow check valve to isolate the ruptured line. Coolant lost from such a break is inconsequential when compared to the makeup capabilities of the feedwater or RCIC system.

6.2.4.2.6 Leak Detection For systems penetrating the primary containment, major leaks in the pipe are located by increased temperature, radiation, sump level, changes in pressure, differential pressure, process line flow, etc. These indications are monitored in the control room to alert the operator when remote manual valves should be closed. In addition, certain indications of leakage will cause automatic valves to close in response to a system accident.

Leak detection is further discussed in Sections 5.2 and 7.6.

6.2.4.2.7 Leak Rate Testing The reactor containment and containment penetrations are designed to permit periodic leak rate testing in accordance with GDC 52 and 53, and Appendix J to 10 CFR 50. See also Subsection 6.2.4.4.

Testing requirements for piping penetration isolation barriers and valves have been established by using the intent of GDC 54 as interpreted in Appendix J to 10 CFR 50.

Exceptions taken to Appendix J Type C tests are described in Table 6.2-2.

The primary containment isolation system is scheduled to undergo periodic testing during reactor operation. The functional capabilities of power-operated isolation valves are tested remote manually from the main control room. By observing position indicators and changes in the operation of the affected system, the closing ability of a particular isolation valve is demonstrated. Testable check valves are provided on influent lines whose operability is relied upon.

Test capabilities, incorporated in the primary containment system to permit leak testing of containment isolation valves, are separated into two categories. The first category consists of pipelines that open into the containment and do not terminate in closed loops outside the containment, but do contain two isolation valves in series. Test taps are provided between 6.2-69 REV 24 11/22

FERMI 2 UFSAR the two valves to permit leakage monitoring. The second category consists of pipelines that connect to the reactor cooling system and that also contain two isolation valves in series. A leakoff line is provided between the two valves, and a drain line is provided downstream of the outboard valve. This arrangement permits leakage monitoring of both the inboard and outboard valves. Valves subject to Type C testing are shown in Table 6.2-2.

Excess-flow check valves can be tested by opening a test drain valve downstream of each valve and verifying proper operation.

As these valves are outside the primary containment and are accessible, periodic visual inspection can be performed in addition to the operational check.

The only systems circulating contaminated water after a postulated LOCA are the core spray system (to cool the reactor core) and the RHR system (to remove the heat from the emergency coolant).

The potential sources for leakage are the pump mechanical seals. The available data indicate the leakage from the pump seals to be essentially zero. This is based on the manufacturer's design criteria, its technical manuals, and industrywide experience. Therefore, specifying a leakage limit would be quite arbitrary.

Only a seal failure could result in any significant leakage. This leakage would be indicated by the operation of the sump pumps in either one of the equipment drain sumps or the floor drain sumps located in each of the four corner rooms of the reactor building subbasement.

Sump pump startup is indicated in the control room. Following sump pump startup and operator investigation, the leaking emergency core cooling system (ECCS) pump would be isolated.

Following a postulated LOCA, either one LPCI pump or two core spray pumps are required for core cooling and one RHR pump is required for long-term containment cooling. Should seal failure occur in one of these, there is sufficient redundancy to allow the leaking pump to be removed from service and isolated. Four RHR pumps and four core spray pumps are provided.

Radioactivity releases and resultant doses from this postulated seal leak would be negligible.

6.2.4.2.8 Environmental Qualification Tests Qualification tests required to ensure the performance of the isolation valves under adverse environmental conditions are discussed in Section 3.11.

6.2.4.3 Design Evaluation One of the basic purposes of the primary containment system is to provide a minimum of one protective barrier between the reactor and the environs. To fulfill its role as a barrier, the primary containment is designed to remain intact before, during, and subsequent to any failure involving process systems either inside or outside the primary containment. Where process lines penetrate the primary containment, the penetration has the same integrity as the primary containment structure itself. In addition, the process line isolation valves perform the containment isolation function for leakage through the process lines.

6.2-70 REV 24 11/22

FERMI 2 UFSAR Since a rupture of a large line connected to the reactor coolant system and penetrating the primary containment may be postulated, isolation valves for lines of this type are required to be located within the primary containment. These isolation valves are required to close automatically on various indications of reactor coolant loss. A certain degree of additional reliability is added if a second valve, located outside and as close as practical to the primary containment, is included. This second valve also closes automatically. A single active failure can be accommodated since a second valve is available to perform the containment isolation function. By physically separating the two valves, there is less likelihood that a failure of one valve would cause failure of the second. Series valves of this type are provided with independent power sources.

As an example, the ability of the main steam line penetrations and the associated steam line isolation valves to fulfill the containment isolation objective for several break conditions in the steam line is shown by consideration of various assumed main steam line break locations.

a. The failure occurs inside the drywell, upstream of the inner isolation valve.

Steam from the reactor is released into the drywell, and the resulting sequence is similar to that of the design-basis accident (DBA) except that the pressure transient is less severe since the reactor blowdown rate is slower. Both isolation valves close on receipt of a signal indicating low water level in the RPV. This action provides two barriers within the steam pipe passing through the penetration and prevents further flow of steam to the turbine. Thus, when the two isolation valves close subsequent to this postulated failure, containment integrity is attained and the reactor is effectively isolated from the external environment

b. The failure occurs inside the drywell, and it is assumed that the inner isolation valve is inoperable. Again, reactor steam will blow into the primary containment. The outer isolation valve will close on receipt of a signal indicating low water level in the RPV, and the reactor will become isolated within the primary containment, as delineated above

c. The failure occurs downstream of the inner isolation valve either inside the drywell or within the guard pipe. Both isolation valves will close on receipt of a signal indicating low water level in the RPV. The guard pipe is designed to accommodate such a failure without damage to the drywell penetration bellows.

In addition, the design of the pipeline both supports and protects its welded juncture to the drywell vessel. Thus, the RPV is isolated within the primary containment by the inner isolation valve, and the primary containment integrity is main-tained by closure of the outer isolation valve. It should be noted that this condition provides two barriers between the reactor core and the external environment

d. The failure occurs outside the primary containment between the penetration and the outer isolation valve. Steam will blow directly into the pipe tunnel until the isolation valves are closed automatically. Closure of the inner isolation valve places a barrier between the reactor core and the external environment. This barrier serves to isolate the reactor and maintain containment integrity 6.2-71 REV 24 11/22

FERMI 2 UFSAR

e. The failure occurs outside the primary containment, and it is assumed that the outer isolation valve is inoperable. Containment isolation is established by the inner isolation valve, and containment integrity is maintained as described in Item d., above

f. The failure occurs outside the primary containment between the outer isolation valve and the turbine. Steam will blow directly into the pipe tunnel or the turbine building until both isolation valves are closed automatically. This action isolates the reactor, completes containment integrity, and places two barriers in series between the reactor core and the outside environment Exceptions to the arrangement of isolation valves described above for lines connected directly to the primary containment atmosphere or reactor coolant system are made only in cases in which the above arrangement would lead to a less desirable situation because of required operation or maintenance of the system in which the valves are located.

Isolation valves must be closed before significant amounts of fission products are released from the reactor core during the DBA. Because the amount of radioactive material in the reactor coolant is small, a sufficient limitation of fission product release will be accomplished if the isolation valves are closed before the coolant drops to a level below the top of the reactor core. For a discussion of closure times for Class A and Class B isolation valves, refer to Section 7.3.2.2.

Valves, sensors, and other automatic devices essential to containment isolation are provided with means for periodic testing of their functional performance. Such tests provide reasonable assurance that the primary containment isolation system will perform properly when required.

6.2.4.4 Leak Rate Testing A testing program has been implemented to measure containment leakage rates prior to initial operation of the unit, and to test the primary containment periodically throughout the operating life. The purpose of the testing is to verify that the leakage rate is within allowable limits given in the Technical Specifications and in the Inservice Testing Program for Pumps and Valves (Subsection 5.2.8.7).

The testing program includes performance of Type A tests to measure the overall integrated leakage rates, Type B tests to detect and measure local leakage from certain components, and Type C tests to measure valve leakage rates.

The leakage tests are performed in accordance with the Fermi 2 Primary Containment Leakage Rate Testing Program as defined in the Technical Specifications. The program, which is based on the requirements of 10 CFR 50 Appendix J, Option B, retains certain previously approved exemptions, and utilizes the approach as defined in Regulatory Guide 1.163 (see Appendix A, Subsection A.1.163).

6.2.4.4.1 Type A Tests Type A tests are intended to measure the primary reactor containment overall integrated leakage rate after the containment has been completed and is ready for operation and at periodic intervals thereafter.

6.2-72 REV 24 11/22

FERMI 2 UFSAR After the preoperational leakage rate test, testing will be scheduled in accordance with Fermi 2 Technical Specifications.

The Type A test will be performed using the Absolute Method or other alternative testing methods that have been approved by the NRC, and verification will be achieved by the Superimposed Leak Method, as described in ANSI/ANS 56.8-2002.

Prior to Type A testing, all lines are either isolated or drained and vented to reflect their status following a postulated LOCA. This ensures that Type A test results accurately reflect the most restrictive LOCA conditions. Systems that are provided with isolation capabilities to satisfy GDC 55 or 56 are either normally open to the containment atmosphere or will be vented to the containment during Type A tests. Exceptions to this are systems that must be in operation during the test.

The primary containment is pressurized and depressurized using existing system piping and equipment to the extent possible. Appropriate pressure controls are provided to attain the test pressure and for controlled depressurization to the plant vent stack via existing adsorber filters. Pressurization is carried out under conditions that will minimize containment air humidity and temperature.

Temperature-sensing devices are distributed throughout the containment and at different parts of the structure wherever local temperature variations are expected in the course of the test. Fans are used for air circulation as required to equalize temperatures.

Measurements are taken during each test period to provide a sufficient amount of data to determine leakage rates for the following tests.

a. Preoperational Leakage Rate Test

1. Peak Pressure Test A test was performed at pressure Pa (where Pa is the calculated peak containment internal pressure related to the DBA) to measure the leakage rate Lam (where Lam is the total measured leakage rate at pressure Pa obtained from testing the containment with equipment and systems in a state as close as practical to that which would exist under DBA conditions)

2. Acceptance Criteria Lam shall be no greater than Ld (where Ld is the design leakage rate at pressure Pa, as specified in the Technical Specifications), which conforms to the requirement of 10 CFR 50 Appendix J, Option B that Lam shall be less than 0.75 La (where La is the maximum allowable leakage at pressure Pa). See Table 6.2-1 for pressure and leakage values

3. Results The preoperational leak rate test was concluded on December 7, 1984.

The calculated leak rates at the 95 percent confidence level were below the acceptance criterion of 0.375 weight percent/day. The Appendix J 6.2-73 REV 24 11/22

FERMI 2 UFSAR acceptance criterion at 95 percent confidence level is 0.75 La =

(0.75)(0.50 weight percent/day) = 0.375 weight percent/day. The accuracy of the test was verified by means of a supplemental test.

b. Periodic Leak Rate Tests

1. The peak pressure tests shall be conducted at Pa

2. Acceptance Criteria - same as Item 2 above.

The accuracy of Type A tests will be verified by a supplemental test. The verification is intended to be conducted by the Superimposed Leak Method.

Results from the supplemental test are acceptable provided the difference between the supplemental test data and the Type A data is within 0.25 La.

If this should not be the case, the reason shall be determined, corrective action taken, and a successful supplemental test performed.

6.2.4.4.2 Type B Test The Type B test is intended to detect local leaks and to measure leakage across each pressure-containing or leakage-limiting boundary for the following primary containment penetrations:

a. Contained penetrations whose design incorporates resilient seals, gaskets, or sealant compounds, piping penetrations fitted with expansion bellows, and electrical penetrations fitted with flexible metal seal assemblies

b. Air-lock door seals, including door-operating mechanism penetrations that are part of the containment pressure boundary

c. Doors with resilient seals or gaskets, except for seal-welded doors.

Table 6.2-2 lists those penetrations that require Type B testing. A detailed description of those penetrations is found in Subsection 6.2.1.2.1.

Type B tests (except the test for the air lock) shall be performed and scheduled in accordance with the Primary Containment Leakage Rate Testing Program as described in the Technical Specifications, based on 10 CFR 50 Appendix J, Option B. Air locks shall be tested at 30-month intervals or after maintenance is performed on the air lock. Additionally, the interior and exterior door seals of the air locks shall be tested after each air-lock opening in accordance with the Primary Containment Leakage Rate Testing Program as described in the Technical Specifications, based on 10 CFR 50 Appendix J, Option B.

All components subject to Type B testing are equipped with test connections to allow pressurization with a test medium.

Soap-bubble testing at design pressure Pa will be used, if necessary, to provide a sensitive and rapid method for qualitative determination of leakage over large areas. The quantitative leakage measurements are made by pressurizing the component to be tested with air or nitrogen to design pressure Pa and measuring the amount of gas required to maintain that pressure.

6.2-74 REV 24 11/22

FERMI 2 UFSAR The personnel access lock and equipment access doors are tested for leakage in accordance with approved written procedure, specifically, the Type B test procedures. The drywell personnel access lock has two mechanically interlocked, gasketed doors. These are designed and fabricated to withstand drywell design pressure.

The Type B test for the personnel access lock is conducted in three steps:

a. The exterior door seals are tested by connecting the local leak-rate test (LLRT) panel to a pressure tap, which has been provided, pressurizing the space between the door's testable gasket to design pressure, and measuring the leak rate

b. The interior door seals are tested in a manner similar to that of the external door seals

c. The space between the shut interior and exterior doors is tested by connecting the LLRT panel to a pressure tap, which has been provided, pressurizing to design pressure, and measuring the leak rate. Prior to conducting this step, tie-downs are installed on the interior door to ensure proper seating of the interior door's testable gasket when pressure is applied in a direction that is not normally expected. By design, both the interior and exterior doors seal with internal pressure, thereby providing a better seal as the drywell pressure increases.

When the tie-downs are installed on the interior door, the air lock cannot be operated from within.

The tie-downs are adjusted to permit compression of the gasket until the door is about 1/16 in. away from the frame. The forces exerted on the door during the leak-rate test (Type B) are the sum of the forces caused by the mechanical tie-downs and the forces attributable to the test pressure.

6.2.4.4.3 Type C Test Table 6.2-2 lists all containment isolation valves that require Type C testing, plus a sketch of piping configurations and test connections.

Type C tests will be performed and scheduled in accordance with the Primary Containment Leakage Rate Testing Program as described in the Technical Specifications, based on 10 CFR 50 Appendix J, Option B.

The boundaries for each test will be established with consideration for minimizing the test volume. Test connections for venting, draining, and pressurization are provided on penetration piping that includes valves requiring Type C testing. To the extent practicable, the piping between the containment penetrations and the test connection isolation valves is minimized.

The tests shall be performed by local pressurization applied in the same direction that the valve would be required to perform its safety function, unless it has been determined that applying the pressure in the opposite direction will provide equal or more conservative results.

6.2-75 REV 24 11/22

FERMI 2 UFSAR Valves listed in Table 6.2-2 as being Type C tested, except those having a water seal which can be maintained for at least 30 days after an accident requiring containment isolation, shall be pressurized with air or nitrogen to the design pressure Pa. Valves that have a water seal shall be pressurized with that fluid to a pressure of not less than 1.10 Pa.

Type C LLRT testing is not required for containment isolation valves that are located in piping of systems which penetrate the Torus and terminate below the minimum water level in the Torus when the systems are closed both inside and outside of containment. The Torus is designed and operated so that it is always filled with water. The supply of water in the Torus is assured during all design basis post-accident modes of operation. Consequently, the subject isolation valves will remain sealed by the water.

The water seal inside the Torus, in conjunction with the design of the piping associated with the penetrations, is a passive post-accident containment bypass leakage barrier. It precludes any direct communication between the post-accident Primary Reactor Containment atmosphere and the subject Containment Isolation Valves, thereby eliminating the possibility of post-accident containment bypass leakage. The torus is assured to maintain its level 30 days post accident, as described in Section 6.2.4.4.3. As such, the torus is not a seal-water fluid system as intended by Appendix J. Therefore, 10 CFR 50, Appendix J, Type C water leak rate testing for the lines and valves is not appropriate and is not necessary to ensure post-accident, containment integrity.

The combined leakage rate for all penetrations and valves subject to Type B and C tests shall be less than 0.60 La. Leakage from those valves that are sealed with a fluid from a seal system may be excluded when determining the combined leakage rate provided that

a. The fluid leakage limit is based on a radiological analysis of the plant site

b. The installed isolation valve seal system fluid inventory is sufficient to ensure sealing function for at least 30 days at a pressure of 1.10 Pa.

Test, vent, and drain (TVD) connections on Class 1 systems which are a part of the containment boundary are provided with at least two isolation valves and are sealed with a threaded pipe cap except for the vents on the RHR return piping inside the drywell which are provided with one isolation valve and a threaded cap. All other TVD connections which are a part of the containment boundary are provided with at least one isolation valve and sealed with a threaded pipe cap. Test, vent, and drain connections shall be under administrative control, and they shall be subject to periodic surveillance to verify their integrity and to verify the effectiveness of the administrative controls in ensuring closure.

There are six types of valves that are not tested in the accident direction: globe valves, gate valves, ball valves, relief valves, stop check valves, and butterfly valves. Each valve type is discussed separately in the following paragraphs.

Globe Valves (Note 2, Table 6.2-2)

All globe valves that are tested in the reverse direction have test pressure applied beneath the disk. The seating force of a globe valve is the vector sum of the actuator force and the fluid force on the valve plug. For all globe valves being considered, accident pressure is above the seat and is thus acting in the same direction as the actuator force, tending to close the valve.

When a valve of this configuration is tested in the reverse direction (pressure under the seat),

test pressure will be acting in opposition to the actuator force, thus tending to unseat the 6.2-76 REV 24 11/22

FERMI 2 UFSAR valve. Therefore, the resultant force on the seating surface will be less when test pressure is applied in the reverse direction than when pressure is applied in the accident direction. As there is only one seating surface where the fluid pressure is applied in a direction opposite to the actuator force, leakage will tend to increase due to the reduced seating load. Because leakage during a test in the reverse direction tends to be greater than when fluid pressure is applied in the accident direction, a test in the reverse direction is conservative.

Gate Valves (Note 4, Table 6.2-2)

All gate valves that are not tested in the accident direction are wedge-disk-type gate valves.

In lieu of testing these valves in the accident direction, Edison tests them through the bonnet.

The gate valve may be tested through a body/bonnet tap. This valve has a tap through which the body/bonnet area is pressurized. Leakage is measured through both seating surfaces along with leakage through the bonnet and packing. Compared with testing in the accident direction, this method of leakage testing is more conservative.

Butterfly Valves (Note 11, Table 6.2-2)

Twenty-seven butterfly valves serve as containment isolation valves and are subject to Type C leak testing. Twelve of the valves are inboard isolation valves, and the remaining 15 are outboard isolation valves.

During Type C testing, the pipe volume or test volume between the inboard and outboard valves will be pressurized. Pressurizing between the valves is necessary because test volumes cannot be established on the containment side of the inboard isolation valve given the present valve and line configurations. Thus, the inboard valves will have the test differential pressure applied in the reverse direction to the accident pressure.

Of the ten inboard valves located outside the primary containment, eight of the valves will have their pipe-to-valve flanges nearest containment seal welded to ensure a leaktight pressure boundary. Because of this seal weld, the inboard valves will have to be maintained in place. In order to change the valve seat, access from the disk side of the valve is necessary. Therefore, for all inboard valves that are located outside the primary containment, the valve disk must face away from the primary containment. There are 10 inboard valves located outside the primary containment. With this orientation, stem leakage of the inboard valves is not measured while pressurizing the test volume. Additionally, two of the inboard containment isolation valves are located inside the primary containment and are flanged into place.

For Type C testing, the stem leakage is measured by pressurizing to Pa through the stem vent and adding this stem leakage to the test volume leakage. The valve manufacturer has stated that the leakage through the stem is not dependent on the direction of the differential pressure. Consequently, pressurizing through the stem vent will yield stem leakage results that are conservative or equivalent to applying the pressure differential in the accident direction.

There are two inboard isolation valves on the inside of the containment. These valves have the disk facing the containment so that the valve seats are accessible. Pressurizing the test volume between the inboard and outboard valves will provide the stem leakage along with the seat leakage.

6.2-77 REV 24 11/22

FERMI 2 UFSAR All the outboard valves have the disk facing toward the containment; thus test and accident differential pressures are in the same direction.

Relief Valves (Note 29, Table 6.2-2)

In addition to the safety/relief valves on the main steam lines, there are 17 relief valves that blow down to the pressure suppression chamber and therefore are classified as isolation valves. During a LOCA, containment pressure will be acting over the relief valve seat.

Therefore, the direction of the accident pressure differential will tend to seat the valves.

Of the 17 relief valves, 15 of them will not be Type C LLRT tested. These 15 relief valves are located in piping of systems which penetrate the Torus and terminate below the minimum water level in the Torus. The Torus is designed and operated so that it is always filled with water. The supply of water in the Torus is assured during all design basis, post-accident modes of operation. Consequently, the subject isolation valves will remain sealed by the water.

The water seal inside the Torus, in conjunction with the design of the piping associated with the penetrations, is a passive, post-accident containment bypass leakage barrier. It precludes any direct communication between the post-accident Primary Reactor Containment atmosphere and the subject CIVs, thereby eliminating the possibility of post-accident containment bypass leakage. The Torus is assured to maintain its level 30 days post accident, as described in Section 6.2.4.4.3. As such, the torus is not a seal-water fluid system as intended by Appendix J. Therefore, 10 CFR 50, Appendix J, Type C water leak rate testing for the lines and valves is not appropriate and is not necessary to ensure post-accident containment integrity.

The two remaining valves in the CGC system will be in-situ tested in the accident direction at a pressure of Pa.

Stop Check Valves (Table 6.2-2)

There are four stop check valves in the HPCI and RCIC systems. All of these stop check valves have uncoupled globe style disks and motor operators.

Operating procedures provide instructions for closing these stop check isolation valves following a post-LOCA event when the HPCI and RCIC systems are no longer needed.

These four stop check valves will not be LLRT Type C tested. All four are located in piping of systems which penetrate the Torus and terminate below the minimum water level in the Torus. The Torus is designed and operated so that it is always filled with water. The supply of water in the Torus is assured during all design basis, post-accident modes of operation.

Consequently, the subject isolation valves will remain sealed by the water.

The water seal inside the Torus, in conjunction with the design of the piping associated with the penetrations, is a passive, post-accident containment bypass leakage barrier. It precludes any direct communication between the post-accident Primary Reactor Containment atmosphere and the subject Containment Isolation Valves thereby eliminating the possibility of post-accident containment bypass leakage. The torus is assured to maintain its level 30 days post accident, as described in Section 6.2.4.4.3. As such, the torus is not a seal-water fluid system as intended by Appendix J. Therefore, 10 CFR 50, Appendix J, Type C water 6.2-78 REV 24 11/22

FERMI 2 UFSAR leak rate testing for the lines and valves is not appropriate and is not necessary to ensure post-accident, containment integrity.

Ball Valves (Note 13, Table 6.2-2)

There are 23 ball valves used for containment isolation; 10 of these are tested in the forward direction and 13 are tested in the reverse direction. All of these valves were manufactured by Jamesbury and are air operated and spring assisted to fail in the closed position.

Valves of this type have the same sealing characteristics in either direction. Consequently, test results obtained in the present configuration (i.e., reverse direction) are equivalent to testing in the accident direction. Additionally, these valves have a "corner seal" design on the stem and stem packing. This design eliminates stem leakage.

The spring assist merely rotates the ball valve in its seat. It does not increase the seat pressure; therefore, the spring assist has no effect on the leakage regardless of the test direction.

6.2.5 Primary Containment Combustible Gas Control The NRC amended 10 CFR 50.44, Standards for combustible gas control system in light-water-cooled power reactors on October 16, 2003 to eliminate the requirements for hydrogen recombiners. The hydrogen recombiner Technical Specification requirements were subsequently removed by License Amendment 159, dated March 15, 2004. Regulatory Guide 1.7 was revised in March 2007 to reflect the amended 10 CFR 50.44. The Combustible Gas Control System (CGCS) has been retired in place with its electrical circuits de-energized and fluid process piping isolated from primary containment with redundant locked-closed isolation valves. Combustible gas control of the primary containment is provided by inerting the primary containment with nitrogen.

General Design Criterion 41 of 10 CFR 50, Appendix A, requires that systems be provided to control the concentration of hydrogen or oxygen and other substances that might potentially be released to the containment atmosphere. Title 10 CFR 50, Section 50.44, establishes the standards for these systems. In Fermi 2, no substances of a combustible nature (other than hydrogen and oxygen) would potentially be released in significant amounts to the containment atmosphere under LOCA conditions. To ensure that containment integrity is not potentially impaired due to buildup of combustible gases following a LOCA, Fermi 2 has an inert containment atmosphere with mixing capability. Hydrogen and oxygen concentrations are monitored. A purge system that uses the reactor building ventilation system or the SGTS is available. The purge system is not required to be a qualified system.

6.2.5.1 Deleted 6.2.5.2 System Design 6.2.5.2.1 Deleted 6.2-79 REV 24 11/22

FERMI 2 UFSAR 6.2.5.2.2 Design Features The CGCS is retired, but all components remain in place as shown in the piping and instrumentation diagram in Figure 6.2-23. The primary containment isolation valves associated with the CGCS have been manufactured, fabricated, and tested in accordance with the requirements of the ASME B&PV Code Section III, Class 2, 1971 edition, summer 1973 addenda.

6.2.5.2.3 Hydrogen/Oxygen Monitoring Because Fermi 2 has an inerted primary containment atmosphere during reactor operation, the oxygen concentration, in the event of a LOCA, is the limiting parameter. The hydrogen and oxygen concentrations are continuously monitored, and are displayed in the main control room. Grab samples are obtained on a weekly basis to ensure the correct operation of the monitoring system. Samples are also taken prior to containment entry. Subsection 7.6.1.12 contains a description of the hydrogen/oxygen monitoring system. To ensure representative sampling, multiple ports allow gas to be drawn into the monitoring system from several locations in the containment. An alarm indicates when the oxygen concentration reaches a preset level.

6.2.5.2.4 Deleted 6.2.5.2.5 Containment Purge Containment purge capability is provided for the purpose of removing fission product activity from the containment atmosphere and pressure control. Containment purge can also be utilized for combustible gas control following a significant beyond design-basis accident.

Piping and valves are provided, connecting the containment atmospheres to the SGTS or reactor building heating, ventilation, and air conditioning (HVAC) system as shown in Figure 9.3-14. The purge system is comprised of the large purge piping used for purging and inerting and a smaller on-line purge system used for nitrogen vent/makeup and pressure control. Isolation valves and piping at the primary containment boundary meet the requirements of Section III ASME B&PV Code, Class 2, and are designed in conformance with Category I requirements. The SGTS treats the containment atmosphere prior to its release to the environment.

The drywell air purge inlet and vent outlet lines are 24 in. in diameter while the suppression chamber purge and vent lines are 20 in. in diameter. Both suppression chamber and drywell outboard isolation valves are supplied with a 6-in. bypass for use when the larger valve is to remain closed. The drywell bypass valve and suppression chamber bypass valve will isolate automatically.

During a power increase and drywell temperature increase, the drywell vent bypass line is opened periodically to maintain a constant drywell pressure. The drywell vent bypass line is also used to alleviate pressure buildup due to leakage from pneumatic solenoid valves. The purge system is not used during normal reactor operation to reduce airborne activity in the primary containment.

6.2-80 REV 24 11/22

FERMI 2 UFSAR Containment vent line effluents are directed to the reactor building ventilation exhaust duct or to the SGTS for release. See Figure 6.2-20. The purge lines can open to the secondary containment volume, which is processed by the SGTS.

Because purging is initiated under the reactor operator's control, and the effluent from the SGTS is monitored for radioactivity, the incremental dose at the low-population zone during the purging will be controlled to ensure that the purge dose does not cause the total dose (LOCA plus purge dose) to exceed the limit specified in 10 CFR 100. High-radiation monitors prior to the reactor building HVAC exhaust fans isolate the containment purge valves and initiate the SGTS. The purge/inert valves comply with BTP CSB 6-4 of SRP 6.2.4. as follows:

a. The design basis for the valves includes the higher post-LOCA pressures

b. The operation of Fermi 2 containment purge and vent valves is in accordance with the Technical Specifications and is consistent with the guidance of the BTP for use of a single supply and exhaust line

c. The nitrogen purge supply valves for the torus and drywell are 6-in. and 10-in.

valves, respectively. The exhaust line from both the torus and drywell are provided with 6-in. valves in parallel with the outboard isolation valve

d. Automatic isolation occurs on low reactor water level (level 2), high drywell pressure, or high radiation. The air-operated isolation valves fail closed on loss of air. The motor-operated isolation valves fail as is, but are only used in series with an air-operated isolation valve. Table 6.2-2 defines which of the above criteria are applicable to each specific isolation valve. The valves are listed in this table under penetration numbers X-25, X-26, X-205C, X-205D

e. The purge and vent valve closure times are consistent with the 5-sec requirement of the BTP

f. Debris screens have been provided for the purge valves inside the drywell to prevent debris from becoming entrained in the valves

g. The purge and vent system is not relied on for temperature and humidity control. The drywell cooling system is described in Subsection 9.4.5, and the vent/makeup of nitrogen for the containment is described in Subsection 9.3.6

h. Isolation valve testing of specific purge and inlet isolation valves is indicated in Table 6.2-2. The testing program is described in Subsection 6.2.4.4. The operability of the isolation function and the purge valve leakage rate are verified in accordance with the Technical Specifications

i. The radiological consequences of a LOCA while purging have been evaluated both specifically for Fermi 2, and generically by the NRC. Both a Fermi 2 specific analysis and the NRC's "Generic Evaluation of the Radiological Consequences of Accidents While Purging or Venting at Power-Multi-Plant Action Item B-24" indicate that while venting or purging at power, the dose contribution through open valves is small

j. The SGTS is downstream of the purge system isolation valves. Operation of the SGTS while purging will be limited and controlled to protect the SGTS from 6.2-81 REV 24 11/22

FERMI 2 UFSAR loss of function from the environment created by the escaping air and steam.

The Technical Specifications delineate the limits on the use of the SGTS while purging or venting. This limit is further controlled by the Technical Specifications, which require that only one division of the SGTS be used.

k. Fermi 2 net positive suction head (NPSH) requirements for emergency core cooling system (ECCS) pumps are in conformance with Regulatory Guide 1.1.

The Regulatory Guide allows no credit for positive containment pressure in the NPSH calculations. Therefore, a reduced containment pressure due to purging has no safety consequence on ECCS pump NPSH margins.

6.2.5.2.5.1 Hardened Torus Vent System A hardened torus vent system has been installed at Fermi 2 under the 10 CFR 50.59 process in response to NRC Generic Letter 89-16, "Installation of Hardened Wetwell Vent".

During severe accidents which are outside the design basis, plant emergency procedures direct the operators to vent the wetwell airspace to prevent exceeding the primary containment pressure limit. Venting permits controlled releases by preventing permanent damage to the drywell. In addition, venting from the wetwell scrubs fission products from the effluent and reduces radioactive releases. The benefits of venting over a rupture of the drywell are reduced radiological consequences. The purpose of a hardened wetwell vent system is to provide a reliable design consistent with the safety objective of the plant emergency procedures.

The vent is sized to meet or exceed the BWR Owners Group (BWROG)/NRC general design criteria which require that under the conditions of (1) a constant heat input at a rate equal to 1.1 percent of rated thermal power and (2) containment pressure is equal to the primary containment pressure limit (PCPL), the exhaust flow through the vent is sufficient to prevent the containment pressure from increasing.

The hardened torus vent system consists of a 10-inch, Schedule 40, carbon-steel pipe routed from the 24-inch standby gas treatment system (SGTS) inlet header on the fifth floor Reactor Building through the Reactor Building siding into a stack which discharges at an elevated location. The 10-inch pipe contains two torus vent secondary containment fail closed isolation valves (TVSCIV), T4600F420 and T4600F421. The TVSCIVs air-operated butterfly valves (AOVs) are normally supplied by Division II non-interruptable control air supply (NIAS). The AC solenoid valves are normally powered by the reactor protection system (RPS) and divisionally separated. The inboard AOV is powered by Division I RPS and the outboard AOV is powered by the Division II RPS. Spectacle flanges, to facilitate maintenance of the AOVs, are installed upstream and downstream of the AOVs, with one outboard spectacle flange located outside the Reactor Building. Controls and position indications for the AOVs are located in the control room and are keylocked to prevent inadvertent positioning.

The piping from the first spectacle flange downstream from the existing header up to and including the second spectacle flange is Class D, QA Level I, and Seismic Category I. This is consistent with the original classification of SGTS. From the second spectacle flange through the remainder of the stack is QA Level 1M and Seismic II/I. The TVSCIVs maintain secondary containment integrity and are Class D, QA Level 1, Seismic Category I, and fail 6.2-82 REV 24 11/22

FERMI 2 UFSAR safe. The valves have been environmentally qualified to NUREG-0588 Category 2B (Mechanical) for pressure boundary integrity purposes. The leak tightness of the TVSCIVs is ensured by performing the secondary containment drawdown test at regular intervals.

Air supply for the primary containment isolation valves T4600F400, F401, and F412 in the SGTS has been changed from interruptable air supply (IAS) to Division 2 NIAS to improve venting reliability.

The pilot AC solenoid valves for the TVSCIVs are supplied by NIAS and are Class D, QA Level I, Seismic Category I, and have been environmentally qualified to NUREG-0588 Category 2B (Mechanical) and 2C (Electrical) to maintain the pressure boundary integrity of NIAS. The limit switches are QA Level non-Q, Seismic Category II/I.

A radiation monitor is installed on the 4th floor of the Auxiliary Building to enable monitoring of any radiological releases when the vent is open. The monitor is QA Level 1M, Seismic Category II/I, and has indication and alarm in the control center to alert the operators of a radiological release. The monitor also has an interface with the Integrated Plant Computer System (IPCS). Arrangement details are shown in Figure 11.4-4. The details of the radiation monitoring system are described in Subsection 11.4.3.11.3.

The torus hardened vent system components which require electrical power are the radiation monitor, solenoid valves, and the controls of the hardened vent air operated isolation valves.

There are two TVSCI valves in series that are keylock switch controlled and fail closed. To preclude any inadvertent opening of the vent line to the atmosphere and jeopardizing secondary containment integrity due to a single failure, the two TVSCIV pilot solenoid valves are powered by different Divisions of RPS. The radiation monitor is powered as described in Subsection 11.4.3.11.3.

The hardened vent system is designed to be used for events that are outside the design basis of the plant. Therefore, the system does not comply with the design basis described in Subsection 6.2.5.1. The RPS power supply is selected to power the above components for reliable operation of the system. The RPS branch circuits feeding the hardened vent system components are adequately protected through properly coordinated safety grade fuses. Since RPS is a fail-safe system and the branch circuits used in the hardened vent system are properly protected, any single failure in the hardened vent system cannot prevent the RPS' ability to scram the reactor when it is needed. The power supply to each of these valves is divisionally separated and each valve control circuit is defeated through a normally open contact of a qualified keylocked selector switch; thus no single failure can inadvertently open the vent path nor can it prevent the ability of the RPS system from performing the scram action when it is needed. Furthermore, the RPS power to non-safety grade torus hardened vent system components is consistent with Fermi 2 design practices and by design any potential of full scram due to single failure or non-Q component failure in the hardened vent system is avoided. Therefore, the RPS system's intended design function to safely shut down the reactor is not compromised.

Beyond Design Basis Events:

As part of the response to the Fukushima Event, the NRC issued Order EA-13-109 and Interim Staff Guidance (ISG) JLD-ISG-2013-02 which requires Licensees:

6.2-83 REV 24 11/22

FERMI 2 UFSAR

a. Provide a reliable Hardened Containment Vent System (HCVS) to assist in preventing core damage when heat removal capability is lost.

b. Ensure that venting functions are also available during sever accident conditions.

Sever accident conditions involving extensive core damage include elevated temperatures, pressures, radiation levels and combustible gas concentrations, such as hydrogen and carbon monoxide. This includes accidents involving a breach of the reactor vessel by molten core debris.

To comply with this order Fermi has modified the existing HCVS as follows:

a. Installed an alternate pneumatic gas supply to containment isolation valves, TVSCIVs and boundary valves associated with the Hardened Vent to allow control during and after a severe event.

b. Provided required panels, 130 VDC power supply, 120 VAC power supply, required instruments, and indications at panels outside and inside the control room.

c. Modified the HCVS exhaust stack to lengthen the stack, install a check valve to preclude backflow of air into the pip, and install a weather shroud.

During normal plant operation and during Design Basis Accidents the Hardened Containment Vent Equipment is de-energized and/or isolated. Upon declaration of a Hardened Containment Venting Scenario, the necessary hardened vent equipment is activated to support mitigation of the event. The intent being to address the station needs for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> until the FLEX equipment can be brought on-line.

The provision of these modifications establishes alternate means of providing motive force (compressed gas) and electric power to assure the capability of the Hardened Vent to remain operable during and after a severe accident.

6.2.5.3 Safety Evaluation The corrosion of containment materials was considered as a potential source of hydrogen.

The corrosion of aluminum, zinc, and zinc-base paints located either in the drywell or torus was evaluated for a potential source of hydrogen. It was determined that these potential sources were insignificant for the following reasons:

1. The containment spray solution, if used, does not contain any chemical additives. The pH of the spray solution is 6.5 to 7.0

2. Aluminum corrosion is highly pH dependent. The Oak Ridge National Laboratory (ORNL) experiments described in Reference 29 have determined that at high pH (approximately 9.3), the corrosion of aluminum was about 100 times greater than at a pH 6.5 to 7.5, which was shown to be negligible

3. Although the corrosion of zinc does not exhibit the same pH dependence as aluminum, the corrosion of both zinc and aluminum is highly temperature dependent. The post-LOCA time/temperature profile in the drywell and torus is much less severe than that experienced in typical BWR 6.2-84 REV 24 11/22

FERMI 2 UFSAR containments. The magnitude, as well as duration, of elevated temperature, is short-lived as shown in Figures 6.2-27, 6.2-29, 6.2-30, and 6.2-16 Because of these reasons, the corrosion of aluminum and zinc is relatively insignificant and does not represent a significant source of hydrogen.

6.2.5.4 Deleted 6.2.5.5 Deleted 6.2.5.6 Materials There are no materials in the CGC system subject to radiolytic or pyrolytic decomposition under the conditions that would exist following a postulated LOCA. The principal materials used are

a. The heated components forming the containment boundary of the system are type 304 (or equivalent) stainless steel in accordance with the appropriate ASME material specifications, and Section III, Class 2 requirements

b. Unheated components forming the containment boundary conform with Section III, Class 2 of the ASME Code. Carbon steel, per SA-106, Grade B or SA-333, Grade 6, is used for piping, SA-216 for castings, and code allowable carbon steels for plate, forgings, weld rod, and other components, as appropriate.

6.2.6 Main Steam Isolation Valve Leakage Control System Note: As a result of the re-analysis of the Loss-of-Coolant Accident (LOCA) using an Alternative Source Term (AST) methodology, it is no longer necessary to credit the Main Steam Isolation Valve Leakage Control System (MSIVLCS) for post-LOCA activity leakage mitigation.

6.2.6.6 Design of Main Steam System Piping and Valves The main steam piping system, from the outboard MSIV to the appropriate anchor positions of all branch lines downstream of the third MSIV, is seismically qualified. The main portion of the main steam system is located in the turbine building, which is seismically qualified to withstand the effects of an operating-basis earthquake (OBE) or a safe-shutdown earthquake (SSE) event.

The main steam system has been seismically analyzed to ensure its integrity after either an OBE or an SSE event. The section of main steam piping analyzed begins at the anchor outside the primary containment and ends at the anchor in each of the branch lines downstream of the third MSIV. The seismic analysis of this portion of the main steam piping and included valves verifies that piping structural and pressure integrity will be maintained, and that included valves will remain in the elastic stress range after either an OBE or an SSE event.

6.2-85 REV 24 11/22

FERMI 2 UFSAR 6.2.6.6.1 Main Steam Lines The main steam lines and branch connections downstream from the outboard containment isolation valve are classified as Group D, where these sections of pipes shall meet all pressure integrity requirements of Group D.

6.2.6.6.2 Valves in Branch Lines Connected To Main Steam Lines The block valve(s) in branch lines connected to the main steam lines downstream of the outboard MSIV shall meet all the pressure integrity requirements of Group D.

6.2-86 REV 24 11/22

FERMI 2 UFSAR 6.2 CONTAINMENT SYSTEMS REFERENCES

1. GE Nuclear Energy, "Generic Guidelines for General Electric Boiling Water Reactor Power Uprate," Licensing Topical Report NEDC-31897P-1, Class III, (Proprietary), June 1991.

2. GE Nuclear Energy, "Generic Evaluations of General Electric Boiling Water Reactor Power Uprate," Licensing Topical Report NEDC-31984P, Volumes I and II, Class III, (Proprietary), July 1991.

3. Letter from Detroit Edison Co. to US Nuclear Regulatory Commission, "Proposed License Amendment - Uprated Power Operation," NRC-91-0102, September 24, 1991.

4. Letter from US Nuclear Regulatory Commission to Detroit Edison, "Amendment No. 87 to Facility Operating License No. NPF-43 (TAC No. M82120)," September 9, 1992.

5. General Electric Company, Mark I Containment Program Load Definition Report, NEDO-21888, Rev. 2, November 1981.

6. General Electric Company, Mark I Containment Program Plant Unique Load Definition--Enrico Fermi Atomic Power Plant: Unit 2, NEDO-24568, Rev. 3, April 1982.

7. U.S. Nuclear Regulatory Commission, Safety Evaluation Report Mark I Containment Long-Term Program, NUREG-0661, July 1980.

8. U.S. Nuclear Regulatory Commission, Suppression Pool Temperature Limits for BWR Containment, NUREG-0783, July 1981.

9. Nuclear Technology Incorporated, Enrico Fermi Atomic Power Plant, Unit 2, Plant Unique Analysis Report, DET-04-028-1, 2, 3, 4, 5, San Jose California, April 1982.

10. Nuclear Technology Incorporated, Enrico Fermi Atomic Power Plant, Unit 2, Plant Unique Analysis Report, DET-19-076-06, San Jose, California, June 1983.

11. Joint G. E. and PG&E Report, Pressure Suppression Test Program, Appendix I, "Preliminary Hazard Summary Report," Bodega Bay Atomic Park, Unit 1, December 1962.

12. Letter from Detroit Edison to NRC,

Subject:

Resubmittal of Fermi 2 Vacuum Breaker Report, NE-85-0707, May 7, 1985.

13. Fermi 2 Design Calculation DC-4968 Vol I Revision C, Primary Containment Negative Pressure Analysis.

14. General Electric Company, The GE Pressure Suppression Containment Analytical Model, NEDO-10320, April 1971; Supplement 1, May 1971; Supplement 2, January 1973.

15. General Electric Co., "The General Electric Mark III Pressure Suppression Containment System Analytical Model," NEDO-20533, June 1974.

16. Decay Heat Power in Light Water Reactors", ANSI/ANS 5.1 - 1979, Approved by American National Standards Initiative, August 29, 1979.

6.2-87 REV 24 11/22

FERMI 2 UFSAR 6.2 CONTAINMENT SYSTEMS REFERENCES

17. General Electric Co., "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident," NEDO-23785-1-A Volume III, October 1984.

18. Structural Design Assessment for Safe-End Break Enrico Fermi Atomic Power Plant - Unit 2, Report SL-3647, Revision 2, March 14, 1980.

19. F. L. Singer, Strength of Materials, Second Edition, Harper College Books, 1962.

20. D. W. Pyatt, Enrico Fermi 2 Reactor Vessel - Sacrificial Shield Annulus Pressurization Analysis, NUS Corporation, Report NUS-3129, March 1978.

21. Multiple Dynamics Corporation, "Evaluation of Containment Coatings," Report No.

DECO-12-2191, Rev. 4, June 1985.

22. Letter from Detroit Edison Co. to US Nuclear Regulatory Commission, "Detroit Edison Response to NRC Plant Systems Branch (SPLB) Verbal Request for Additional Information on Fermi 2 Power Uprate Submittal (TAC No. 82102),

NRC-92-0095, August 13, 1992.

23. General Electric Company, Enrico Fermi Atomic Power Plant Unit 2 Suppression Pool Temperature Response, NEDC-24388-P, December 1981.

24. D. P. Siegwarth and M. Siegler, Detroit Edison Standby Gas Treatment System Gasketless Filter Test Series, NEDC-12431, Class I, General Electric Company, January 30, 1974.

25. GOTHIC, Generation of Thermal Hydraulic Information for Containment, Version 8.0.

25a. U.S. Nuclear Regulatory Commission Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 98 to facility operating license No. NPF-43, 22nd April 1994.

26. TDVCAL DC-6132 VOL I, ANALYSIS OF LOSS OF COOLANT ACCIDENT (LOCA) USING ALTERNATIVE SOURCE TERMS, Ed. File# P1-17130

27. Deleted

28. Deleted

29. Cotrell, W. B., ORNL Nuclear Safety Research and Development Program Bimonthly Report for January-February 1971, Oak Ridge National Laboratory, ORNL-TM-3842, May 1971.

30. General Electric-Hitachi, Licensing Topical Report: Generic Guidelines and Evaluations for General Electric Boiling Water Reactor Thermal Power Optimization, NEDC-32938P-A, Revision 2, May 2003.

31. General Electric - Hitachi, Validation of LBLOCA Initial Primary System Energy Distribution for Fermi 2 GEH Letter 303881-3; DSN 000N6651.

32. GENE 0000 0054 0856 R0, Edison File R1-8030 6.2-88 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa I. General Information Drywell Torus A. Calculated peak pressure, Pa, psig 49.9 28.3 B. Maximum allowable pressure, psig 62 62 C. Design temperature, °F 340 281 D. Free volume, ft3 163,730 130,900 E. Design leak rate, Ld, percent/day 0.5 0.5 F. Maximum allowable leak rate, La, percent/day 0.5 0.5 II. Initial Conditions Short-Term Analysis (M3CPT Code)

INPUT PARAMETER VALUE Core Thermal Power, Mwt 3,499 (102% of 3430 MWt)

RPV Dome Pressure, psia 1,063 Core Inlet Enthalpy, Btu/lbm 531.1 Initial Liquid Mass in RPV, lbm 640,500 Feedwater Addition to RPV 0.

Drywell volume, ft3 163,730 Initial Drywell Pressure, psig 0.75 Initial Drywell Rel., Humidity, % 20 Initial Drywell Temperature, °F 145 Vent Flow Area, ft2 240.9 Vent Flow Loss Coefficient 5.51 Vent Submergence, ft 3.33 Suppression Pool Volume, ft3 124,220 Page 1 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa INPUT PARAMETER VALUE Wetwell Airspace Volume, ft3 127,760 Suppression Pool Temperature, °F 95 Wetwell Airspace Pressure, psig 0.75 III. Initial Conditions Long-Term Analysis (SUPERHEX Code)

INPUT PARAMETER SUPERHEX VALUE Core Thermal Power, Mwt 3,499 (102% of 3430 MWt)

Vessel Dome Pressure, psia 1,063 Feedwater Addition, lbm 607,638 Decay Heat ANS/5.1 + 2 Drywell Free Volume, ft3 163,730 Supression Pool Volume, ft3 117,161 Initial Suppression Pool Temp, °F 95 Initial Wetwell Air Temp, °F 95 Initial Wetwell Relative Humidity, % 100 Wetwell Airspace Free Volume, ft3 134,819 RHR HXR K, Btu/sec - °F 321 (original analysis, loss of one division of AC) 366 (loss of one division of RHRSW, only)

See Section 6.2.2.3 RHR Service Water Temperature, °F 80 - 90 RHR Pump Heat, Hp 2,100 LPCS Pump Heat, HP 1,600 Page 2 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa Time to turn on RHR, minutes 20 Initial Drywell Relative Humidity, % 20 Initial Drywell Pressure, psia 15.45 Initial Drywell Temperature, °F 145 Initial Wetwell Pressure, psia 15.45 IV. Engineered Safety Features Systems Information Full Capacity High-pressure coolant injection No. of pumps 1 No. of lines 1 Flow rate, gpm 5,000 Core spray No. of pumps 4 No. of lines 2 Flow rate (rated), gpm/line 6,350 No. of spargers 2 Low pressure coolant injection mode of RHR system No of pumps 4 No. of lines 2 Flow rate, gpm/line 25,860 Heat exchangers (RHR system)

Type - inverted U-tube, single pass shell, multi-pass tubes, vertical mounting Number 2 Page 3 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa Heat transfer areas, ft2 7,320 Overall heat transfer coefficient 321 (original analysis - loss of one division of AC.)

366 (loss of one division of RHRSW, only.)

See Section 6.2.2.3 Flow of pumps, gpm Shell-side 10,000* with one RHR pump Tube-side 9,000**

Source of cooling water RHR service water Flow begins Manual, approximately 1200 sec (20 minutes)

Automatic depressurization system Total number of safety/relieve valves 15 No. actuated on ADS 5 Drywell spray (RHR system)

No. of pumps 4 No. of lines 2 Flow rate gpm/line 1 pump 9,500 Suppression pool spray (RHR system)

No. of pumps 4 No of lines 2 No. of headers 1 Flow rate, gpm/line Page 4 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa 1 pump 500 RHR heat exchanger performance maintained to assure credited overall heat transfer coefficient based on an RHR heat exchanger flow of 9250 gpm.

RHRSW pump flow reduces below 9,000 gpm with time due to the RHR reservoir evaporative and drift losses.

V. Assumptions Used in Pressure Transient Analysis Feedwater valve closure time Instantaneous MSIV closure time, seconds 3.5 Scram time, seconds 1 Liquid carryover, percent 100 VI. General Information for the Pressure Suppression Type Containment Drywell Value Maximum code allowable pressure, psig 62 Internal design pressure, psig 56 External design pressure, psig 2 Design temperature, °F 340 Suppression Pool Maximum code allowable pressure, psig 62 Internal design pressure, psig 56 External design pressure, psig 2 Design temperature, °F 281 Drywell free volume, including vent system (minimum), 163,730 ft3 Suppression pool free (air) volume, ft3 Page 5 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa Analytic 134,819 Tech Spec 130,900 Suppression pool water volume, ft3 Analytic 117,161 Tech Spec 121,080 Vent submergence, ft Minimum, ft 3 Maximum, ft 3.33 Vent loss coefficient 5.51 Pool cross sectional area, ft2 731 Pool depth (normal), ft 14 ft 6 in.

No. of vents 8 Nominal vent diameter, ft 6 Nominal vent line area, ft2 226 No. of downcomers 80 Nominal downcomer diameter, ft 2 Drywell free volume/pressure suppression chamber free 1.25 volume Deleted Containment heat removal capability per loop, using 66.5 x 106 85°F service water and 165 °F pool temperature; 1 RHR and 2 service water pumps, Btu/hr VII. Recirculating Line Break Accident Initial Conditions and Calculated Response Value Effective accident break area (total), ft2 4.1 Page 6 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa Componentsof effective break area Recirculation line (area), ft2 3.5 Equalizer line (area), ft2 N/A RWCU line (area), ft2 0.07 Jet pumps (area), ft2 0.55 Break area/ vent area 4.1

= 0.018 226 Reactor pressure vessel and attached piping initial liquid 13,706 volume, ft3 Drywell Initial temperature, °F 145 Initial pressure, psig 0.75 Relative humidity, percent 20 Suppression pool Initial temperature, °F 95 Initial pressure, psig 0.75 Relative humidity, percent 100 RHR complex reservoir initial temperature, °F 80 - 90b Calculated peak drywell pressure, psig 49.9 Calculated drywell margin, percent 19.5c Calculated peak suppression pool pressure, psig 28.3 Calculated suppression pool margin, percent 54.35c Calculated peak deck differential pressure margin, psig N/A Calculated deck differential pressure margin, percent N/A Peak pool temperature during blowdown, °F 135 Page 7 of 8 REV 19 10/14

FERMI 2 UFSAR TABLE 6.2-1 CONTAINMENT PARAMETERSa Long-term peak pool temperature from accident, °F (with 196.5 degraded containment cooling system) a This list of parameter and results corresponds to those referred to in Subsection 6.2.1.2, Primary Containment System Design.

b RHR service water varies linearly from 80 °F to 90 °F over a period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

c Percent below maximum allowable pressure of 62 psig.

Page 8 of 8 REV 19 10/14

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position D

M, ooyo o a~q W 5~; a5vi' VLQ' H.w-Penetration Detail System Title Remarks X-1A 6C721- - - Equipment Access Hatch - - - - - - - - - - - - - - - - Type BTest 2304

-1B 6C721- - Equipment Access Hatch - - - - - - Type BTest 2304

-2 6C721- -- - Personnel Airlock - - - - - - - - - - - - - - - - Type B Test 2304

-3 -- -- - Drywell Head -- -- -- -- - -- -- -- -- -- -- -- -- -- -- -- Type BTest

-5A 6C721- -- -- Vent Pipe -- -- -- -- - -- -- -- -- -- -- -- - -- -- -- Type A Test, Note 1 2304

-sB 6C721- -- -- Vent Pipe - -- -- -- -- -- -- -- -- -- -- -- "- -- -- - Type ATest, Note 1 2304

-se 6C721- - - Vent Pipe - - - - - - - - - - - - - - - - Type A Test, Note 1 2304

-s0 6C721- - - Vent Pipe - - - - - - - - - - - - - - - - Type ATest, Note 1 2304

-SE 6C721- -- -- Vent Pipe - - - - - - - - - - - - - - - - Type A Test, Note 1 2304

-5F 6C721- - -- Vent Pipe - - - - - - - - - - - - - - - - Type A Test, Note 1 2304

-Sn 6C721- - - Vent Pipe - - - - - - - - - - - - - - - - Type A Test, Note 1 2304

-sH 6C721- - - Vent Pipe - - - - - - - - - - - - - - - - Type A Test, Note 1 2304 X-6 60721- - - Control RodDrive - - - - -- - Type B Test 2304 Removal Hatch Page 1of 38 REV 24 11/22

FERMI2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

-c o oo o- o a o o o Penetration Detail ____System Title Remarks X-7A 6M721- 55 Yes Main Stea Line A B2103F022A GLB AG A RMv A E, F, 0 C C C C No A Yes Yes Notes 2and 3 INSIDE OUTsIDE 2089 (V17-2003) G, J, P SEMB2103F028A GLB AG A RM A E, F, 0 C C C C No A Yes Yes Note 3 FR OM SEMO(V17-2007) G, J, P REACTOR26"SEMT VESSEL B2103F022A 3/8 2103F028A TRNE 6M721- - No - -- - -- - - - - - - - - - - - - Note 42 TC Ld 2100F434 CONTROL B2100F104A SYSTEM S-7B 6M721- 55 Yes MamnSteam Line B B2103F022B GLB AG A RM A E, F, 0 C C C C No A Yes Yes Notes 2and 3 INIE OTIE2089 (V17-2001) G, J, P TvB2103F028B GLB AG A RM A E, F, G C C C C No A Yes Yes Note 3 STEAM ACO AO (V17-2005) G, J, P REACTOR26"ET VESSEL B2103F022B B2103F5288 6M721- - No - -- -- - -- - -- - - - - - - - - - Note 42 3/4 " A FROM 3045 ONTROL TCLC 8210F434 ()LEAKAGE CONTROL X-7C 6M721- 55 Yes Main Steam Line C B2103F022C GLB AO A RM A E, F, G C C C C No A Yes Yes Notes 2and3 INSIDE OUTSIDE 2089 (V17-2002) G, J, P STEAM B2103F028C GLB AO A RM A E, F, G C C C C No A Yes Yes Note3 FROM STEAM TO (V17-2006) G, J,P REACTOR ( TURBINE VESSEL 82103F022C 82103FD28C 6M721- - No - -- - - -- - - - - - -- -- - - - - - Note42 FRMA ^

4N FROM MSV 3045 l TC LC B2100F434 SYSTEM TC 2100F104C PLUG411/22 P oINU

FERMI 2UFSAR TABLE6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

Zhz "oB C" 6M21 55 YeoanSemLn 20F2D GB A M A E , O C C C C N e e oe n Penetration Detail OUSD 208

,NID SstemTitle (V172004 a m

, J, nza w v 7 H a Remarks 6M721- 55 Yes Main Steam Line D B2103F022D GLB AG A RM A E, F, 0 C C C C No A Yes Yes Notes 2and3 INSIE OUTSIDE 2089 (V17-2004) ,,P B2103F028D GLB AO A RM A E, F, 0 C C C C No A Yes Yes Note3 AM26 STEAM TO (V17-2008) GJ,P REACTOR 62103FO22D B2103F028D TURBINE VESSEL l3/4" AO FROM MS- 6M721-- - - - - - ---N Note42 LEAKAGE 3045 (TV) CONTROL TC E B2100F434 SYSTEM TC INLNEPLUG B2100F1040 X 6M721- 55 Yes Main Steam Line Drains B2103F016 GAT MO A RM A E, F, C 0 C AIS C No A Yes Yes Note4 INSIDE OUTSIDE 2089 (V30-0259) G,J,P E2103F0161 FROM MAIN (M/j -1 T E CONDENSER LINE E2103FU1S B2103F019 GAT MO A RM A E,F, C 0 C AIS C No A Yes Yes DRAINS TOC I TO G,J,P 6M721- 55 Yes Feedwater B2100F010B CHK -- RF - - - 0 C C - C R A Yes Yes -

/F c 2023 (V12-2007)

B2100F076B CHK AO RF RM - - 0 C C C C R A Yes Yes Note5

-EEL( r (V12-2001) 2 7 6M721- 55 Yes Reactor Core Isolation E5150F013 GAT MO RM M -- Z C C 0 AIS C R A Yes Yes Note6 T 2044 Cooling (V8-2228)

Fr 6M721- 55 No Reactor Water Clean-up G3352F220 GAT MO A RM B W 0 C C AS C No A Yes Yes Note 35 2046 (V30-0322)

Page 3of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

T

>6M721- 55 Yes Feedwater B2100F010A CHIK -- RF - -- -- 0 C C - C R A Yes Yes -

Y2023 (V12-2008)

FB2100F076A CHK AO RF RM - - 0 C C C C R A Yes Yes Note5 (V12-2002)

S6M721- 55 Yes High Pressure Coolant E4150F006 GAT MO PM M - Z C C 0 AIS C Yes A Yes Yes Note 7 2035 Injection (V8-2194)

X-10 6M721- 55 Yes SteamtoReactorCore E5150F007 GAT MO RM M -- Y 0 C 0 MS C R A Yes Yes Notes4,6,and31 T2044 Isolation Cooling Turbine (V17-2030)

FROM MO EF M(

MANT STEAM E51EFO7(TV)RCIC X11 TO I T E5150F008 GAT MO RM M - Y 0 C 0 AIS C R A Yes Yes Notes 6and 3l (V17-2031) 6M721- 55 Yes Steam to HighPressure E4150F002 GAT MO RM M -- X 0 C 0 AIS C Yes A Yes Yes Notes 4, 7, and 31 INSIDE OUTSIDE 2035 CoolantInjection Turbine (V17-2020)

STEM FROM STEAM E4150F003 GAT MO RM M - X C C 0 AIS C Yes A Yes Yes Notes 4and 7 REACTOR ITOHPCI (V17-2021) 0 E415SFTE3 E4150F600 GLB MO RM M - X 0 C C AIS C Yes A Yes Yes Notes 7and3 TO 1MO (V17-2088)

TCCT M0 TC/TV E4150F600

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATIONDATA ISOLATION VALVE DATA Valve Position MO M0 T5OV0 Penetration Detail S___

SstemTitle Wv Remarks E 06M721- 55 No Residuale atRemovalPump E1150F009 GAT MO A RM C L C 0 C AIS C No A Yes No Note8 2083 SuctionFromRecirculation (V8-2091) 1V OUTSIDE I INSIDE Ppn E1150F608 GAT MO RM M - -- LC LC LC S C No A Yes No Note9 RHR K25 VO E1 RO REACTOR (V8-3407) rlleElo RUFOU VR20 PEIPAI E1150F008 GAT MO A RM C L C 0 C MTS C No A Yes No Note8 Tc PC(V8-2092) 110P m"E1100F408 CHK SA RFO - - -- C C C -- C No A Yes VaeS-T TV EllOOF400 (V8-3874)

X13 6M721- 55 No Residual Heat Removal Pump E1100F050B CHK SA RE - - - C 0 - C Yes A No Yes Note 36 OUTSIDE INSIDE 2083 Discharge to Recirculation (V8-2164)

Tv E1100F050 Loop FROM 24" V TOEB-2166REATOS E1150FO15B GAT MO RM M - Z C 0 O AIS C Yes A No Yes Notes 7,12, 37 and38 RHR RECIRCULATON PUMPS V8-2160E1160F015B T LOOPB (V8-2162)

Tc 5-V TO El11F610B GLB SO RM M - - C C C C C No A No Yes Notes 7 and36 E11F10 (V13-7688)

X-13B 6M721- 55 No Residual HeatRemoval Pump E1100F050A CIIK SA RE - - - C 0 - C Yes A No Yes Note 36 INSIDE OTSIDE 2084 Discharge to Recirculation (V8-2163)

Tc E1100F50A TV ILoop AO M7 7 TOREACTORVH T6 25^" 55 FROM EliSOFOlSA E1005 GAT A

MO MO R M

M - Z C O O AIS C Yes A No Yes Notes es, 7, 12, 37, and 38 (V8-2161)

TO IC RECOIO2 BFO ROCRO2 LOOP SEFIRN A VR2155 PUMPS PUP so T Tc El1F610A GLB SO RM M - - C C C C C No A No Yes Notes 7and36 E11F6l1A (V13-7687)

-4

-- - Spare - - - - - - - -- - - - - - - - - TypeATest Page 5of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA

_ Valve Position NT Bn FR TV 207Sseouto V-14 OP0 L0J 4-1 (V-254 25005 O SPAC21005B enRERV-02 GT MO R) -0~ - C5 O-~ AI H YeCe e Nts7ad3 S NSID OUTSIDE 6M71- 55 No Corbsbe Spay PmDChatrge E2100F6006B CH SA R - - - LC LC OC -C LC Yes A Yes Yes te ,0,1 ad4

,u2034SstmSuto II. T-(V8-204)

AT H ATMOSPBR V8M 1 B LOERM X-165 INSIDE OUTSIDE 6M721- 55 No Core Spray Pump Discharge E210F006A CHK SA RF -- -- - C C O - C Yes A Yes Yes T 2034 (V8-2024)

TSPARGER3A V822F005A E2150F005A GAT MO RM M -- -- C C O AIS C Yes A Yes Yes Notes 7and38 T C (V8-2021)

Tv A9M coE TB SCHRG X-1A SPASE BRE TV j TO COESRA (VS-2021)

INSIDE OUTSIDE 6M721- 55 No CoreSpray PumpoDischarge E210F06 CHK SA RF -- -- -- C C 0 -- C Yes A Yes Yes 2034 (V8-202)

O G TB T BISFLANGE

-18 " }E2l5DFDD5B PUMP AE2150F005B GAT MO A RM C L C C 0 AIS C Yes A Yes Yes Notes 7and38 ouNSIDE OTSIDE 6M721- 55 No CRsda epa Rumoscarg E100FO6A CHK SOA R C L- - C C 0 AIS C Yes A Yes Yes te an3 SPARSE 6 MO1/2M2-of 38ERA - REVC5U5(C24A (V8-2172)

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

Penetration Detail __ __ System Title >___a° a wH Remarks X-18 TC INSIDE OUTSIDE 6M721- 56 Yes Drywell Floor Drain Sump G1154F600 GAT MO A RM C,K -- 0 0 C AIS C No B Yes No -

2032 PumpDischarge (V9-2044)

FROM TO DRyWELL MO v AO FLOOR FLOOR T DRAIN DRAIN (RI) 00 0 SUM VS 03 G1154F60 01100F003 COLLECTOR G11 F 03 GAT AO A RM C,K - 0 C C C C No B Yes No -

V9-2004 TO I (V9-2005)

X-19 TO TO INSIDE OUTSIDE 6M721- 56 Yes Drywell Equipment Drain G1154F018 GAT MO A RM C,K - 0 0 C AIS C No B Yes No --

FR LL TB Tv 2032 Sump Pump Discharge U

EQUIPMENTv-21va DRAIN V-01 MO OTO SUMP TM 3" A RADWASTE S(TV)

V9-2027 G1154F01B G1100F019 COLLECTOR TM . TANK G1100FO19 GAT AO A RM C,K - 0 C C C C No B Yes No -

v9-2028 TO I TC (V9-2023)

X-20 OUTSIDE INSIDE 6M721- 56 No DemineralizedService Water P1100F126 GAT M M -- - -- LC LC LC -- LC No B Yes No Note9 FROM TO 2678 toDrywell Connection (V8-3120) Flange Type BTested DEMINERALR SERVICE SERCE CONNECTON SSTEM I P110OF126 INSIDE O DRYWELL TC X-1 OUTSIDE INSIDE 6M721- -- No Service Air toDrywell - -- - - - - - - - - - - - - Note 41 2085 Type ATest FROM MO MO TO SERVICE L ' CONTAINMENT AIR EE= SERVICE SYSTEM P5000F03 P5e00F604 AIR N2 SUPPLY HEADER TC0°f Page 7of 38 REV 2411/22

FERMI 2UFSAR TABLE6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position P1 Penetration Detail System TitlefI ~Remarks

___ ___ ___ __ ___ ___ __Detil___ Sytem Title > ~ >9 ac X-22 Zv' ¢ m z2c Om a d m d N ea 6M721- 56 No Nitrogen toDrywell T4901F601 GLB MO A RM B,K - O C AIS C R B Yes Yes Notes 2and32 OUTSDE INSIDE 5007 FROM T4901F465 SYSTEM A 1/2" M T4901F465 GLB AO A RM B, K - 0 0 C C C R B Yes Yes Note 32 T4901F601 LEO

• SOLENOID

. 2 TVrMALV T4901F007 GLB M M - - - LC LC LC LC LC No B Yes Yes Note9 RELIEF T4901F007 VALVES X23 OUTSIDE INSIDE 6M721- 56 Yes Reactor Building Component P4400F282A CHK SA RF -- - - 0 0 0 -- 0 Yes B Yes Yes -

5444 Cooling Water/Emergency TC COMPONENT Equipment Cooling Water FROM MO 10" . W ATR Supply RECCW TO PUMP P4400F606A P400F282A DRWEL P4400F606A GAT MO RM M - -0 0 AIS 0 Yes B Yes Yes Note34 TC/P TO X-24 OUTSIDE INSIDE 6M721- 56 Yes Reactor Building Component P4400F616 GAT MO RM M -- -- 0 0 0 AIS 0 Yes B Yes Yes Note4 TO l 5444 Cooling Water/Emergency I Equipment Cooling Water TO MO MO COMPONENT Return RECCW 6 10" COOLING HEAT WATER EXCHANGER P4400F607A F P440F616 FDRYWEU P4400F607A GAT MO RM M -- -- 0 0 0 AIS 0 Yes B Yes Yes T4600F411 INSIDE OUTSIDE AC 6M721- 56 No Drywell Exhaust and Air Purge T4803F602 BFY MO A RM B,K,R -- C 0 C AIS C R B Yes No Note11 3445 FROM MO AO E6" T4600F402 BFY AO A RM B,K,R -- C 0 C C C R B Yes No -

DRYWELL - -- 24. TO SBGTS DR'AJEW i REHVAC ATMOSPHERE T4803F602 T4600F402 TO Tv 7M721- T4600F411 BFY AO A RM B, K, R -- C 0 C C C R B Yes No 2709 Page 8of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 6 D CS B, R

.) m C ,`S 48F C)

B A R C) 6' y' R1

, R - C OS p

B O OE TO 2 C O) TO m C 2 ( (d (e 2 Sml of0our aC Q H- 7)vlZV

¢° wWmd F Penetration Detail System Titl > <dc~~ Remarks FROTMN2flX2 SSE -56M721- 56 No DrywellAirPurge Ilet T4803F601 BFY MO A RM B,,R -- C 0 C MS3 C R B Yes No Note 11 T4855F4T0 3445 (VR3-3011)

OUTSIDE INSIDE Y) I T48000F407 BFY AG A RM B,K,R - C 0 C C C R B Yes No -

OETO 2 A OMENTO (V5 2)

RooM ATMOSPHERE 7M721- T480F408 BFY AG A RM B,K,R - C C C C C R B Yes No T4900 F7 T4553FR51 2709 (V4-2060)

X-27s 61721- 56 No Containment Atmosphere Typical BAL AG RM M - - C 0 0 C 0 No B Yes Yes Notes 12 and 13 h27 (C) (a) (e) 2679-1 Sample of~our T5000F401B OUTSIDE jINSIDE (V15-2159)

T5000F403B 29 S(V5-2161)

TO CONTAINMENT T500F404B PMSE T5 0 2 ATMOSPHERE (V1-2162)

TSSSF4 (b) T5000F405B TSSSSPOO4SRoa (V5-2163)

TSSSSF4SSE OPEN TO ~~~~ ~ ~PETO 671 6 YsP4GB S M - - - C C C C C N e e oe1 61721- 56 Yes ContainmentAtmosphere T5000F402B BAL AO R M - - C 0 0 C 0 No B Yes Yes Note12 2679-1 Samples (V5-2160)

T04 so so SAMPLE P34 GLB SO RM -- -- -- C C C C C No B Yes Yes NotelO0 INSIDE OUTSIDE so F403A NSIDE4 UTSID P34F453A P34F454A (V13-7364)

OPEST TO 61721- 56 Yes P34 GLB SO RM\ -- -- -- C C C C C No B Yes Yes Note 10 CONTAINMENT ATMOSPHERE 7TSSSSF4S2R PCMS (NY) 2400-10 F404A (V13-7374)

I INS I OUTIOSE

] S61721-TPMS 2679-1 56 -- Containment Atmosphere Montoin Syte T50F458 GLB SO RM -- - -- 0 0 0 MIS 0 No B Yes -- Note 12; Page 9of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA b~ Valve Position 010 m )-

wQN0m p

!1 b0 A i.' d- dN*q b y i INSIDE I OUTDE 6M721- 55 No Jet Pump Flow EFC SA HF - - - 0 0 0 - O No A No Yes Note 14, Type A Test FROM 2090 Instrumentation ORIFICE X-28B

-- - Spare - --- - - - - -- - - -- TypeATest X-2ad 6M721- 55 No Jet Pump Flow Typical EFC SA HF - -- - 0 0 0 -- 0 No A No Yes Note 14, Type A Test 2090 Instrumentation of Five See Penetration Detail X-28A OIFICE TC xe2 6M721- 55 No Jet Pump Flow B2100F514B EFC SA HF - - - 0 0 0 - 0 No A No Yes Note 14, Type A Test SAMPL M 2090 Instrumentation (V13-2329)

P34F401A o

FROM PRIMAR Y /4" FLUYDE MIN I SYSTEM RESTRICTIN 6I721- B2100F5148 Yes Postaccident Pressurized P34 GLB SO RM - - - C C C C C No B Yes Yes -

OFFICE2400-10 Reactor Coolant Sample F401A 6M721-X2D2090 55 Jet Pump Instrumentation (1) Typical EFC SA HF - - - 0 0 0 - O No A No Yes Notes 15 and 16, Type A Test 2833 and Recirculation Inlet AP (4) of Five See Penetration Detail X-28A X-28E

- - - Spare - - - - - - - -- - - - - - - -- -- Type A Test Pae1 f3fRV2 12

- - Spare - - -- - 0 0 0 C 0 - A - Type ATeTest X-28G

- - Spare p-o-2-0-4CFC-

- -- -- -- -- 0 0 0 C 0 N A- - - -- Type ATeTest

FERMI 2UFSAR TABLE 6.2-2 SUMM4ARY OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0 ~

C, C S AR CCNAY o Z ,,, Z S

H DE o ~ 0C. o" i30

'UTSID m

0 H8-OCES ACRE CULTIO

-IBD INSIE 6M721- 55 No ReactorWater Sample B3100F019 GLB AO A PM B,K D C C C C C No A Yes No Note2 2IrOM 2833 (V17-2077)

RPStato X-29il 6M2-S6NyRato ste TiSytemCOTAIMEN E/E1F13 GB SeRmark00 0 ASs o B Ye e ots22,ad1 ENE1-F43 Eo P 1 19'- CONT- M EN RP >12B M2- 56 N eco3oecinytmEV11F413 GLB SO RM RM B,K D 0 0 0 MS 0 No B Yes YeN ots,2,n1 203-V5221 o o so PNO 2083 (V5-2546)

INSOPNT CONTAINMENT 61721ME-RecirculationiLoopaFlow'(2 X3 1A -2R EPS N2E~~b 6M721-

-/d6M721-56 55 No No Reactrulation Reactor ProesurempIstm Sesemve(2)fTyical-F B210IF09 EFCL EFC 50 SA PMHF -

-- --- 0 0 00 00 AIS-S 00 No No AB Yes Nos Yes Yes Notes12n1 Note 1,ad1 OX-30B 1

~iD 2090I 20833 DInstrumentation8 O-SIDEreINS-6M721- 56 No relInstetion Reicuain up5-(25o46xSe)eerain T500F42 (V1-247) B A0 PM 0 0 0 C- 0 No B Yes Yes NotSe,ntaineal-8 es2,1,tand43 eal -8 OusD NIE6M721- 55 No ReIrcuenationpnt() Typical0 EFC A HF -M -- -- 0 0 0 C- 0 No A Nos Yes Note16.315 nd4 XE2833 Recruenation umpAP(),3of0i See PenetrationDetail X-28A Recirculation Loop Flow (2)

-- - - Spare -- - - - - - - - -- - -- - -- - - -- Type ATest Page 11 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA ValvePosition 00 w~ a Oo solO,m p'

Penetration Detail ____ SystemTitle > > °6¢ ~ w a° dOwd Remarks X-31S 6M721- 56 No Drywell On-Line Pressure T4800F455 GLB AO A RM B,K,R -- 0 C C C C R B Yes No Note2 Tv 3445 Control A T4800F454 GLB AO A RM B, K, R -- 0 C C C C R B Yes No -

TON2 PNEUM SUPPLY T4800F454 TC I T4800F453 GLB AO A RM B,K,R -- 0 C C C C R B Yes No I IfOTS OPENTO-TOSBTS& y L~IZ 1 OPYSNELL PBHTAC &ATMOSPHERE (T) T4800F453 T4800F455

-32A 6M721- 55 No Reactor Pressure Vessel B2100F516C EFC SA HF - 0 - 0 No A No Yes Notes 15 and 16 2090 Pressure SeePenetration DetailX-28A 6M721- 55 No Steam Flow to High-Pressure Typical EFC SA HF 0 0 0 - 0 No A No Yes Note 16 X-2B 2833 Coolant Injection (2) and of Six See PenetrationDetailX-28A 2035 Recirculation Loop Flow (4) 6M721- 55 No Recirculation Pump AP (2), Typical EFC SA HF - 0 0 0 - 0 No A No Yes Notes 15 and 16 a3A 2833 Recirculation Pump Inst.(2), ofFive See PenetrationDetailX-28A and Recirculation Pressure (1) 6M721- 55 No RPV Pressure (1), Steam Flow Typical EFC SA HF - 0 0 0 - 0 No A No Yes Notes 15 and 16 x-3Ba 2090 to High Pressure Coolant ofFour See Penetration DetailX-28A 2035 Injection (2), and Feedwater 2034 Pressure (1)

X-34A 6M721- 56 Yes Reactor Building Component P4400F282B CHIK SA RF - 0 -- 0 Yes B Yes Yes 5357 Cooling Water/Emergency OUSIE INSIDE EquipmentCooling Water MOCMPOENT 'supply FROM 6" 10" 6" UNGENT PP PW TO P4400F606B GAT MO RM M - 0 0 0 AIS 0 Yes B Yes Yes Note34 P4400FRORB P4450F252B DPYWEL TC !TV TC T X-34B 6M721- 56 Yes Reactor Building Component P4400F615 GAT MO RM M - 0 0 0 AIS 0 Yes B Yes Yes Note4 OU1DE INSIDE 5357 Cooling Water/Emergency EquipmentCooling Water TO MO COMPONENT Return RBBCWO 6" 10" 6" COUN0 ER FESOH~A P4FE P4450F557 P4400ES H1ODRYVELL M P440OF607B GAT MO RM M - O 0 O AIS 0 Yes B Yes Yes v

S AB,C,D,E,F,G 61721- 54 No TIP System Flanges - - - - - - - - - - - - No - No Yes TypeBTest 2837-6 Page 12of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIA'TED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0~~ ~ CD

-nN)A, 0Y P CaG 2 a Z)

Zj Sg

_b E' 0 0 Penetration Detail °QSystem Tite oza P, E u (5aRemarks

-3A . 61721- - - TIP System (Spare) Type A Test 2837-6 C50)018C10F02 M00NS X-358 6I721- 54 No TIP System 5100F002B BAL SO - C, K - C C C C C No - Yes Note 17 OUTiDE INSIDE 2837-6 (C5102J004B)

DRNVE SECT 5100F001B SHR EX RM - - - O O O O O No - No Note 17 61721- 54 No TIP System (5100F002A BAL SO - C-C, - C C C C C No - Yes Yes Note 17 sc 2837-6 C5102J004A)

C5100F001A SHR EX RM - O- O O O O No - No Yes See Penetration Detail X-35B 61721- 54 No TIP System C51002B BAL SO - - C,K - C C C C C No B Yes Yes Note17 X-5DE 2837-6 (C5102J004B)

C500OOC SHR EX RM - - O O O0 No B No Yes See Penetration Detail X-3 5B 6I721- 54 No TIP System C5100F002E BAL SO - - C, K - C C C C C No B Yes Yes Note 17 X35E 2837-6 (C5102J04E)

C5100FOO1E SHR EX RM - - 0 0 0 0 0 No B No Yes See Penetration DetailX-35B 61721- 54 No TIP System C5100F002D BAL SO - - C, K - C C C C C No B Yes Yes Note 17 X-35 2837-6 61721-D 54 N TPyteI500O2 (C5102J004D) BL S -- -- , -- C C C C C No B Ys es ot1 C5100FOO1D SHR EX RM - 0 0 0 0 0 No B No Yes See Penetration DetailX-35B 61721- - No TIP System Note 18 X° 2837-6 (Spare) -C- - - - Type A Test OUTJ D INSID SWCAP 27 oC38R2J201E)

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position Ce d 0 i3 z) U5) oCe oCe v)w5 bm 1 -1 /2 AO MK - 0 0 C A C Yes B Yes Yes Note 32 6M1 56 NoNLoenorwl T4901F68 GLB AO A RM B,K -- 0 0 C CI C Yes B Yes Yes Note32an N 1-1/2 D RYWeLL (V4-2188)

SYSTEM T4991P455 T4501FB02 T4901F016 GLB M - - - -- LC LC LC LC LC No B Yes Yes Note9 (V8-4140) 6M721- 54 No Control Rod Drive Insert - BCK SA RF - - - 0 0 C - Yes B No No Note 19 SDVVENT 2081 and Withdrawal Lines (1-C1100F18 115 BCK SA RF - - - 0 C C C C Yes B No No This Information Applies to

> G- C1100F01 Penetrations X-37 (A, B, C,D) 121 GAT SO A RM - - C C C C C Yes B No No and X-38 (A, B, C,D)

INSIDE OUTSIDE DH 123 GAT SO A RM - - C C C C C Yes B No No 127 VOLUME (SDVs) 0o4C1100F011 120 GAT SO A RM -- -- C C C C C Yes B No No OD (VTHDRAV C100F181 Typical of 122 GAT SO A RM - - C C C C C Yes B No No SOVORAIN 185 Units o 126 GLB AO A RM - - C C 0 0 0 Yes B No No WATFER HEADER 127 GLB AO A RM - - C C 0 0 0 Yes B No No X37 FROM E 138 BCK SA RF - - - 0 C C C C Yes B No No C1100F010 REG AO A RM 0 0 C C C Yes B Yes No TO (V8-2073)

CONTROL 1P VE Ci1OOFO1 REG AO A RM 0 0 C C C Yes B Yes No (INSERT) 13B OOUNG ATER C1100F180 REG AO A RM 0 0 C C C Yes B Yes No TE126 SUPPLY 11 SUPPLY (V8-3876)

Ci10OF181 REG AO A RM 0 0 C C C Yes B Yes No Page 14 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

o c' 0 P, "m mr

',o v°b.`

-o 39Av 6M721- 56 No Residual Heat Removal to E1150F021A GAT MO A RM A, K - C C O AIS C Yes B Yes No Notes 4, 10, 20 and 21 INSIDE OUTSIDE 2084 Containment Spray Header (V8-2169)

Te A,K TO CONAINMENTMDO SPRAYHEADER 12" FROM E1150F016A GLB MO A RM - C C O AIS C Yes B Yes No Note20 E1150F21A E1150F016A PUMP (V8-2167)

TOOTMEN O MO M 6M721- 56 No Residual HeatRemoval to E1150F021B GAT MO A RM A,K -- C C 0 AIS C Yes B Yes No Notes 4,10,20 and21 INSSDE OSIDE 2083 Containment Spray Header (V8-2170)

Note 20 R M TCr" LECONTANME E1150F016B GLB MO A RM A,K C C

- 0 AS C Yes B Yes No langeobeType BTested PUMP E 7F E1150F02I HEADR (V8-2168) 6M721- 55 No Recirculation Inlet AP (4) and Typical EFC SA HF - - - O O O - O No A No Yes Note 16 X4Ao 2833 Reactor Pressure Vessel of Six See Penetration Detail X-28A 2090 Pressure (2) 6M721- 55 No Reactor Pressure Vessel Typical EFC SA HF - - - 0 0 S- O No A No Yes Notes 15 and 16 X40B 2089 Pressure (1) and Main Stear of Five See Penetration DetailX-28A 2090 Flow (4) 6M721- 55 No Jet Pump Flow Typical EFC SA A - 0 0 0 - C No A No Yes Note 14 x40c 2090 Instrumentation of Six -See Penetration Detail X-28A 6M721- 55 No Jet Pump Flow Typical EFC SA HF - - - 0 0 0 - No A No Yes Note 14 X40 a,, 2090 Instrumentation of Five See PenetrationDetailX-28A TC 6M721- 55 Yes JetPump Flow B2100F514A EFC SA HF - - - 0 0 0 - No A No Yes Note 14 2090 Instrumentation and (V13-2328) x-os Postaccident Reactor SCoolantSample INSIDE OUTSIDE SAMPLE(TV)

P34F401B '

FROM PRIMARY" 6I721- P34F401B GLB SO RM -- -- - C C C C C No B Yes Yes FLUID w -

SYSTEM RESTRICTNG7 B2100F514A 2400-10 FLOW ORIFICE X4 - -- - Spare -- - -- -- -- -- -- - - - - - - - -- - TypeATest Page 15 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0 m a m 6M2- 5 o StnbaiudCnrlC1007 CK S F - - - C C C - C R A Ys N 0a m S' O 36 w 7 ° Penetration Detail ________ System Title °Z m aQ a d wv daRemarks 6M721- 55 No Standby Liquid Control C4100F007 CHK SA RF -- - - C C C -- C R A Yes No -

INSIDE OUTSIOE 2082 (VR4-2037)

TC FROM TO STANDBY RET TB CT URNOL C4100F006 CHK SA RF -- -- -- C C C -- C R A Yes No Note 22 PESSE C4100F007 C4100FO0 PUMPS (VR4-2036)

TCIT X-43 INSIDE OUTSIDE 6M721- 55 No Reactor Water (Cleanup From G3352F001 GAT MO A RM B W 0 0 C AIS C No A Yes Yes Alternate-Note4 FROM 2046 Recirculation Piping) (V8-2252)

FROM JM REACTOR MO RECIRCULAION LOOPS TO G3352F004 GAT MO A RM B W 0 0 C AIS C No A Yes Yes Note 35 G332F1G]3352F004 R(CUV8-2253)

Tc TCrv X-44 INSIDE OUTSIDE 6M721- 56 No Combustible Gas Control T4804F603B BFY M M -- -- - LC LC LC LC LC No B Yes No Notes 9, 10, 11, and45 Tv 2087 System Suction (V4-2143)

OPENTO J TO ATMOSPHERE 4F BLOER T4804F605B BFY M M - -- - LC LC LC LC LC No B Yes No Notes 9and 45 T4E14F603B T4BB4FD5B LVE (V4-2153)

TC X45 -- -- -- Spare - -- -- - -- - - - - -- -- - - -- -- -- Type ATest X46A 6M721- 55 No Main Steam Flow Typical EFC SA HF -- - - 0 0 0 - 0 No A No Yes Notes 15 and16 2089 of Four See PenetrationDetailX-28A x 6M721- 55 No Main Steam Flow Typical EFC SA HF - - 0 0 0 - 0 No A No Yes Notes 15 and16 2089 of Four See PenetrationDetail X-28A Page 16 of38 REV 2411/22

FERMI 2UFSAR TABLE 6.2-2 SUMM4ARY OF PRIMARY CONTAINMENT PENETRATIONS ANT)ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA b~ Valve Position COC LL H 0'C)

CO C U NSD o Penetration2Detail RPCUSDONIE6 72- 5 o RatrPotcinSse Title 1F1 (12System GLB SO S RM - - -OO I O No) B Ye 0e See oeP tr

,1,ad1 ea X47b 71 56 NCeco)Poeto yse 1F1 GL-O R - -O 0C0AI OQoB Ys Ys Nte ,1,ad1 6M721- No Reactor ProtectionSystem EIF414 GLB SO RM 0 0 0 IS 0 No B Yes Yes Notes 2, 12,and 15 RPCUSIE)5DE6 56 - - -

___________________P .T 2084 (V5-2548)

EPS OUTSID use 6M721- 56 No Reactor Protection System E11F415 GLB SO RM - - -- 0 0 0 AIS 0 No B Yes Yes Notes 2,12, and 15 SoNS 2084 X-7 6M21 55 No Reco Prssr VeslLvee2F0mECHar-- O O O(V5-2549)

-ksoA No Ys Nts5ad1 TOTOPE ' SE 6M721- No Note 15 X47d 6M721- 55 No Reactor Pressure Vessel Level B321F7507 EFC I-F -- -- -- 0 0 0 -- 0 No A No Yes Notes 15 and 16 2090 (V13-2318) SA See PenetrationDetailX-28A

, 4SF,5 6M721- 56 No Drywell Pressure T5000F420A BAL AO RM M - -- 0 0 0 C 0 No B Yes Yes Notes 2,12,13, and 15 2084 Nitrogenlnerting (V5-2230)

L_ OInstrumentation T 0 2 ATMOSPHERE 61721-I2679-1 Page17of38 REV2411/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

o

- , C0 q a sIa Penetration Detail __ _System Title U> ~m a. 5 4 1 Remarks X-48 abc'd e 61721- 56 No Containment Atmosphere T5000F401A BAL AO RM M - -0 0 C 0 No B Yes Yes See Penetration DetailX-27 2679-1 Samples (V5-2151)

INSIDE OUTSIDE TC OPEN TOPGM(V-12 TO T5000F402A CONTAINMENT T000F401A(V5-2152)

ATMOSPHERE T5000F402A T5000F403A {T5000F403A T5000F404A (V5-2153)

T5000F405A so PFRATIO T50F450 T5000F404A x-23 ATO(V5-2154)

AO T5000F456 T5000F405A To (V5-2155)

PCR MS T50F450 GLB SO A - B,K B, K 0 0 C C C No B Yes Yes Note 10 (V5-3083)

T5000F456 BAL AO A M B,K B, K 0 0 C C C No B Yes Yes Note 10 (V5-2235)

TC 61721- 56 Yes Containment Atmosphere 2679-1 Samples P P4 s E 6I721- P34F403B GLB SO RM - - - C C C C C No B Yes Yes Note 10 2400-10 (V13-7365)

CONTIMN DRYWELL ATMOSPHERE - P34F404B GLB SO RM -- - - C C C C C No B Yes Yes Note 10 INSIDE OUTSIDE (V13-7375) 6M721- 55 No Recirculation Pump Seal Purge B3100F014B GLB AO A M B,K - 0 0 C C C No B Yes Yes Note 15 2x5 2833 (V8-3590)

@(491 OUTSIDE INSIDE B3100F016B GLB AO A M B, K - 0 0 C C C No B Yes Yes Note 15 1vj Tc (V8-3768)

N TC FROM CRD 3/4" A

TB RECIRCULATION PUMP B3100F014A GLB AO A M B,K - 0 0 C C C No B Yes Yes Note 15 PUMPS B3100FOl1A B3100F014A SEAL CAVITY (V8-3710) 9310016B B3100F014B NO. 1 B3100F016A GLB AO A M B,K - 0 0 C C C No B Yes Yes Note 15 (V8-3767)

- - Spare - - - - - - - - - - - - - - - - Type ATest 6M721- 55 No Main SteamFlow (4) and Steam Typical EFC SA HlF - - - G 0 - G No A No Yes Note 16 x-2 2089 Flow to Reactor Core Isolation of Six See Penetration DetailX-28A 2044 Cooling (2)

Page 18of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

6M721- 55 No Steam Flow to Reactor Core Typical EFC SA HF - - - 0 0 0 - 0 No A No Yes Notes 15 and 16 X-5 2044 Isolation Cooling (2), ofFour See Penetration Detail X-28A 2034 Feedwater Pressure (1), and Reactor

-54Ad 6M721- 55 Yes Reactor Level, Pressure B2100F506 FFC SA HF - - - 0 0 0 - 0 No A No Yes Notes 15 and 16 2090 (V13-2317) See Penetration Detail X-28A X-54B 6M721- 55 Yes Reactor Level, Pressure B2100F508 EFC SA HF - - - 0 0 0 - 0 No A No Yes Notes 15 and 16 2090 (V13-2397) See Penetration Detail X-28A X-55Ae 6M721- 55 No ReactorLevel,Pressure B2100F510 EFC SA HF - - - 0 0 0 - 0 No A No Yes Notes15and16 2090 (V13-2321) See Penetration Detail X-28A 6M721- 55 No ReactorLevel,Pressure B2100F512 EFC SA HF - - - 0 0 0 - 0 No A No Yes Notes15and16 X-55Bb 2090 (V13-2323) SeePenetration Detail X-28A B2100F511

_____________________________________________ __________(V13-2396)

X-100A 6E721-2831-8 - - Neutron Montor C- -T -c -E -S - - - - - - - N- - N-- - TypeB Test x-100B 6E721-2831- Low Voltage Switching 8 - - Reactor Protection System - - - - - -- - - - - -- - - - - - Type B Test X-100F 6E721-2831-8 -6 - Spare - - - - - - - - - - - - - - - - Type ATest X-100G 6E721-2831-8 -6 - NeutronMointor - - - - - - - - - - - - N- - N- Y- TypeB Test X-101A 6E721-2831- - - RecirculationPumpPower, - - - - - - - - - - - - - - - - Type B-Test 8 5kV X-101B 6E721-2831- - - Recirculation PumpPower, - - - - - -- - - - - - - N- - N- Y- Type B Test 8 5kV Page9of3 REV2411/22 VltgeSwtcin x-ioic 6E721-2831- - - RecirculationPumpPower, - - - - - - - - - - - - - - - - TypeDB Test 8 5kV Xoo 6E721-2831- - - RecirculationPumpPower, - - - - - - - - - - - - TypeBTest 8 5kV X-101E 6E721-2831- - -- Recirculation PumpPower, - -- - -- - -- - -- - -- -- -- - -- -- -- Type BTest 8 5kV

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

mo o 8 a p e o o o. o o Y a Q H> rC)°OC¢' C)z Penetration Detail SystemTitle w a 4 Remarks X-101F 6E721-2831- -- -- Recirculation Pump Power, - - - - - - - - - - - - - - - Type BTest 8 5kV X-102A 6E721-2831- -- -- Neutron Monitor - - -- - -- -- - -- -- - -- -- - - - - Type BTest 8

X-102B 6E721-2831- -- -- Low VoltageSwitching! - - - - - - - - - - - - - - - - Type BTest 8 ReactorProtection System X , 6E721-2831- - - Low Voltage Switching/ - - - - - - - - - - - - - - - - Type BTest 8 Reactor Protection System X10sc 6E721-2831- - - Low Voltage Switching/ - - - - - - - - - - - - - - - - Type BTest 8 Reactor Protection System X-103A 6E721-2831-8 -- -- Drywell Thermocouples -- -- -- -- -- -- - -- -- - -- -- - - - - Type B Test x-103B 6E721-2831-8 - - Neutron Monitor - - - - - - - - - - - - - - - - Type B Test X-104A 6E721-2831- - - ControlRodDrive Position -- -- -- - -- - - - -- - -- -- - - - -- Type BTest 8 Indicator x-104B 6E721-2831- -- -- Control Rod Drive Position - - - - - - - - - - - - - - - - Type BTest 8 Indicator X-104c 6E721-2831- - - Control Rod Drive Position - - - - - - - - - - - - - - - - Type B Test 8 Indicator X40 6E721-2831- - - ControlRod Drive Position - - - - - - - - - - - - - - - - TypeB Test 8 Indicator X-104a 6E721-2831- - - Control Rod Drive Position - - - - - Type B Test 8 Indicator X-104F 6E721-2831- - - Control Rod Drive Position - - - - - - - - - - - - - - - - Type BTest 8 Indicator X-105A 6E721-2831- -- -- Low Voltage Power - - - - - - - - - - - - - - - - Type BTest 8 (480 V)

Page 20 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position o

a~ o Qo o~

z~ `02 o- cD "o

0 ° ww 8- a- - 00+ - - - -o 80(40CV PenerationDetail 2SystemTitle LwL Sgnal H Remarks 6E721-2831- -- -- LowVoltagePower -- -- -- -- -- - -- -- - - -- - -- -- - - Type BTest 8 (460 V)

X-0A 6E721-2831-8 -- - Spare -- -- - - - - - - - - - - -- - Type ATest x6E7 21-2831- Low Level Signal Vibration Test 8 - - - -- -- -- -- -' _' -- -- -- -- - - - Type BTest

- - -- Torus Access Hatch - - - -- - - Type B Test

-- - - TorusAccess Hatch - -- -- - -- -- -- - -- -- -- - - -- - -- Type B Test 6C721- - - trusecces - -- -- - -- -- -- - -- -- -- - - -- -- -- Type B Test 2305 x-201a 6C721- -- -- Vent Line Bellows - - -- -- -- -- - -- -- -- -- - - - -- -- Type BTest 2305 x201c 6C721- - - VentLineBellows - - - - - -- Type BTest 2305 x2om 6C721- - - VentLineBellows - - - - - - - - - -- - - - 'Type BTest 2305 X-201E 6C721- - -- Vent Line Bellows -- -- -- - -- -- - - - -- - -- -- - - - Type BTest 2305 x-iooc 6E721-2831- -- - Blanked Off Electrical -- - -- -- - -- - - - -- -- - - - - -- Type B Test, Double0-Ring 8 Penetration (Spare) Testable Seal X-100E 6E721-2831- - - Blanked OffElectrical - - - -- - - -- - - - - - - - - -- Type BTest,Double0-Ring 8 Penetration (Spare) Testable Seal 6E721-X-100D 2831-8 - - Low Level Signal - - - - - - - - - - - - - - - - Type B'Test Vibration Test Page21lof 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

8m oo8o v ..

Penetration Detail System Title Remarks 6E721-2831-8 - - Drywell Thermocouples - - - - - - - - - - - - - - - - Type BTest 6E721-

-0 2831-8 - - Spare - - - - - - - - - -- - - - - - - Type ATest X-201F 6C721- -- - Vent Line Bellows - - - - - - - - - - - - - - - - Type BTest 2305 X-201 6C721- - - Vent Line Bellows - - - - - - - - - - - - - - - - Type BTest 2305 X-201H 6C721- - - Vent Line Bellows - - - - - - - - - - - - - - - - TypeB Test 2305 X202A 6C721- - - Vacuum Breaker - - - - - - - - - - - 0 - - - - Note 23 2305 (Inside Torus)

X-202B 6C721- - - Vacuum Breaker - - - - - - - - - - - 0 - - - - Note 23 2305 (Inside Torus)

X202c 6C721- -- - Vacuum Breaker - - - - - - - - - - - -- - - - Note 23 2305 (Inside Torus)

X202D 6C721- -- - Vacuum Breaker - - - - - - - - -- - 0 -- - -- - Note 23 2305 (Inside Torus)

X-202E 60721- -- - Vacuum Breaker -- "- -- -- -- -- -- - - - - - - - - Note 23 2305 (Inside Torus)

X-202F 6C721- -- - Vacuum Breaker - - - - - - - - - - - -- - -- - Note 23 2305 (Inside Torus)

X-202G 6C721- - - Vacuum Breaker - - - - - - - - - - - 0 - - - - Note23 2305 (Inside Torus)

X-202H 6C721- -- -- Vacuum Breaker --- - - - - - - - - 0 -- - - - Note 23 2305 (Inside Torus)

Page 22 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA v Valve Position C soo (C-O x - -

>) > u0 oo b<4 -

X -202O 0-- O ----N 23 X-0K671 -O VaumBeae) -CD- - - - OC- - - N te2 T4 800F416 (TC) To X-24 6721- 57 N Vacuum T480F41 GL A RM M - - LC LC LC C 0 B Y N See P D 6M21 57 NCrwl)t ou aum 40F1 L AO RM M - -/ LC LC C C0o Ys NoNoe

-~~ ~ ~OT DEz IN7IDE 344 Brakerm Nirogken Supl (V4-2036)-- - -- - - - -- Noe2 X-20 6721- 5 Nl Vacuum T480F41 GL A --- M- - LC LC LC C C N B Ye No See Prna-23445 Breakder TronsuplV-05 3445 2305F1 (Inid'ous Breaker Nitrogen Supply (V4-2086)

X-204c 6721- 57 No Dyelou Vacuum T4800F41 GL AO R - -- LC LC LC C C No B YstoSe PeertinDtilX24 23445 en4 BeaerNiroen Breakder TronsuplV-05 uply(V-284 345Brae NtoenSppy(4-05 xr 6M721- 57 No Drywell to Torus Vacuum T4800F416 GLB AG RM M - - LC LC LC C C No B Yes No No Pte inDtalX24 OUSD 23445 NIE3445 Breaker Breakder Nitrogen Supply TrognSppy(4-07 (V4-2075)

X-20 6M721- 57 No Dywl- ou Vacuum T4800F423 GLB AO RM M - - LC LC LC C 0 No B Yes No Noe2eertinDtilX24 X-252K6C7213445- X-0E6M721- 57 No Vraumrker Drywell Torus Vacuum to irnSpl T4800F420 (V -088)- GLB AO RM M- -- -- LC

- LC

- LC

- C

- 0 C No

-- -B Yes No

- Nt2 Soe eerto9ealX24 X-25a 6M721- 57 No Drywell to Torus Vacuum T`4800F420 GLB AG RM M -- -- LC LC LC C C No B Yes No See Penetration DetailX-204A 3445 Breaker Nitrogen Supply (V4-2082) x-254c 6M721- 57 No DrywelltonTorus Vacuum T4800F421 GLB AG RM M -- -- LC LC LC C C No B Yes No See Penetration DetailX-204A 3445 Breaker Nitrogen Supply (V4-2084)

X-2540 6M721- 57 No DrywelltoTorus Vacuum T4800F419 GLB AG RM M -- -- LC LC LC C C No B Yes No See Penetration Detail X-204A 3445 Breaker Nitrogen Supply (V14-2086) x254a 6M721- 57 No Drywell to Torus Vacuum T4800F420 GLB AG kM M -- -- LC LC LC C C No B Yes No See Penetration DetailX-204A 3445 Breaker Nitrogen Supply (V4-2088) 3445 BreakefitroenEuply4(V11/22

FERMI 2UFSAR TABLE 6.2-2 SUMM~vARY OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position C) 0 C) cO oo 0C) p) 0-' p0 -0 0 oo ~ ,I o ~ '

n xi l AU o) v -.-o~ ,-0 o

<0< ovom a~ pp H o~

-, oaC7

-i vQ C)v 3< C) 6M21 57 No eerto ealX24 Peetato Deai w<p~ S0 stmil 0>O w-CDrwlooTrsVcu 0 Hz i a ° d eak 40F2 L O R C C L o B Ys N e 344 Brae Niroe Supl (V4-090 6M21 57 No Drwl to Toru Vauu T40F2 GL AO RM MHC L C C C N e o e eerto ealX24 3445 Breaker Nitrogen Supply (V4-2092) x-20s 6M721- 57 No Drywell to Torus Vacuum T4800F426 GLB AO RM M - - LC LC LC C C No B Yes No See Penetration Detail X-204A 3445 Breaker Nitrogen Supply (V4-2094)

X-204 6M721- 57 No Drywell to Torus Vacuum T4800F427 GLB AO RM M - - LC LC LC C C No B Yes No See Penetration Detail X204A 3445 Breaker Nitrogen Supply (V4-2096) 345Xrakritoenupl-B4202 6M721- 56 No Secondary Containment T2300F410 BFY AO RM - H C C C C Yes B Yes No Notes 10, 11, and 24 ND OTD 3445-1 to Torus Vacuum Breaker (V21-2016)

B0KER120"DyPENrTOuT2300F450B CHK SA RF RM - - C C LC C Yes B Yes No Notes 10 ande25 OPEN (V21-2014)

T230F450B CONAMENT SUPRsso T2300F410 POOL TC 6M721- 56 No Secondary Containment T2300F409 BFY AO RM - - H C C C G C Yes B Yes No Notes 10, 11,and 24 NDE 00TS0D 3445-1 to Torus Vacuum Breaker (V21-2015)

Notes 10 and 25 7

OPEN TO T2300F450A CHK SA RF RM - - C C C - C Yes B Yes No EN AR (V21-2013)

UPPRESON T2300F40 T2300F40 A POOL OPEN av OT 23040A CNAIMNTCOOR (V21-3014)2709C9 6M721- 56 No Suppression Pool Air Purge T4800F404 BFY AO A RM B,K,R - C C C C C R B Yes No Notes 10 and 11 FROM N2 3445-1 Inlet (VR3-3013) Flanges type Btested OUTID INSIDE C Note 10 T4800F49 Ac 7M721- T4800F405 BFY AO A RM B,K,R -- C C C C R B Yes No RMOM-T4800F409 BFY AO A RM B,K,R - C C C C C R B Yes No Note 10 T4800F405 T4800F404 OPENmT (VR3-2061)

SUPPRESSION Pae2O38RE2L12

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

p v5 0 2 5 No S )Y C C R B Y No N 7M21 56 No C Supeso Exas 40F0 EY Hoo A M BKR 0 C C C B Yes No Nts1,1,ad4 FROMraio N2ai 270 an SitoenIlt (R-0lnes type B testeds SUPPLY T4800F456 TC 6M721- T4600F401 BFY AO A RM B, K, R - C O C C C R B Yes No Note 10 and 44 To sBrs a 1 3445-1 (VR3-3016)

RHVCT4800F458 T4800F457 T4600F412 BFY AO A RM B, K, R - C C C C C R B Yes No Note 10 (VR3-3019)

F205 BY AO A RM ,K,R C C C C C R B Yes No Note 10 NSIDE T4800F410 TC (V4-2063)

T4600F412 6 AnO AO T4800F456 GLB AO A RM B, K, R - O C C C C R B Yes No Note 10 SBGTS (TV) 20"° - (VR3-2826)

& RBHVAC T4600F401 T4600F400 (OENTO LRESSION T4800F457 SUPLY1F402 5 T GLB AO A RM B, K, R - O C C C C R B Yes No Notes 2 and 10 AO OurTSIE (VR3-2827)

FROM N22 SYSTEM T40F410 T4800F458 GLB AO A RM B, K, R - O C C C C R B Yes No Note 10 111N (VR3-2828)

-206A TC 6I721- 56 No Tors Pressue and Liquid E41F402 GLB SO RA M B- - 0 0 AIS C No B Yes Yes Note 12 S2679-1 Level Instrumentation (V5-2552)

E1F400 E41F403 GLB SO RA M B- - C O AIS No B Yes Yes Notes 12 and 26 (V5-2553)

V (V5-256)

-20B E41F401 GLB SO RM M -, - 0 0 AIS O No B Yes Yes Notes 12 and 26 LOW WATER LEVEL (V5-2551)

ENS RI E41F400 GB SO RM M 0 0 AIS No B Yes YesNote 12 T 1E41F401 FLOW (V5-2550)

ORIFICE T50F412A GLB SO RM M - - 0 0 AIS No B Yes Yes Notes 12 and 26 T T 4(V5-2555)

L- T41 F4712 GLB SO RM M - - 0AIS No B Yes Yes Notes 12 and 26 T50F412A r RES TRICTING TSOF4128 FLOW ORIFICE 206E T50412 6CLB1 50 KM Mri ie(nieTrs -- -- -- 0- 0MS 0 No B Ye Ye Notes2an

-(-

RET25~N Page12 rf 38VRV2411/2

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 22 D-

- - 0 o)QQV' - - - - -

C) 3 C) Te QCe - - -

-27CC71e -f Driie(nieT rs - - - ---- oe2

-20E 6C721- - - Drain Line (Inside Tors) - - - - - - - - - - - - - - - - Note 23

-H 0 --~ ------ OC) --- - -

-.. 07 6C721- - - Drain Line (Inside Torus) -Note 23 S 6C721- - - Drain Line (Inside Torus) - - - Note 23 2305 2305

-27 71 - - Drain Line (Inside Torus) - - - - - - - - - - - - - - - - Note 23 2305 0 6 1- - - Eeromane eie Valve - -- - - - - - - - - - - - - - - Note 23 2305CDischarge(InsideTor 2305

-208B 6C721- - - DrainLine(InsideTorus) - -- - - - -- - - -- - - -- - - - -- Note 23 2305

-208C 6C721- -- - DrainLinet(InsideTrals) - -- - - - -- -- - -- - - -- -- -- - -- Note 23 2305 X-a07F 6C721- - ElecDra neiseiefrus)e- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- Note 23 2305 Dshre(isd'os X-207 6C721- - - Electromagnetic Relief Valve - - - - - - - - - - - - - - - - Note23 2305 Discharge (Inside Torus)

-208E 6C721- - - DrmaneticnsiefValve - -- -- - - - - -- -- - - -- -- -- - -- Note 23 2305 Ds)

-006C721- -- -- raie(nideorusValv -- - -- - -- - - - - - -- -- - Note 23 2305 Dshre(nieTrs

-2070 6C721- - -- Electromagnetic ReliefValve - -- -- -- -- -- -- -- - - -- - -- -- -- - Note 23 2305 Discharge Inside Torus)

-0B6C721- - -- Electromagnetic Relief Valve -- - - - - - - -- -- -- - - - - - Note 23 2305 Discharge (Inside Torus)

-208G 6C721- - - Electromagnetic Relief Valve - - - - - - - --- -- - - - - - Note 23 2305 Discharge(Inside orus) 2305 Discharge(Inside Torus)

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA b~ Valve Position 00 o

C) 3 wC) s 0'i C .;0ti~m0

'o Penetration Detail __ _

2305 SystemTitle DicagInieTrs wC- mtV d z v w°c/Oa v H Remrk

-208H 6C721- - - Electromagnetic ReliefValve - - -- -- -- -- -- -- -- -- -- - -- - -- -- Note 23 2305 Discharge (Inside Torus) 208K 6C721- - - Electromagnetic Relief Valve - - - - - - - - - - - - - - - - Note 23 2305 Discharge(InsideTorus)

-208L 6C721- - - ElectromagneticReliefValve - - - - - - - - - - - - - - - - Note 23 2305 Discharge(Inside Torus)

- -- -- - - Note 23

-208M 6C721-2305 - - Electromagnetic Discharge Torus)Valve (InsideRelief - -- -- -- -- - -- -- - - -

-208N 6C721- -- - Electromagnetic ReliefValve -- -- -- -- -- - - -- -- - - - -- -- - -- Note 23 2305 Discharge (Inside Torus)

-2080 6C721- -- -- Electromagnetic Relief Valve -- -- - - - - - - - - - - - - - -- Note 23 2305 Discharge (Inside Torus)

-2080 6C721- -- -- Electromagnetic ReliefValve -- -- - -- -- -- - - -- -- -- - - -- -- -- Note 23 2305 Discharge (Inside Torus)

-208 6C721- - - Electromagnetic Relief Valve --- - - - - - - - - - -- --- Note23 2305 Discharge (Inside Torus)

-209A - -- -- Thermocouple -- - -- - -- -- - - - -- - -- - -- - -- Type BTest X-209B -- -- - Spare -- -- - -- -- -- - - -- -- -- - -- -- -- - Type A Test x-209c -- -- - Torus Thermocouple -- - -- -- -- - -- -- -- -- - -- - -- - TypeB Test X-209D -- -- - Spare -- - -- -- -- - -- - -- -- - -- - -- - Type ATest Page 27 of38 REV 2411/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS ANT)ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA ValvePosition 0

Penetration Detail System Title Remarks X-211A OLTSDE NSIDE 6M721- 56 No Residual Heat Removal E1150F007B GAT MO RM M - Z 0 C C AIS C Yes B No Yes Notes 12 and39 2083 Minimum Flow (V8-4679)

MO MO (TV) ~ 18-6 56 No Residual Heat Removal Heat E1100F025B REL SA -- -- -- -- C C C - C Yes B No Yes Notes 27,28and39 E110F28 E1150F27BPPSN Exchanger Discharge Header EOM RH POOL Thermal Relief EXCHANGER CSPRAY 18 56 No Residual Heat Removal Test E1150F024B GLB MO A RM A,K - C C C AIS C Yes B Yes Yes Notes 2, 10 and 26 Line (V8-2136)

X-2-1TA El150F0248 MO 56 No Residual Heat Removal to E1150F027B GLB MO A RM A,K -- C C C AIS C Yes B Yes Yes Notes2and 10 TC MO 0UTS0DE INSIDE Suppression Pool Spray (V8-2158)

E1150F026B-E1150F028B GAT MO A RM A,K - C C 0 AIS C Yes B Yes Yes -

(V8-2156)

RO 56 No Residual Heat Removal Heat El100F001B REL SA - - - - C C C -- C Yes B No Yes Notes 27,28, and39 w 4 Exchanger Thermal Relief (V22-2642)

FROM E1100F025 56 No Residual HeatRemoval E1150F026B GAT MO RM M -- -- C C C AIS C Yes B No Yes Notes 39, and 40 Warmup and Flush Line (V8-2152) Flanges Type BTested E1100F 1BAT LE L Page 28 of38 REV 24 11/22

FERMI2 UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0 -

0 z°RH 4mw o, 6M21 CoTrsaeangetG50F0 GT MRMB,KM O o B e oe2 Penetration Detail °______ System Title ____ wm m______?d Remarks SUPESO FRM( 8-89 G510F04 GA MO CA RMC B,K0 M- o B YsNts4ad2 POOL M-OC-4'MORHR 6M721- 56 No ToRs WaterManagment G5100F605 GAT MO A M B,K M 0 C C AS C No B Yes Yes C Note 26 IES15E U1 O 4100 System (V8-4680)

TO G5100F604 GAT MO A RM B,K M C C C AIS C No B Yes Yes Notes 4mad26 SUPPRESSION FO (V18-3849)

POOL MO MO 7

SPRAY l C. ISYSTEM fiJ 6M721- 56 No Residual Heat Removal E1100F029 REL SA - - - - C C C - C Yes B No Yes Notes 27,28, and 39 E11SSFS27A EllESFOOA 2083 SautinThermal Relief (V22-2033)

O6M721-2084 56 No Residual Heat Removal Heat E110O025A REL SA - - - - C C C -- C Yes B No Yes Notes 27,28,md 39 I -Exchanger Discharge Header EO Thermal Relief El10Fd9 E1150F024 X21E CO 56 No Residual Heat Removal Heat E1100FOOlA REL SA -- -- -- -- C C C - C Yes B No Yes Notes 27,28, and39 11E00F025A Exchanger Relief (V22-2643)

E110S 1AF'SM I CR2'210"O 56 No Residual Heat Removal E1150F007A GAT MO RM M - Z 0 0 C MS C Yes B No Yes Notes 7,12,and 39 E1150FS07A UP MinimumFlow (V8-2133)

TO MS SUPPRESON I 56 No Residual Heat Removal Test E1150F024A GLB MO A RM A,K C C C C Yes B Yes Yes Notes 2, 10,and26 7"

POOL -

m' ms Line (V8-2135)

"MO G5100FB04 No Residual Heat Removal E1150F028A GAT MO A RM A,K - C C C S C Yes B Yes -

Tc Suppression Pool Spray (V8-2155)

MO G5100F605 E1150F027A GLB MO A RM A,K - C C C MS C Yes B Yes Yes Note 10 BELOW LOW TC (V8-2157)

WATER LEVEL 61721-PROM TORUS WATERMACAGER 2400-10 56 No Liquid Sample Retum P34F407 GLB SO RM - - - C C C C C No B Yes Yes Notes 10 and26 So sO (V13-7368)

Notes 10 and 26 3/4. LIQUID TE P34F409 GLB SO RM - - - C C C C C No B Yes Yes P34F407 P34F4 (V13-7378) Flanges TypeBTested TC Page 29of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS ANT)ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA o ValvePosition aa a p g r a h ,'-`' a 7a.w

°- a > a C v u °av 0r 0 a Q0 a , U~ d zL)  ? ao a°w a 6M21 56 No RatrCrpslto5F00 SC MO RF RM -C -- 0 0` 0 I o YsNoe ,2ad3

.000 6 -Reactor Core Isolation E5150F062 GAT MO A RM & - O O O AIS C R B Ye No Note 6 E510F04 AT MO A R &) 0 O O AS C B TO 2044Cooling Vauumin Eaker (V11-20020) aoai l" eaaLine 6M721- HigPCore Isolation E415OF075 GAT MO A RM K&X4) - 0 0 0 AIS C R B Yes No Note6 Cooling Vacuum Breaker (V11-2020)

WA/R35V Line E5150F084 GAT MO A RM K&Y(4) - 0 0 0 AIS C R B Yes No Notes 4 and6 (Vi1-2026)

POOL H ~

6M721- High-Pressure Coolant E4150F075 GAT MO A RM K&X4) - 0 0 0 AIS C Yes B Yes No Note7 2035 Injection VacuumBreaker (V11-2013)

Line 6M 7 T 4100 St N 10 E4150F079 GAT MO A RM K&X(4) -- 0 0 0 AIS C Yes B Yes No Notes 4and7 (V81-2019)

SRSO MOFRM High-Pressure Coolant E4150F021 SCK MO RF RM - -- 0 0 0 MIS C Yes B No Yes Notes 7,12 and 39 TSNInjectionTurbineExhaust I Line (V1-2006) 6M721- 56 No TorusWaterManagement G5100F600 GAT MO A RM B,K M 0 C C AIS C No B Yes No Notes 10 and26 4100 Suction (V8-3834)

HO1 TTORU HO

~MA J

oo /OM/

GH10[Fm O THO/USPT PoU POOL IG5100F600 GAT MO A PM B,K M C C C MIS C No B Yes No Notes 4, 10, and 26 I TO (V8-3832)

Page 30of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA j

Valve Position 0

0 Penetration Detail ______ System Title °j~ ¢ ~ z a- a Remarks x-213B INSIIDE OUTSIDE 6M721- 56 No TorusWater Management G5100F602 GAT MO A RM B, K M C C C AIS C No B Yes No Notes 4, 10, and26 4100 Suction (V8-3831)

TC MO MO TO TORUS OPEN e° e WATER TOEN - 6 MANAGEMENT G5100F603 (V8-3833)

GAT MO A RM B, K M 0 C C AIS C No B Yes No Notes 10 and26 SUPPRESSION G51oF602 G5100F6o3 PUMP POOL BELOW LOW j TC WATER LEVEL

- -- -- Vacuum BreakerLine, High- -- -- -- -- - - - - - - - - - - - - See PenetrationDetail X-212 xa-4 Pressure Coolant Injection/

Reactor Core Isolation Cooling X215 POST 6M721- 56 No Combustible Gas Control T4804F602A BFY M M - -- - LC LC LC LC LC No B Yes No Notes 9,10,11, and45 ACCIDENT TC SAMPLE RETURN 2087 System Suction and Gaseous (V4-2142)

INSIDE OUTSIDE CSample Returns I P34F408 P34F410 TOPENT TO CCS 61721- 56 No T5000F408A BAL AO RM M - -0 0 C 0 No B Yes Yes Notes 12and 13 CONTAINMENT BLOWER 2679-1 (V52158)

ATMOSPHERESE (6N1)258 ATMSPHREST4804F602A T4804F606A (OIV. 1) 6M721- 56 No T4804F606A BFY M M - - - LC LC LC LC LC No B Yes No Notes 9and45 TC 2087 (V4-2156) 61721- 56 Yes P34F408 GLB SO RM - -- - C C C C C No B Yes Yes Note10 PROMPCMS(TC) 2400-10 (V13-7369)

Note 10 T5000F455 56 Yes P34F410 GLB SO RM -- - - C C C C C No B Yes Yes PROM PCRMS T50F451 (V13-7379) 61721- 56 No T50F451 GLB SO A -- B, K B, K 0 0 C C C No B Yes Yes Note 10 2679-1 (V5-3084) 61721- 56 No T5000F455 BAL AO A M B,K B,K 0 0 C C C No B Yes Yes Note 10

____________________________2679-1 ___________________(V5-2239)

-216A

-- -- - Spare - - - - - - - - - - - - - - - - Type ATest

-216B X-217

-- - - Spare -- -- -- -- - -- - -- - -- - - - -- -- - Type ATest Page 31 of38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA ValvePosition 0 C H a C)CD D 5 HC 208 SytemRetrn V4-140 CO CO "o 0+ 0,o - o 0 0 m w 0x Penetration Detail °QSystemTitle > u 2' a H a Remarks 6M721- 56 No CombustibleGasControl T4804F601A T484F16A BFY RE M SA M- - -- --

- LC CCCC LC LC LC

) LC C0e No B Yes e Noe Notes oe 9,10,11, 7ad2 and 45 OPEN 0 " " 2087 C(V222122 SystemReturn (V4-2140)

T4WAFO4F1 T4804F604A BFY M M - -- - LC LC LC LC LC No B Yes No Notes 9and45 (V4-2148)

IFRO OPNa"C"IK -ROG (J T4804F016A (V22-2122) REL SA - - - - C C C -- C Yes B Yes Yes Notes 27 and28 sUPESSION T4804F601A T4804F64A (DV 5oMmsn T4804F601B BFY M M LC LC LC LC LC No B Yes No Notes 9,10,11, and45

)

T294FO1-1 (V42139)

T4804F604B BFY M M -- -- - LC LC LC LC LC No B Yes No Notes 9and45 (V4-2149)

SsT4804F016B REL SA - - - -- C C C - C Yes B Yes Yes Notes27and 28 X1(V22221) 6M721- 56 No Combustible GasControl T4804F602 BFY M M - - LC LC LC LC LC No B Yes No Notes 9,10,11, and 45 2087 SystemSuction (V4-2141)

Notes 12 and 13 CORTAC-IRR TOOO RiIOPRR T4R4ER2 T4R4FRRRR mu 1O 61721- 56 No T5000F408B BAL AO RM M -- - 0 0 0 C 0 No B Yes Yes Turbine4 Exhaust i4Injectio 2679-1 (V5-2166) 0H 6M721- 56 No T48041F6063 BFY M M -- - - LC LC LC LC LC No B Yes No Notes 9and45 02087 (V4-2155) isD OUTS X-220 -- -- -- High-Pressure Coolant -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- See Penetration Detail X-212 Injection Turbine Exhaust 6M721- 56 No High-Pressure Coolant E4150F022 SCK MO RF RM -- -- 0 0 0 M1S C Yes B No Yes Notes 7,12 and 39 2035 Injection Turbine Exhaust (VI1-2008) c Drain

-I Page 32of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 00

-~ H o

^H C) U

~-

o Q~UC q 01 v 'O0 72 F -o H 6M721- 56 No Reactor Core Isolation E5150F002 SCK MO RF RM - - O O O AIS C R B No Yes Notes 6,12 and 39 S°PRSIN2 RM 2044 Cooling Vacuum Pump (V8-2235) pooL - R,l Discharge X-223A OUTSEDEQUNSID 6M721- 56 No ReactorloresatiovanPm E1150F004D SCK MO RF PM -- - 0 0 0 AIS C Re B No Ys Notes67,12,and 39 POOL L1 N 2 "v 2POOL 1O" MOS 6M721- 56 No Residual Heat Removal Pump E1150F004D GAT MO RM M - - 0 0 0 S 0 Yes B No Yes Notes 7,12,and 39 I VPEER 2083 Suction (V8-2100)

L Notes 27,28, and 39 TO MPO REM Residual Heat Removal Pump E110O03OD REL SA - - - C C C -- C Yes B No Yes oc> E1150004D BELOLOW Suction Header Thermal (V22-2035)

WATERLEVEL Relief X-223M E1100F030B 2 OUTSIDE INSIDE amo M 6M721- 56 No ResidualHeatRemovalPump E1150F004B GAT MO RM M - - 0 0 0 AIS 0 Yes B No Yes Notes 7, 12,and 39 2083 Suction (V8-2102)

MO SUPPRESSION To RHR 2" POOL T ResidualHeatRemovalPump E1100F030B REL SA - - - - C C C - C Yes B No Yes Notes 27,28, and 39 E15004 BELOWSuctionHeaderThermal (V22-2037)

WATER LEVEL Relief UTSI 6M721- 56 No Residual Heat Removal Pump E115OF004C GAT MO RM M - -- 0 0 0 AIS 0 Yes B No Yes Notes 7, 12,and 39 2084 Suction (V8-2101)

SUPPRESSIORN POOL 24A TORHR BELOWLOW E1100040 (Tc Residual Heat Removal Pump E1100F030C REL SA - -- - -- C C C -- C Yes B No Yes Notes 27,28,and 39 WATERLEL Suction Header Thermal (V22-2036)

Relief E1100030

FERMI 2UFSAR TABLE 6.2-2 SUMM~vARY OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA b~ ValvePosition 0 -

xa0 E1160Fat Te Hde Detuctio 4A (V-2) 711C U ]F0i¢OA~ R z.R Reoa Zeida E11OFo0 REL Hea - e -umo YsNt ,ad3 0S) 6M721-2034 56 No CReda Spra Pumva Suctio E2150F036B GAT MO RM M - - O O O AIS O Yes B No Yes Notes 7,12, and 39 SUPPRESS10NtiMn (V8-2008) 6M721-2034 56 No Core Spray PuRmp Suction E2150F036A GAT MO RM M - - 0 0 0 AIS 0 Yes B No Yes Notes 7,12,and 39 SUPPRESSONE O Suc(V8-200)

POOL 20 T CORE E2I:OFO3ER PURR E150FR36A PUMP BELOW VLOW Reie X-225-008 6M721-2034 56 No CoreSprayPump Suction E2150F036A GAT MO RM M - - 0 0 0 AIS 0 Yes B No Yes Notes 7, 12,and 39 i P(V8-2002)

E21ROPROiA nPOMP POOL 24"TO6CORT RELOWSLOW E R60D4 6M721-2035 56 No High-Pressure Coolant E4150F042 GAT MO RM M - X C C 0 AIS C Yes B No Yes Notes 7,12,3 1,and 39 Injection Pump Suction (V8-2202)

MOORROLTVEE POOL 24 RE R O F1 POU P ISDE 0UTSE WATER LEVEL BLOWLOWElOF) j6M721-2044 56 No Reactor Core Isolation E5150F031 GAT MO RM M -- -- C C 0 MIS C R B No Yes Notes 6, 12, and 39 MO T Cooling Pump Suction (V8-2225)

WPO~LCHL .J R O Page 34of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position 0

C~) MO TB - 4-TBFO 0 4~i RS 1FLAW 6MNSIDE6 56 NOUorSprayump2.tionE2100F011B No CoreSprayPumpinimum E2150F01B REL REL SA RM- M- - Z

- CC C CC AI

- C Yes B No Yes Notes 12, 12,27,and 28,3and 39 E20F1M UOFOE TOC 03 hraleif(V22-2119) Flw H i(V8-2032)

SUPESOIN-00 RAEFTL AE 56 No Core Spray Spray Pump Pump Dinimumg Stin E210F01B E2100F015B GAT REL SA SAvi - M A,

- - C C CC C CC AI C Yes Ys B BN-e No Yes Notes 12,27,28, and 39 ots1,2,2,2,ad3 8 TC TB (V8-2119) Z 0 0 C MS C e BYso04)

CW RELIE VALVEE PO Flow el (VV2202-)2 LU P2(62-2119 1OU2"E LLE MOO)-I COESRA P6M721-4100E56 WAS OREOR M214 56 No Toru S atermMan m G250F06 GAT MO AM No C 0 C MIS C Nos B Yes Nos Notes7 1and69 RM B, MCoresprayerMpaen E2100F0B GL MO A RM ,K - C C C MS C Yes B No Yes Notes 12 and9 OWLOW O(VOFE2M0P32)4 UOESPA 12"TB LUG5100F60(V8-V2-204 TC . TB FROM CURE G5100F607 GAT MO A PM B,K M 0 C C AIS C No B Yes No Note 26 GS100F607 MO VE-205 SPAYUM (V8-4682) 6M721-(Tv> 2035 56 No High-Pressure Coolant E4150F012 GLB MO RM M - Z C C C AIS C Yes B No Yes Notes 7,12, and 39 FROMTORUSWATERMANAGEMENT InjectionMnimum Flow (V8-2196) y 6M721-2034 56 No Core Spray PumpSuction E2100F032A REL SA - - - -- C C C -- C Yes B No Yes Notes 12, 27,28,and39 X-227 s- E UORE MMRLMThermal Relief (V22-2019) 6M721-1420 SISIESPARGER 56 No Core Spray Pump Discharge E2100F012A REL SA -- - - - C C C - C Yes B No Yes Notes 12, 27, 28, and 39 MOEI T Header Relief (V22-2016)

S PESO O4E2100F011A REL SA -- -- - - C C C - C Yes B No Yes Notes 12, 27, 28, and 39

-' -. TO P10 ROM W-X-R °V2RALED

~2" TI F015A E2150.

-X--

vP-2051 SPA SS SISTER 6 721 56 No CoreSprayPumpTestLine E2150F015A GLB MO A RM A,K - C C C AIS C Yes B No Yes Notes 12and39 GTBCV--X

- YRE (V8-2033)

P22-2120 6 71 WATERLEEL 12APER RE VALE 2044 56 No ReactoreCore Isolation E5150F019 GAT MO RM M - Z C C C AIS C R B No Yes Notes 6, 12,and 39 "n°2 Cooling Minimum Flow E 21000 2 A B12 FROM CORE6M721 No -- 0 BELOWLOW TB 2034 56 No Core Spray Minimum Flow E2150F031A GAT MO RM M - Z O 0 C MS C Yes B No Yes Notes 7,12, and39 W S RAYP S (V8-4683)

Torus -Low Voltage X-228A -- -- - Switching -- -- -- -- - - - - - - - - - - -- - TypeBTest Torus- Low Voltage X-22B a 2 -- - - Switching - - - -G -M -- -- - - - - - - - N -- Type B Test

-2281 -- -- s - TLowVoltage - -- - -- -- -- -- -- -- -- -- - -- -- - - Type BTest Switching Page 35of 38 REV 2411/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES PENETRATION DATA ISOLATION VALVE DATA Valve Position C

0 d o-

'G0 P y Z B y' yp o C)F (C S S U S P S SO N ' 'a Penetration Detail SystemaTitle P SO R - - - Z C C Remarks X29-- -~C - pre- - -; - - - - - Tp ATs Q28 -- -- - Torus -Low Voltage -- -- -- -- -- -- - - -- -- -- -- -- -- -- -- Type BTest Switching 6I2- 5 o Piar otimn 50047 A O R Mt - - C C C C O N e e oe 2 3ad3 OUSIE INIE 67- M ntoig yse Scio (5217 (e PnertinX-8 R-229 (V P3F0BGSpareLB S- - C C C C C No B YATest X-230 61721- 56 No Primary Containment T5000F407A BAL AO RM M - - C C C C 0 No B Yes Yes Notes 12,13 and 31 OUTSIDE INSIDE 2679-1 Monitoring System Suction (V5-2157) (SeePenetrationX-48)

Division I TO AO and (TC) SUPPRESSION T5000407 POOL 61721- 56 Yes Suppression Pool Postaccident P34F405B GLB SO RM -- -- - C C C C C No B Yes Yes --

SAM- so s0 2400-10 Atmosphere Sample Suction (V13-7367)

P34F406B GLB SO RM - - - C C C C C No B Yes Yes -

ti Tc (V13-7377)

PCMS L. OPEN TO PLE Lo X2161721- 56 No PrimaryContainment T5000F407B BAL AG RM M - - 0 C C C 0 No B Yes Yes Notes 12 and 13 2679-1 Monitoring System Suction (V5-2165)

OUTSIDE INSIDE DivisionHl To POand

[TC SUPRESSION TS0OFU4O7E POOL 61721- 56 Yes Suppression Pool Postaccident P34F405A GLB SO RM\ -- -- -- C C C C C No B Yes Yes -

so-s o2400-10 Atmosphere Sample Suction (V13-7366)

(rl g aP34F406A GLB sO RM -- -- -- C C C C C No B Yes Yes-(V13-7376)

Page 36of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OFPRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES CODES AND SYMBOLS NOTES Penetration Details Bypass Leakage Note Description Note Description Standard mechanical symbols are employed to represent piping details. Bypass leakage paths are identified in this table bya"Yes ora"No". 1. This piping consists of the eight vent pipes that connect the drywell and Each penetration detail provides the following information: Bypass leakaepathsarefurther discussed inSection 6.2.1.2.2.3. pressure suppression chamber. As part of the primary containment structure, criteria. These designcriteria includestress analysiswith consideration giventodead-Primary/Secondary Actuation Modes they areType Atested. weight, thermal, andseismic conditions. The systems areseismicallysupported.

Symbol Description Nuclear gradematerial is used throughoutthe fabrication of the piping system.

1<2> - Penetrationdetailsinnumericalorder L These columns

-eneraton indicate the nature dtais of the containmenti isolation signal oderThe numricl as follows: 2. Globe valve tested in thereverse direction. Results obtained in this test design temrperture and pressure ratings of the systems are greater than those of 2.(TC) - TestconnectionforTypeCtesting A- Automatic configuration are conservative since test pressure tends to unseat the valve disk. thecontainment.

3. (TV) -Test vent forType Ctesting RM - RemoteManual

4. TB - Test Barrier RF - Reverse Flow 3. These valves will be tested at a differential pressure of 25psi with the reactor at 13. Ball valve testedin the reverse direction. Results obtained in this configuration are M - MHigh atmosphericpressure(i.e.,25psig). equivalent to testing in theaccident direction, since valves ofthistype have the same

4. Gate valve tested through the bonnet. This valve has a bonnet tap through sealing characteristics ineitherdirection.

Valve Type Engineered Safety Feature which thebonnet area is pressurized. Leakage is measured through both seainguracealngwtheakgehroghhebnnt~opaedwthestng seating surfaces along with leakage through the bonnet. Compared with testing

14. Jet pump flow instrumentation lines are provided with manual globe valves and The following codes are used to Valves in Engineered Safety Feature systems are identifiedin this column by a"yes"entry. in theaccident direction, thebonnet test leakage is conservative. excess-flow check valves outside the containment. Also, flow is restrictedto a1/4-in.

identify valve type: An"R" entry identifies a valve in an Engineered Safety Feature-related system. Such orifice atthenozzle. Therefore, these instrumentationlines are designed in CHK - Check Systems are not required to function following the design basis loss-of-coolant accident. Air-operated,spring-to-close,positive-actingcheckvalve.Canbeclosedby accordance with therecommendations of Regulatory Guide1.11(Safety Guide 11).

GAT - Gate However, if the system is available, it can be used to accomplish a function similar to an remote manual operation from the control room when system isolation is All instrument line penetrations will be Type A tested.

GLB - Globe Engineered Safety Feature system. required.

BFY - Butterfly 15. Instrumentation penetration. Standardinstrumentationpenetrations areprovidedwith REG - Regulating Containment/AccidentIsolation Signals 6. RemotemanualcontainmentisolationvalveinanESF-relatedsystem. six instrument tubes. In thistable,only thosetubes that areutilizedbyinstrument lines BAL - Ball Thefollowing codes are used to abbreviate isolation signals: Provisions aremade to detect leakage from this line outside the containment. are addressed. All other instrumenttubes associated with the penetration are spares REL - Relief Signal Description See Table 5.2-11. and areTypeAtested.

EFC - ExcessFlowCheck A Reactor Vessel LowLevel 1 SCK - Stop Check B Reactor Vessel Low Level2 7. Remote manual containment isolation valve in an ESF system. Provisions are 16. Instrumentlines of this type are provided with a flow-restricting orifice inside the BCK - Ball Check C Reactor Vessel Low Level 3 made to detect leakage fromthisline outside the containment. See Table 5.2- containment and amanual globe valve and excess-flow checkvalve outsidethe SHR - Shear D Main Steam Line High Radiation 11 containment inaccordance withthe recommendations of Regulatory Guide 1.11 E Main Steam Line High Flow (Safety Guide 11). All instrumentline penetrationswill be Type A tested.

ActuatorType F Main Steam Line Tunnel HighTemperature 8. Valve isolates when reactorpressure exceeds 75psig.

G Main Steam Line Low Pressure 17. The TIP system lines do not communicate freely with the containment atmosphere or H Torus Pressure > Secondary Containment Pressure 9. Manual orremotemanualvalvethatislockedclosedandremainsclosedaftera the reactor coolant. General Design Criteria55and 56 are not directly applicable to Thefolloowing coes de are useH dto J LowCondenser Vacuum LOCA this specific class oflines. The basis to which these lines are designed is more closely L High w RyeaCtoressel esr described by GDC 54, whichstates in effect that the isolation capability ofasystem identifyvalve actuator type:

gh Reaor idniyvleacut :L Vessel Pressure 10. Two containment isolation valves located outside the containment. Due to the should becommensurate with thesafety importance of that isolation. Furthermore, AO - Air Operator M High-High Sump Level Torus Area design ofboth the containment and thesystem, it is not practical to locate one even though thefailureof the TIP system lines presents no safety consideration, the are TIPsystem guide tubes have redundantisolationcapabilities.Thesafety featureshave MO- SolenoidOperator SO- oenoidrOperator High-HighorywellloolofthetwovalvesinsidethecontainmentBothvalves alocatedoutsidethe been reviewedby theNRCforBWR/4 (Duane Arnold), BWR/5 (Nine Mile Point)

MO - Motor Operator High-High Drywell Floor Drain Sump Level containment as close as practical to the containment wall.

M- Manual N High Sump Level or High Sump Temperatures andBWR/6(GESSAR),anditwasconcluded thatthe design of the containment SA - Self Actuated P Turbine Building High Temperatures 11. Butterfly valve tested in the reverse direction.Reverse flow tests are designed isolation system meets theobjectives andintentof the GDC.

EX - Explosive R Reactor Building ExhaustRadiation High toprovide equivalent orconservative results compared with testing in the TheTIP idtubeasembl andthe ortionofthetubinbetweenthe idetube W RWCU System Line accident direction. Incases where stem leakage isnot measured by the leakage ThemTIPgnde s y p og gbetgdet wenth

1) SLCSlnitiation (OutboardValve Only) outofthetestvolume,stemleakageisdeterminedbytestingthroughthestem assemblyandthecontainmentflangeareconsideredtobeinstrumentsandasaresult Valve Position 2) High RWCU Differential Flow vent and thisleakage is added to the test volume leakage. Additional tests on are not classified as ASME components butare purchased and installed as safety-

3) High RWCU Area Temperature purge system butterfly valves are set forth in the Technical Specifications. relatedassemblies.

valve system isprovided withavalve on each guide tube entering the primary

4) High RWCU Area Ventilation Differential Temperature, The following codes are used to 4) R Crea ntiatrLeentgat l nope uiA identifydif erentvalvepositions:different identify valve positions:S ingleisolation vaclosed ou containment. Thesevalvesare closed except when the TIP system is in operation X HPCI System Steam Lines (open an average of15hr/month). Aball valve and acable-shearing valve are 0 - Open1) HPCISpaceHighTemp. a. ThelineisinanESForESF-relatedsystem mounted in theguide tubingjust outside the primary containment. Theypreventthe C -Closed 2) High Steam Flowb. Systemreliabilityisgreaterwithoneisolationvalve loss of containment integrity. The ball valve positionis indicated in the control room.

IS - As Is 3) High Turbine Exhaust Pressure c. The system is a closed system outside the containment TheshearvalveisusedonlyifcontainmentisolationisrequiredwhentheTIPis LC - Locked Closed 4) HPCI Steam Line Low Pressure d. Asingleactivefailurecanbeaccommodatedwithoneisolationvalvein beyond the ll b valve andwhen power to the TIP system fails. The shear valve, which LO - LockedOpen the line iscontrolledbyamanuallyoperatedkeylockswitch, cancutthecableandcloseoff Y RCIC System Steam Lines theguide tube. The shear valves are actuatedby detonationsquibs. The continuity of RCIC Space High Temp The specific closed system requirements met bythis system outside the thesquibcircuits ismonitored byindicatorlightsin the main control room. Identical-Misl1 u1) seeaneous_2) High Turbine Exhaust Pressure containment includemissileprotection,Category I, and Quality Group Bdesign design shearvalves are shoptested by statistical

3) HighSteam Flow standards.

A dash (-) indicates that technical information is not applicable to this 4) RCIC Steam Line Low Pressure column Forinstmmentationpiping,thesystemsaredesignedandinstalledasQuality Z Closes Through Electrical Interlocks With Group B, up to and including the isolation valves. The balance of the This column references the appropriate General Design Other System Valves of Pump Motors h instrument piping is designed to meet Quality Group Bdesign Criteriatof 10 CFR 50,AppendixA(orotherdefinedbasis)withwhichthe penetration is incompliance.

Page 37of 38 REV 24 11/22

FERMI 2UFSAR TABLE 6.2-2

SUMMARY

OF PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES Note Description Note Description Note Description Note Description

21. Due to system configuration, the test pressure is not in the same 31. These valves do not close on the containment isolation signals, but 41. A plant modification, EDP 33297, modified theservice airpiping to the sampling methods to ensure operability and leaktightness. direction as the pressure existing when the valve is required to perform automatically close on accident isolation signal as identified in Table drywell. The pipe penetrating the drywell is plugged and welded and The Technical Specification testing requirements for the TIP shear its containment isolation function. The valve will be tested in the 6.2-2. GDC 56no longer applies.

and ball valves are correct direction during the Type A tests. 32. These valves close on the containment isolation signals butare also 42. A plantmodification, EDP 35267, plugged the Main Steam Isolation

22. The standby liquid control system (SLCS) has been designed to reflect provided with a manual override to these signals to reopen the valves. Valve Leak Control System atthe Main Steam Line interface. Therefore,

a. Verifying the continuity of the explosive charges at least the importance of the functions it may perform. The probability of This is done to provide divisional control air/nitrogenforthe controls of GDC 55 no longer applies.

b Int a ingoneofthe explosivechargesonceeveryfuel reliable and timely actuation of this system is enhanced by inclusion of pneumatic equipment/instruments inside the drywell. 43.Incaseofalossofpowerevent,T5000F420Bcanbereopenedusinga ycle. The replacement charge shall be from the same fewer valves and simplicity of design. The use of a check valve outside 33. Flanged portion of the residual heat removal head spray piping, DC solenoid valve with a dedicated nitrogen supply system.

cyc plgethe containment is consistent with these system design requirements. betweenreactorpressurevesselandtherefuelingfloorbulkhead manufactured batch as the one fired or from another g 44. In case of a Beyond Design Basis External Event, T4600F400 and batch that has been certified by having one of-that 23. This is a penetration of the vent pipe inside the torus and thus is not a penetration, is permanently removed. T4600F401 can bereopened using a 3-way piloted shuttle valve with a batch successfully fired bona fide containment penetration. It is included in this table for Remaining line within the drywell is blind flanged. dedicated nitrogen supply system.

c. Replacingallchargesaccordingtothemanufacturer's copletenessonly. 34. Valve closes on a high drywell pressure signal to isolate the drywell 45. The Combustible Gas Control System (CGCS) hasbeen retiredin place recommended lifetime for the charges 24. This butterfly valve is normally closed and opens automatically to heat load. with itselectrical circuits de-energized andfluid process piping isolated

d. Performing Type C tests on the ball valves in prevent formation of negative pressure in the torus. This butterfly valve from containment with redundant isolation valves. These valves accordance with a performance based leak testing closes automatically upon increasing torus pressure and remains 35. SLCS initiation signal is not a containment isolation signal. This signal primarycontainmentwithredundantisolationvalves.Thesevalves program in Technical Specification 5.5.12. closed during containment high-pressure conditions. Upon loss of prevents removal of liquid poison in the event ofstandby liquid control are locked closed and can only be operated locally.

power or degraded voltage, the butterfly valve will open but closes system actuation.

18. Aplant modification, EDP-4940, changed the routing of the automatically once power is restored or voltage recovers. 36. PenetrationsX-13A and X-13B will have a 30-day water seal during and nitrogen purge supply line to the TIP system. The nitrogen source -followin apostulated LOCA. Therefore valves E1100-F050A F61 0A is taken from a primary containment pneumatic system line inside 25. Secondary containment to torusvacuum breaker. This vacuum breaker ap the drywell. PenetrationX-35Gthusbecomesaspare,thepipe opens automatically to prevent formation of a negative pressurein the F050B, and F610B are not considered containment isolation valves and penetrating the drywelliscappedand welded, and GDC 56 no torus. This line is essential to ensure primary containment structural therefore are not subject to Type C testing (see TS Amendment 98).

longer applies. integrity. The probability of system operation is enhanced by using 37.30-day water seal for penetrations X-13A and X-13B (duringand fewer valves and by the simplicity of design. The use of a check valve following a postulated LOCA) requiresexternal water leakage, through

19. The control rod drive (CRD) insert and withdrawal line. Each of outside containment is consistent with these system design valves El150-F015A and F015B, to be less than 5 ml/min. at 1.1 Pa, the 185 CRD withdrawal lines is separated from the RPV by a requirements. i.e., 62.2 psig. As these valves will be subjected to a more conservative redundant seal design in the CRD units. Each of the 185 CRD 26. The flow path associated with this penetration inside containment PIV test thatdemonstrates external leakage less than 5 mlmin. ata insert lines has a CRDM flange ball check valve that isolates the terminated below the low water level in the suppression pool. Awater pressure of 1045 psig, TS Amendment 98 exempts these valves from line from the RPVfollowing a scram. The redundant seal system, seal is assured during normal plant operation and for more than 30 Type C airtest.

the CRDM flange ball check valve, and a manual isolation valve days following an accident requiring containment isolation. It is not 38. Flexible wedge gate valve tested in the accident direction and through a provide adequate isolation in the event of a line break in the credible that these isolation valves will be exposed to the containment body\bonnet tap from asingle test connection. Leakage is measured hydraulic control unit (HCU) or the scram discharge volume atmosphere at any time following the accident. pastthe outboard seating surface.

(SDV).

These penetration containment isolation valves will be Type C seat 39. Single isolation valves on aclosed system both inside and outside of During a scram, the 185 outlet scram valves open and the four leak tested using water or air as the test medium. In some cases, due containment.

SDV vent and drain valves close. If the scram system is not reset, to system configuration, the Type C test pressure will not be in the The flow pathassociated with this penetration inside containment thus closing the scram inlet and outlet valves, CRD seal leakage same direction as the pressure existing when the valve is required to terminates below the low waterlevel in the suppression pool. Awater could slowly pressurize the SDV to the RPV pressure. Therefore, perform the containment isolation function. The valves will be a part of seal is assured during normal plant operation andfor more than 30 the SDV vent and drain valves along with 185 drive and 185 the periodic Type A tests where the test pressure is applied in the days following an accident requiring containment isolation. Itis not cooling water ball check valves will be Type A tested. correct direction. credible that these isolation valves will be exposed to the containment Leakage from the CRD system into the reactor building is detected 27. Relief valve used as a containment isolation valve. The construction atmosphere at any time following the accident.

for the full spectrum of leakage rates. Small leaks will be detected and orientation of this valve is such that increased containment Also many ofthe valves are required to be open post-accident to fulfill by observation during daily inspection rounds of the control unit pressure acts in conjunction with spring pressure to increase the their safety function.

areas by operators. Large leaks will be detected by duty timers on seating force of the valve and tends to reduce leakage. Thus the relief the reactor building floor drain sump pumps. A large leak of valve setpoint has no bearing on containment isolation. Type C LLRT testing is not required when the valve is located on a closed system and on a line which terminates below the minimum reactor coolant from any insert line will be automatically isolated 28. Flange on relief valve discharge to be Type B tested. water level of the suppression chamber.

bythe ball check valve intheCRD housing. Leaks of CRDsupply 29. Due to system configuration, the test pressure on the relief valve is not 40.Valveisinterlockedtoinhibitopeningonlowreactorwaterlevelsignal wtecnrlleindaTeCRDireedflowacontinol ecred in the same direction as the pressure existing when the relief valve is (Level 1) to ensure all RHRflow isdirected to the reactor vessel.

in thcontrolroom.TheCRDdirectionalcontrolvalvesare required to perform its containment isolation function. The test normally closed and are automatically closed upon a reactor pressure is applied under the relief valve seat. This is conservative scram signal. Excessive leakages through the scram valves will since it tends to unseat the relief valve.

be detected by duty timers on the sump pumps.

30. Not used.

20. The residual heat removal (RHR) system discharge line to the containment spray header receives an automatic containment isolation signal. The operator may, however manually override the isolation signal as needed to reduce containment temperature and pressure.

Page 38of 38 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-3 ELECTRICAL PENETRATION SCHEDULE Penetration Number Penetration Type T2301-X-100A Neutron monitor T2301-X-100B T2301-X-100F T2301-X-100G T2301-X-101A Medium voltage power (5kV)

Recirculating pump power T2301-X-101B T2301-X-101C T2301-X-101D T2301-X-101E T2301-X-101F T2301-X-102A Low-voltage switching/RPS T2301-X-102B T2301-X-102C T2301-X-102D T2301-X-103A Thermocouples T2301-X-103B T2301-X-104A Control rod drive position indicators T2301-X-104B T2301-X-104C T2301-X-104D T2301-X-104E T2301-X-104F T2301-X-105A Low-voltage power (480 V)

T2301-X-105D T2301-X -106A Low level signal vibration test T2301-X-106B Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-4 DRYWELL TO SUPPRESSION CHAMBER VACUUM BREAKER VALVE DATA

1. Number of drywell-to-suppression 12 chamber vacuum breaker valves

2. Valve size 20 in. seat x 18 in.

flanged outlet

3. Valve location Elevation Valve centerline 562 ft 8.5 in.

Position Two valves on each drywell support chamber downcomer with azimuth locations 22° - 30', 67° - 30' 112° - 30', 247° - 30',

292° - 30', and 337° - 30'

4. Differential pressure to open 0.5 psid

5. Valve manufacturer GPE Controls of Morton Grove, Illinois

6. Design temperature 350 °F

7. Design pressure 62 psig

8. Hydrostatic test pressure 87 psig

9. Valve position indication Limit switches, circuitry, and indicator lights.

Closed limit switches are redundant

10. Main control room panel number Indicating lights are on panel H11-P808 and H11-P817 Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-5 PRIMARY SYSTEM ENERGY DISTRIBUTION AT THE TIME A RECIRCULATION LINE BREAK ACCIDENT OCCURS Fluid Energya Energy (106 Btu)

1. Steam 30.6

2. Liquid 346.8 Sensible Energy

1. Reactor pressure vessel 103

2. Reactor internals (less core) 78.9

3. Core 7.5 a

All energy values are based on a 32 °F datum. Fuel energy is based on a datum of 285 °F.

Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-6 HAS BEEN INTENTIONALLY DELETED Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-7 ACCIDENT CHRONOLOGY DESIGN BASIS RECIRCULATION LINE BREAK ACCIDENT Time (sec)

Minimum ECCS Available

1. Vents cleared 0.2

2. Drywell reaches peak pressure 4.6

3. Maximum positive differential pressure occurs 4.6

4. Initiation of the ECCS 60

5. Vessel reflooded 220

6. Introduction of RHR heat exchanger 1200

7. Containment reaches peak secondary pressure 1 x 104 (2.8 hr)

This value taken from the containment analysis models; it is onlysignificant in confirming that core reflooding occurs before pool cooling or other RHR functions are needed.

The containment analysis was based on a 30-sec maximum analyzed HPCI response time. The HPCI design basis has been subsequently revised to incorporate a 60-sec maximum system response time. The containment analysis is not impacted by increasing the HPCI response time from 30 sec to 60 sec. The short-term containment analysis calculates a peak containment pressure before the HPCI injects. The long-term calculation assumes one RHR loop is operating in the containment cooling mode at partial pumping capacity.

Core cooling is provided by the core spray system and the RHR/LPCI pump and no credit was taken for the HPCI system (UFSAR Section 6.2.1.3.3) for long-term core makeup.

Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-8 PRIMARY AND SECONDARY CONTAINMENTS SURFACE COATING SCHEDULE PRIMARY CONTAINMENTf Approx.

Approx. Total Average Surface Type of Coating Location DFTa (mils) (ft2)

Drywell interior steel Carbozinc 11 7 120,000 Interior structural steel hangers and supports Vent line interior Plasite 7155bc Torus interior 12 38,000 Carboguard Torus interior 40 34,300 6250 Nb,c,e Vent header interior Vent line interior tie-in to vent header Ameron 66 and RPV support pedestal 1/16 in. 7,380 Surfacerb Drywell concrete floors plus10 mils Drywell concrete walls Unqualified Miscellaneous Note e Note e Paintse Carboguard Drywell dado region 6 232 890N SECONDARY CONTAINMENT Thickness, Thickness, Location Area(ft2) Primer Approx. (in.) Top Coat Approx. (in)

Drywell exterior steel 36,200 Carbozinc 11 0.002 +/- 0.002 None -

0.001 Torus exterior steel 84,000 Carbomastic 15 0.002 - 0.009 None -

Secondary containment concrete 109,200 Carboline 295 0.020 - 0.040 Carboline 288 0.008 Secondary containment structural 29,000 Type II red 0.001 to Cooks 0.002 steel leadd 0.00153 Amercote Enameld a

DFT = Dry Film Thickness.

b Qualified Coating; other coatings are unqualified.

c Other compatible touch-up coatings are used inside the torus.

d Other compatible coatings per Specification 3071-055 per painting system PS-2 are used on top or in lieu of Cooks Amercote Enamel and Type II red lead.

e For current unidentified and unqualified coating totals, see the design calculations for the Torus strainers.

f Coating materials listed in this table are estimated quantities of significant coating materials inside containment. Actual coating materials and quantities inside containment are managed as indicated in design calculations for the Torus strainers.

Page 1 of 1 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-9 WIRING INSULATION Approximate Type Amount (lb)

Primary Containment Cable Power and control cable EPR Hypalon Silicone Rubber 5,340 25 Instrument Cross-linked Polyethylene or Polyolefin 5

Thermocouple Polyamide Capton 18 Secondary Containment Cable Power EPR Hypalon and Neoprene 137,000a Control EPR Hypalon and Neoprene 14,000a Instrument Cross-linked Polyethylene by Raychem 99,000a Thermocouple Polyamide Capton 25 a

In addition to the amounts shown here in cable trays, there is an approximate additional 15 percent in conduit.

Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-10 OTHER ORGANIC COMPOUNDS Commercial Name Compound Quantity (approx.)

Primary Containment Shell to concrete joints Dow Corning/ Silicone rubber 1900 in.3 DOWSIL 790*

Concrete floor to wall Carboline 225 Epoxy polysulfide 400 in.3 joints Secondary Containment Steel wall panel gaskets Blanchard Foam Guard Polyvinyl chloride 40 ft3-340 lb to 620 lb Steel wall panel 3M THIOKOL Weatherban Polysulfide rubber 40 ft3-580 lb caulking Concrete floor joints Carboline 225 Epoxy polysulfide 14 ft3

• Note: Dow Corning 790 is retained as a historic information as Dow Corning 790 product name was rebranded to DOWSIL 790.

Page 1 of 1 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-11 STANDBY GAS TREATMENT SYSTEM MAJOR COMPONENT DESCRIPTION Filter Train Type Multiple filters for removal or particulates, elemental iodine, and organic iodine from air Quantity Two 100 percent-capacity trains Capacity, scfm air 4000 each Demister (Each Train)

Type Impingement Quantity One Water removal rate, lb/min 20 Static resistance at design flow in. H2O 1 max at 4000 scfm with 0.005 lb/ft3 of free moisture Prefilter (Each Train)

Type Dry disposable cartridge Quantity One bank Capacity, scfm air 4000 Media Glass fiber Efficiency, percent 85 (NBS dust spot)

Heater (Each Train)

Type Electric, open, single-stage, on-off Quantity One Capacity, kW 24 Accessories Overload cutout HEPA Filters (Each Train)

Type High-efficiency, dry Page 1 of 3 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-11 STANDBY GAS TREATMENT SYSTEM MAJOR COMPONENT DESCRIPTION Quantity Two banks (one before and one after charcoal absorber)

Elements per bank Four Capacity, scfm air 4000 Media Waterproof, glass Separator material Aluminum Frame material Steel Charcoal Adsorber Bed (Each Train)

Type Deep bed Quantity One Capacity, scfm air 4000 Media Impregnated Carbon Quantity of media, lb 1250-1500 lbm (nominal)

Efficiency Lab tested to ensure 99.9 percent removal efficiency for methyl iodide. Installed and tested in the adsorber housing such that an overall decontamination efficiency of 99 percent is assumed for removal of all forms of gaseous iodine.

Charcoal volume, ft3 50 (approximately)

Charcoal density, lb/ft3 23.7 Minm Depth of bed, in. 6 Face velocity, ft/minute 40 Residence time, seconds 0.75 Ignition temperature, °F 625 (approximately)

Iodine desorption temperature, °F 355 Page 2 of 3 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-11 STANDBY GAS TREATMENT SYSTEM MAJOR COMPONENT DESCRIPTION Charcoal loading, mg iodine/g carbon 2.5 (approximately)

(30-day accident duration)

Media Particle Size Distribution USS Mesh 8 3 percent 12 51 percent 16 40 percent 18 5 percent Fines 1 percent SGTS Exhaust Blower (Each Train)

Quantity and type One Centrifugal (with inlet vanes)

Capacity, scfm 4000 Static pressure, in. H2O 20 Drive V-belt Motor, hp 25 Standby Cooling Air Fan Quantity and type One centrifugal Capacity, scfm air 1000 Static pressure, in. H2O 18 Drive V-belt Motor, hp 10 Page 3 of 3 REV 24 11/22

FERMI 2 UFSAR TABLE 6.2-12 STANDBY GAS TREATMENT SYSTEM EQUIPMENT FAILURE ANALYSIS Component Failure Failure Detected By Action SGTS primary blower Monitor burnout, drive Flow monitor - low Main control board alarm shaft break, trip, etc. pressure switch Operating equipment train shutdown (manual)

Redundant train startup (manual)

Electric heating coil Element overheat High temperature cutout Circuit trip on coil Electric heating coil Element burnout Temperature indicator or High moisture alarm moisture detector Operating equipment train upstream of adsorber shutdown (manual)

Redundant train startup (manual)

Standby cooling fan No start or failure results Temperature switches Alarm sounds in main control in high charcoal adsorber room (automatic if setpoint temperature achieved)

CO2 is auto backup to cooling fan if charcoal bed temperature raises to 310 °F Flow-control valve Falls in open position High P indicator across Main control board alarm filters, demisters, and adsorber High building vacuum Operating equipment train shut-alarm down (manual)

Redundant train startup (manual)

Isolation valves positioned (automatic)

Isolation valve Falls in open position Local indicator light No automatic action.

Requires backflow prevention and building isolation accomplished by series valves Page 1 of 2 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-12 STANDBY GAS TREATMENT SYSTEM EQUIPMENT FAILURE ANALYSIS Component Failure Failure Detected By Action Falls in closed position Flow monitor - low- Main control board alarm pressure switch Operating equipment train shutdown (manual)

Redundant train startup (manual)

Isolation valve positioned (automatic)

HEPA filter High particulate loading High P indication Operating equipment train shutdown (manual)

Redundant train startup (manual)

Isolation valves positioned (automatic)

Charcoal filter High temperature Temperature elements Alarm sounds start cooling fan Page 2 of 2 REV 16 10/09

FERMI 2 UFSAR TABLE 6.2-13 REMOTE MANUALLY OPERATED CONTAINMENT ISOLATION VALVES WITH LEAK DETECTION CAPABILITY Penetration Valve Penetration Valve X-27 T5000F401B T5000F402B T5000F403B T5000F404B T5000F405B T50-F458 P34F403A P34F404A X-9A E4150F006 X-9B E5150F013 X-29Be T5000F420B X-10 E5150F007 X-34A P4400F606B E5150F008 X-34B P4400F615 P4400F607B X-11 E4150F002 E4150F003 X-35B-F TIP shear valves E4150F600 X-13A E1150F015B E1150F610B X-40Dd P34F401B X-13B E1150F015A E1150F610A X-47e T5000F420A X-16A E2150F005B X-48 T5000F401A T5000F402A X-16B E2150F005A T5000F403A T5000F404A T5000F405A X-219 T5000F408B X-23 P4400F606A X-24 P4400F616 P4400F607A X-223A E1150F004D X-223B E1150F004B X-48 P34F403B P34F404B X-223C E1150F004C Page 1 of 2 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-13 REMOTE MANUALLY OPERATED CONTAINMENT ISOLATION VALVES WITH LEAK DETECTION CAPABILITY Penetration Valve Penetration Valve X-223D E1150F004A X-224A E2150F036B X-224B E2150F036A X-206A E41F402 X-225 E4150F042 X-206B E41F403 X-226 E5150F031 X-206C E41F401 X-227A E2150F031B E4150F012 X-206D E41F400 X-227B E5150F019 E2150F031A X-210A E1150F007B E1150F026B X-210B E1150F007A X-230 T5000F407A P34F407 P34F405B P34F409 P34F406B X-231 T5000F407B X-215 T5000F408A P34F405A P34F408 P34F406A P34F410 X-206E T50F412A X-206F T50F412B X-28Cf P34F401A X-29Bb E11F412 X-29Bc E11F413 X-47a E11F414 X-47b E11F415 Page 2 of 2 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-14 PRIMARY CONTAINMENT PENETRATION PIPE LINES CONNECTING CLOSED-LOOP QUALITY GROUP B SYSTEMS TO QUALITY GROUP D SYSTEMS Line Diameter System Line (in.) Separation Valve Emergency core cooling - high Turbine exhaust drain to barometric 1 SOV pressure coolant injection condenser Interstage tap to barometric condenser 2 MOV Pressure source from the condensate system 3/4 CV, CV through the Torus Water Management System (TWMS) supplying HPCI pump discharge piping Condensate to radwaste 1 CV, AOV, AOV (1)

Suction from condensate storage 14 CV, MOV (1)

Discharge to condensate storage 10 MOV, AOV (1)

Steam drain to main condenser 1 AOV, AOV (1)

Emergency core cooling - core Suction from condensate storage 16 LCV spray Keep full line from demineralizer water 3, 3 CV, CV system Emergence core cooling - Keep full line from demineralizer water 4, 4 CV, CV residual heat removal system Supply from RHRSW system 12 TC, MOV (1)

RHR drain to radwaste 4 MOV, MOV (1)

To fuel pool cleanup 8 LCV From fuel pool cleanup 8 LCV From chemical clean 4, 4 MV (NC)

To process sampling system 1/2 AOV, AOV (1)

From FLEX supply piping Div 1 8 LCV From FLEX supply piping Div 2 8 LCV Reactor core isolation cooling Turbine exhaust drain to barometric 3/4 MV, MV, MV condenser Page 1 of 2 REV 20 05/16

FERMI 2 UFSAR TABLE 6.2-14 PRIMARY CONTAINMENT PENETRATION PIPE LINES CONNECTING CLOSED-LOOP QUALITY GROUP B SYSTEMS TO QUALITY GROUP D SYSTEMS Line Diameter System Line (in.) Separation Valve Discharge to lube oil cooler 2 MOV Condensate to radwaste 1 CV, AOV, AOV (1)

Suction from condensate storage 6 CV, MOV (1)

Steam drain to main condenser 1 SOV, SOV (1)

Combustible gas control None Symbols:

SOV = solenoid-operated valve TC = testable check valve MOV = motor-operated valve MV = manual valve CV = check valve (1) = on isolation panel AOV = air-operated valve (NC) = normally closed LCV = locked-closed valve Page 2 of 2 REV 20 05/16

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-7A Main steam line A B2103F022A Nonessential These lines provide a heat- sink path for the reactor MSIV leakage control B2103F028A Nonessential pressure vessel. It is desirable to keep the MSIVs open for this function during postulated small leaks or breaks. Therefore, high drywell pressure has been deliberately omitted from isolation of main steam lines.

The MSIVs and the main steam line drains also isolate on signals D, E, F, G, J, P, and RM.

X-7B Main steam line B B2103F022B Nonessential B2103F028B Nonessential MSIV leakage control X-7C Main steam line C B2103F022C Nonessential B2103F028C Nonessential MSIV leakage control X-7D Main steam line D B2103F022D Nonessential B2103F028D Nonessential MSIV leakage control X-8 Main steam line drains B2103F016 Nonessential B2103F019 Nonessential X-9A Feedwater line A B2100F010A Essential The portion of the feed-water line that is Class 1 is B2100F032A Essential essential. During the postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply.

B2100F076A Essential This valve is provided for long-term leaktightness only.

Remote manual control is provided in the control room to close the valve upon indication of loss of feedwater flow.

X-9A High-pressure coolant E4150F006 Essential Automatically opens and closes with HPCI pump Injection operation.

X-9B Feedwater line B B2100F010B Essential The portion of the feedwater line that is Class 1 is B2100F032B Essential essential. During the postulated LOCA, it is desirable to maintain reactor coolant makeup from all sources of supply.

B2100F076B Essential This valve is provided for long-term leaktightness only.

Remote manual control is provided in the control room to close the valve upon indication of loss of feedwater flow.

X-9B Reactor core isolation E5150F013 Essential Automatically opens and closes with RCIC pump Cooling (safety system) operation.

X-9B Reactor water cleanup G3352F220 Nonessential Inadvertent isolation of this line due to inclusion of the high drywell pressure signal is undesirable, as it results in reactor coolant chemistry problems, fuel leaks, and RPV bottom thermal problems.

RWCU is desirable for post-accident sampling of reactor coolant.

The system includes break detection mechanisms that will automatically isolate on unbalanced flow or high temperature. Therefore, isolation on high drywell pressure is not needed.

X-10 Steam to RCIC turbine E5150F007 Essential E5150F008 Essential Page 1 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-11 Steam to HPCI turbine E4150F002 Essential E4150F003 Essential E4150F600 Essential X-12 RHR/RHR pump suction E1150F009 Nonessential High drywell pressure has been deliberately omitted from recirculation piping E1150F608 Nonessential from this line's isolation initiation to avoid the loss of E1150F008 Nonessential the shutdown cooling mode of RHR for small breaks or leaks.

X-13A RHR/RHR pump E1100F050B Essential Not a containment isolation valve.

discharge to recirculation E1150F015B Essential loop X-13B RHR/RHR pump E1100F050A Essential Not a containment isolation valve.

discharge to recirculation E1150F015A Essential loop X-15 Combustible gas control T4804F603A Nonessential The CGCS PCIVs are permanently de-energized and system suction T4804F605A Nonessential locked closed.

X-16A Core spray pump E2100F006B Essential discharge E2150F005B Essential X-16B Core spray pump E2100F006A Essential discharge E2150F005A Essential X-17 RHR/RHR head spray E1150F023 Nonessential High drywell pressure was deliberately omitted from (piping within the E1150F022 Nonessential this line's isolation initiation to avoid the loss of the drywell is blanked off) head spray mode of RHR for small breaks or leaks.

X-18 Radwaste system/drywell G1100F003 Nonessential floor drains sump pump G1154F600 Nonessential discharge X-19 Radwaste system/drywell G1100F019 Nonessential equipment drains sump G1154F018 Nonessential pump discharge X-20 Demineralized service P1100F126 Nonessential water to drywell X-22 Station and control air/ T4901F465 Essential Manual override is available to operator.

nitrogen inerting system/ T4901F601 Essential drywell equipment T4901F007 Essential pneumatic supply Division I X-23 Reactor building closed P4400F606A Essential Closes on high drywell pressure cooling water and P4400F282A Essential emergency equipment cooling water systems supply X-24 Reactor building closed P4400F616 Essential cooling water and P4400F607A Essential emergency cooling water systems return X-25 Reactor building HVAC/ T4600F402 Nonessential drywell exhaust and air T4803F602 Nonessential purge T4600F411 Nonessential X-26 Nitrogen inerting system T4800F408 Nonessential and reactor building T4803F601 Nonessential HVAC/ T4800F407 Nonessential drywell air purge inlet X-27a PCMS containment T5000F401B Essential atmosphere sample Page 2 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-27b PCMS containment T5000F402B Essential atmosphere sample X-27c PCMS containment T5000F403B Essential atmosphere sample X-27d PCMS containment T5000F404B Essential atmosphere sample X-27e PCMS containment T5000F405B Essential atmosphere sample X-27f Drywell pressure T50-F458 Essential instrumentation X-27b PASSb/containment P34F403A Nonessential Administrative control utilized.

drywell P34F404A Nonessential atmosphere sample X-28Cf PASS/pressurized reactor P34F401A Nonessential Administrative control utilized. Orifice in line inside coolant sample containment.

X-29Aa Process sample/reactor B3100F019 Nonessential recirculation water B3100F020 Nonessential sample X-29Bc PCMS/drywell E11F413 Essential instrumentation X-29Bb PCMS/drywell E11F412 Essential instrumentation X-29Be PCMS/drywell T5000F420B Essential instrumentation X-30Aa RWCU/RPV pressure G33F583 Essential X-31Ba Nitrogen inerting system/ T4800F453 Nonessential drywell nitrogen makeup T4800F454 Nonessential and vent T4800F455 Nonessential X-32Ba Steam flow to HPCI E4100F503 Essential (instrumentation)

X-32Bb Steam flow to HPCI E4100F502 Essential (instrumentation)

X-33Bc Core spray/RPV pressure E21F500A Essential (instrumentation)

X-33Ba Steam flow to HPCI E4100F501 Essential (instrumentation)

X-33Bb Steam flow to HPCI E4100F500 Essential (instrumentation)

X-34A RBCCW and emergency P4400F606B Essential Closes on high drywell pressure cooling water systems P4400F282B Essential supply X-34B RBCCW and emergency P4400F607B Essential cooling water systems P4400F615 return X-35B NMS/TIP system Nonessential System normally isolated and closed inside containment.

X-35C NMS/TIP system Nonessential Page 3 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-35D NMS/TIP system Nonessential X-35E NMS/TIP system Nonessential X-35F NMS/TIP system Nonessential X-35G TIP system spare Nonessential X-36 Station and control air/ T4901F468 Essential Manual override is available to operator.

nitrogen inerting system/ T4901F602 Essential drywell equipment T4901F016 Essential pneumatic supply, Division II X- CRD/control rod drive None Essential 37A,B,C,D insertion line X- CRD/control rod drive None Essential 38A,B,C,D withdrawal line X-39A RHR/RHR to E1150F021A Essential containment E1150F016A Essential spray header X-39B RHR/RHR to E1150F021B Essential containment E1150F016B Essential spray header X-40Dd PASS/pressurized reactor P34F401B Nonessential Administrative control utilized. Orifice in line inside coolant sample containment.

X-42 SLCS/standby liquid C4100F007 Essential control C4100F006 Essential X-43 RWCU/reactor water G3352F001 Nonessential Inadvertent isolation of this line due to inclusion of the (cleanup G3352F004 Nonessential high-drywell-pressure signal is undesirable, as it results from recirculation piping) in reactor coolant chemistry problems, fuel leaks, and RPV bottom thermal problems.

RWCU is desirable for postaccident sampling of reactor coolant.

The system includes break-detection mechanisms that will automatically isolate on unbalanced flow or high temperature. Therefore, isolation on high drywell pressure is not needed.

X-44 CGCS/combustible gas T4804F603B Nonessential The CGCS PCIVs are permanently de-energized and control system suction T4804F605B Nonessential locked closed.

X-47a PCMS/drywell E11F414 Essential instrumentation X-47b PCMS/drywell E11F415 Essential instrumentation X-47e PCMS/drywell pressure T5000F420A Essential X-48b PCMS/containment T5000F402A Essential See also containment penetration "PCRMS."

atmosphere sample X-48c PCMS/containment T5000F403A Essential See also containment penetration "PCRMS."

atmosphere sample X-48d PCMS/containment T5000F404A Essential See also containment penetration "PCRMS."

atmosphere sample X-48e PCMS/containment T5000F405A Essential See also containment penetration "PCRMS."

atmosphere sample Page 4 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-48f PASS/containment P34F403B Nonessential Administrative control utilized.

drywell atmosphere P34F404B sample X-49a Reactor recirculation/ B3100F016A Nonessential High-pressure line with globe valves inside and outside recirculation pump seal B3100F014A Nonessential containment, and an orifice in the line to prevent purge backflow.

X-51a Reactor recirculation/ B3100F016B Nonessential High-pressure line with globe valves inside and outside recirculation pump seal B3100F014B Nonessential containment, and an orifice in the line to prevent purge backflow.

X-52e Steam flow to RCIC E51F506 Essential (instrumentation)

X-52f Steam flow to RCIC E51F505 Essential (instrumentation)

X-53a Steam flow to RCIC E51F503 Essential (instrumentation)

X-53b Steam flow to RCIC E51F504 Essential (instrumentation)

X-53c Core spray/RPV pressure E21F500B Essential (instrumentation)

X-204A Nitrogen inerting T4800F416 Nonessential Electrically de-energized system/drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400A X-204B Nitrogen inerting T4800F417 Nonessential Electrically de-energized system/drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400B X-204C Nitrogen inerting T4800F418 Nonessential Electrically de-energized system/drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400C X-204D Nitrogen inerting T4800F419 Nonessential Electrically de-energized system/drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400D X-204E Nitrogen inerting T4800F420 Nonessential Electrically de-energized system/drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400E X-204F Nitrogen inerting system/ T4800F421 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400F X-204G Nitrogen inerting system/ T4800F422 Nonessential Electrically de-eneregized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400G Page 5 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-204H Nitrogen inerting system/ T4800F423 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400H X-204J Nitrogen inerting system/ T4800F424 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400J X-204K Nitrogen inerting system/ T4800F425 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400K X-204L Nitrogen inerting system/ T4800F426 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400L X-204M Nitrogen inerting system/ T4800F427 Nonessential Electrically de-energized drywell to torus vacuum breaker nitrogen supply, vacuum breaker valve T2300F400M X-205A Primary containment T2300F450B Essential Provisions for administrative control ensure that the system/ valve is not inadvertently positioned open by the to secondary containment T2300F410 Essential operator. This does not prevent automatic operation to to torus vacuum breaker control primary containment vacuum formation.

X-205B Primary containment T2300F450A Essential Provisions for administrative control ensure that the system/secondary valve is not inadvertently positioned open by the containment to T2300F409 Essential operator. This does not prevent automatic operation to torus vacuum breaker control primary containment vacuum formation.

X-205C Nitrogen inerting system T4800F409 Nonessential and reactor building T4800F404 Nonessential HVAC/suppression pool T4800F405 Nonessential air purge inlet X-205D Nitrogen inerting system T4600F400 Nonessential and reactor building T4600F401 Nonessential HVAC/suppression pool T4600F412 Nonessential exhaust air purge to standby gas treatment Torus nitrogen inerting T4800F410 Nonessential inlet Torus nitrogen makeup T4800F456 Nonessential and T4800F457 Nonessential Vent T4800F458 Nonessential X-206A PCMS/liquid level E41F402 Essential Accident monitoring instrumentation.

indicators X-206B PCMS/liquid level E41F403 Essential indicators X-206C PCMS/liquid level E41F401 Essential indicators X-206D PCMS/liquid level E41F400 Essential Valves fail as is.

indicators X-206E PCMS/liquid level T50F412A Essential indicators Page 6 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-206E PCMS/suppression pool Essential liquid level indicators X-206F PCMS/liquid level T50F412B Essential indicators X-206F PCMS/suppression pool Essential liquid level indicators X-210A RHR/RHR minimum E1150F007B Essential flow RHR heat exchanger E1100F025B Essential discharge header thermal relief RHR/RHR test line E1150F024B Essential Manual override available to operator.

RHR/RHR heat E1100F001B Essential exchanger thermal relief RHR warmup line E1150F026B Nonessential X-210B PASS/containment liquid P34F407 Nonessential Administrative control utilized.

sample return P34F409 Nonessential X-210B TWMS G5100F604 Nonessential G5100F605 Nonessential X-210B RHR/suction thermal E1100F029 Nonessential relief RHR/heat exchanger E1100F025A Essential discharge header thermal relief RHR/heat exchanger E1100F001A Essential relief RHR/minimum flow E1150F007A Essential RHR/test line E1150F024A Essential X-211A RHR/RHR suppression E1150F027B Essential pool Spray E1150F028B Essential X-211B RHR/RHR suppression E1150F028A Essential pool Spray E1150F027A Essential X-212 RCIC turbine exhaust line E5150F001 Essential X-213A TWMS suction G5100F600 Nonessential G5100F601 Nonessential X-213B TWMS suction G5100F602 Nonessential G5100F603 Nonessential X-214 HPCI vacuum breaker E4150F075 Essential line E4150F079 Essential X-214 RCIC vacuum breaker E5150F062 Essential line E5150F084 Essential X-215 PCMS return Division I T5000F408A Essential See also containment penetration "PCRMS."

X-215 CGCS/combustible gas T4804F602A Nonessential The CGCS PCIVs are permanently de-energized and control system suction T4804F606A Nonessential locked closed.

X-215 PASS/containment P34F408 Nonessential Administrative control utilized.

gaseous sample return P34F410 Nonessential Page 7 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-218 CGCS/combustible gas T4804F601A Nonessential The CGCS PCIVs are permanently de-energized and control system return T4804F604A Nonessential locked closed.

T4804F016A Nonessential T4804F601B Nonessential T4804F604B Nonessential T4804F016B Nonessential X-219 CGCS/combustible gas T4804F602B Nonessential The CGCS PCIVs are permanently de-energized and control system suction T4804F606B Nonessential locked closed.

X-219 PCMS return Division II T5000F408B Essential X-220 HPCI turbine exhaust line E4150F021 Essential X-221 HPCI turbine exhaust E4150F022 Essential drain X-222 RCIC vacuum pump E5150F002 Essential discharge X-223A RHR/RHR pump suction E1150F004D Essential X-223A RHR/RHR pump suction E1100F030D Essential header thermal relief X-223B RHR/RHR pump suction E1150F004B Essential X-223B RHR/RHR pump suction E1100F030B Essential header thermal relief X-223C RHR/RHR pump suction E1150F004C Essential X-223C RHR/RHR pump suction E1100F030C Essential header thermal relief X-223D RHR/RHR pump suction E1150F004A Essential X-223D RHR/RHR pump suction E1100F030A Essential header thermal relief X-224A Core spray pump suction E2150F036B Essential X-224B Core spray pump suction E2150F036A Essential X-225 HPCI pump suction E4150F042 Essential X-226 RCIC pump suction E5150F031 Essential X-227A TWMS discharge G5100F606 Nonessential G5100F607 Nonessential X-227A HPCI minimum flow E4150F012 Essential X-227A Core spray pump suction E2100F032B Essential thermal relief X-227A Core spray pump E2100F012B Essential discharge header relief E2100F011B X-227A Core spray pump E2150F031B Essential minimum flow X-227A Core spray pump test line E2150F015B Nonessential X-227B RCIC minimum flow E5150F019 Essential X-227B Core spray pump suction E2100F032A Essential thermal relief X-227B Core spray pump E2100F012A Essential discharge E2100F011A Essential header relief Page 8 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-15 ESSENTIAL/NONESSENTIAL LINES Containment Containment Penetration Valve Isolation Number System/Line Number Classification Signalsa Comments X-227B Core spray pump test line E2150F015A Nonessential X-227B Core spray minimum E2150F031A Essential flow X-230 PASS/suppression pool P34F405B Nonessential Administrative control utilized Atmosphere sample P34F406B Nonessential X-230 PCMS suction Division I T5000F407A Essential X-231 PCMS suction Division II T5000F407B Essential X-231 PASS/suppression pool P34F405A Nonessential Administrative control utilized.

atmosphere sample P34F406A Nonessential PCRMS Primary containment T50F450 Nonessential Sample suction X-48.

radiation monitor T5000F456 Nonessential Sample suction X-48.

T50F451 Nonessential Sample return X-215.

T5000F455 Nonessential Sample return X-215.

a Containment Isolation Signals are contained in UFSAR Table 6.2-2.

b PASS is postaccident sampling system.

Page 9 of 9 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-16 ESSENTIAL/NONESSENTIAL SYSTEMS System Classification Comments Main Steam Nonessential Not required for shutdown.

Feedwater Nonessential Not required for shutdown.

Portion that is Class 1 is essential.

Reactor core isolation Essential Necessary for core cool-cooling down following isolation from the turbine condenser and feedwater makeup.

Reactor water cleanup Nonessential Not required during and immediately following an accident.

High pressure coolant Essential Safety system.

injection Core spray Essential Safety system.

Standby liquid Control Essential Should be available as a post LOCA pH control system and backup to CRD system.

Drywell floor/equipment Nonessential Not necessary for core drains cooldown.

Torus water management Nonessential Not required for reactor shutdown cooling.

Primary containment Essential Required for postaccident monitoring system monitoring of containment atmosphere hydrogen concentration.

Primary containment Nonessential Not required during or radiation monitoring system immediately after an accident.

Residual heat removal Heat exchangers Essential Main heat sink during isolation.

Page 1 of 3 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-16 ESSENTIAL/NONESSENTIAL SYSTEMS System Classification Comments Shutdown cooling Nonessential Nonessential, but desirable to use if available. Not redundant, but safety grade.

Drywell/suppression Essential Necessary to control pool spray pressure.

LPCI function Essential Safety function.

Keep-filled system Nonessential Not required after accident.

Control rod drive Essential Necessary for shutdown. No credit taken for reflood, but is desirable.

Emergency equipment Essential Necessary to cool safety cooling water system pumps and motors.

Station and control air Pneumatic supply to Essential For safety/relief valves on primary containment steam lines and ADS accumulators.

Demineralized service water Nonessential Not assumed available in ECCS analysis.

Nitrogen inerting Nonessential Not required during and immediately after accident.

Reactor building closed Nonessential Used for normal operation cooling water only.

Reactor recirculation Nonessential Not required because core can be cooled by natural circulation.

Traversing in-core probe Nonessential Not required for reactor shutdown cooling.

Page 2 of 3 REV 23 02/21

FERMI 2 UFSAR TABLE 6.2-16 ESSENTIAL/NONESSENTIAL SYSTEMS System Classification Comments Primary containment Essential Vacuum breakers (vacuum breakers between automatically open to secondary containment and prevent formation of suppression pool) excessive negative pressure in the suppression pool chamber. They close automatically upon increasing suppression pool chamber pressure and remain closed during all containment high-pressure conditions.

Reactor building heating, Nonessential Reactor building purge and ventilation and air vent functions are conditioning nonessential. Essential cooling is provided by equipment outside primary containment.

Page 3 of 3 REV 23 02/21

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Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-5 PRIMARY CONTAINMENT PERSONNEL HATCH

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1. Drywell head.

2. Equipment access hatch in cylindrical portion of Drywell.

Fermi 2

3. Rod removal hatch in the spherical UPDATED FINAL SAFETY ANALYSIS REPORT portion of Drywell.

4. Access to the pressure suppression FIGURE 6.2-6 chamber PRIMARY CONTAINMENT EQUIPMENT HATCH

POINT OF CRITICAL FLOW REACTOR VESSEL RECIRC a* RECIRC LINE RECIRC b* CLEANUP LINE LOOP' LOOP c* 10 JET PUMP NOZZLES

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REV. 6 3/93

WW a: a:

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ci ci ci LO 81Sd '3HnSS3Hd Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-9 RECIRCULATION LINE BREAK PRIMARY CONTAINMENT INITIAL PRESSURE TRANSIENT (3499 MWT)

REV 6 3/93

WW c:C:

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REV 6 3/93

LO 0

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REV 6 3/93

LO o

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REV 6 3/93

I

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LONG TERM RESPONSE (3499 MWT)

REV 6 3/93

FIGURE 6.2-14 HAS BEEN INTENTIONALLY DELETED REV 6 3/93

OO~--------------r---------------r---------------r---------------r---------------'

1. DRYWELL PRESSURE

2. SUPPRESSION CHAMBER PRESSURE 40 C) 0; c.

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10 102 103 104 TIME. SECONDS

• NOTE:

THE CONTAINMENT TEMPERATURE RESPONSE DUE TO THE SSA HAS ALSO BEEN RE-EVALUATED USING THE BASES PROVIDED IN REFERENCES 1 AND 3. THE PREDICTED SHORT-TERM RESPONSE IS REPORTED IN REFERENCE 2.

• EDISON NOTE TO GE DRAWING Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-15 0.1 FT2 LIQUID BREAK PRIMARY CONTAINMENT PRESSURE RESPONSE (BASED ON ORIGINAL POWER OF 3358 MWT)

REV 9 4/99

300. r---------.--------,--------,-:---------,--------, 1 DRVWELL TEMPERATURE 2 SUPPRESSION POOL TEMpERATURE 200.

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• NOTE:

THE CONTAINMENT TEMPERATURE RESPONSE DUE TO THE SBA HAS ALSO BEEN RE-EVALUATED USING THE BASES PROVIDED IN REFERENCES 1 AND 3. THE PREDICTED SHORT-TERM RESPONSE IS REPORTED IN REFERENCE 2.

• EDISON NOTE TO GE DRAWING.

Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-16 0.1 FT2 LIQUID BREAK PRIMARY CONTAINMENT TEMPERATURE RESPONSE (BASED ON ORiGINAL POWER OF 3,358 MWr)

REV 9 4/99*

FIGURES 6.2-17 THROUGH 6.2-19 HAVE BEEN INTENTIONALLY DELETED REV 6 3/93

Figure Intentionally Removed Refer to Plant Drawing I-2649-01 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-20 STANDBY GAS TREATMENT SYSTEM P&ID REV 22 04/19

06L H. r+/-4L 1~

- 1-0.5 0.4- - 4h E :t 0.3-0.2 -

0.1 0.0

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-0.4 1 10 100 1,000 10,000 Time, seconds Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-21 SECONDARY CONTAINMENT RESPONSE DUE TO A DBA-LOCA REV 21 10/17

FIGURE 6.2-22 HAS BEEN INTENTIONALLY DELETED REV 23 02/21

Figure Intentionally Removed Refer to Plant Drawing M-2087 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-23 POST-LOCA RECOMBINER P&ID REV 22 04/19

FIGURE 6.2-24 HAS BEEN INTENTIONALLY DELETED REV 23 02/21

FIGURE 6.2-25 HAS BEEN INTENTIONALLY DELETED REV 23 02/21

60.~--------------r---------------'----------------r---------------,

1 DRYWELL PRESSURE

40. 2 SUPPRESSION CHAMBER PRESSURE 20.

2 2

0'0t===~====~=-----~------------------_110------------------~~----------------J103

.1 TIME, SECONDS

• NOTE:

Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT THE CONTAINMENT PRESSURE RESPONSE DUE TO THE RECIRCULATION LINE BREAK HAS ALSO BEEN RE-EVALUATED USING THE BASES PROVIDED FIGURE 6.2-26 IN REFERENCES 1 AND 3. THE PREDICTED SHORT-TERM RESPONSE IS REPORTED IN REFERENCE 2. RECIRCULATION LINE BREAK PRIMARY CONTAINMENT INITIAL PRESSURE TRANSIENT

• .EDISON NOTE TO GE DRAWING (3358 MWT)

REV 6 3/93

1 DRYWELL TEMPERATURE 2 SUPPRESSION CHAMBER TEMPERAtURE LL o

w' a:

J

!;: 200.

a:

w a.

l:

~

2 2 100.

2' ., 2 o.~ ________________ ~ ________________ ~ ________________ ~ ______________ ~

0.1 10 TIME, SECONDS

• NOTE:

THE CONTAINMENT TEMPERATURE RESPONSE DUE TO THE RECIRCULATION LINE BREAK HAS ALSO BEEN RE-EVALUATED USING THE BASES Fermi 2 PROVIDED IN REFERENCES 1 AND 3. THE PRE- UPDATED FINAL SAFETY ANALYSIS REPORT DICTED SHORT-TERM RESPONSE IS REPORTED IN REFERENCE 2.

FIGURE 6.2-27 RECIRCULATION LINE BREAK PRIMARY CONTAINMENT INITIAL

• EDISON NOTE TO GE DRAWING TEMPERATURE TRANSIENT (3358 MWT)

REV 6 3/93

3or---,--------------------..-------------------~--------------------,

20 a. 4-LPCI 4-SW Cl fi) a.. c. 1-LPCI 2-SW u.i' d. 1-LPCI 2-SW W=O a:

)

(I)

(I) w a:

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I-Z w

E z

~

z 8

6~~1~02~-10~3---------------------10~4~------------------~10~5~------------------1O~6 TIME, SECONDS Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-28 PRIMARY CONTAINMENT PRESSURE LONG TERM RESPONSE (3358 MWT)

REV 6 3/93

300r---~--------------------~--------------------~---------------------'

a. 4-lPCI 4-SW

c. 1-lPCI 2-SW

d. 1-lPCI 2-SW W=O 200 II..

0 w'

a:

J

!ia:

w Q.

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..J

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c 100 TIME, SECONDS Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2*29 DRVWELLTEMPERATURE LONG TERM RESPONSE (3358 MWT)

REV 6 3/93

300r---~--------------------~--------------------~---------------------'

a. 4-LPCI 4-SW

c. 1-LPCI 2-SW

d. 1-LPCI 2-SW W=O' u.

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w a..

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en TIME, SECONDS Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-30 SUPPRESSION POOL TEMPERATURE LONG TERM RESPONSE (3358 MWT)

REV 6 3/93

STEAM JET r-________________ ~~~------~CONDENSER

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MAN1FOlO AO Vl0-2.So'O VtO- 200<3 DRAiN VI 0-'2.50'2.

Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-31 MAIN STEAM SYSTEM PIPING AND VALVES REV 6 3/93

Figure Intentionally Removed Refer to Plant Drawing M-3045 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.2-32 MAIN STEAM ISOLATION VALVE LEAKAGE CONTROL SYSTEM REV 22 04/19

FERMI 2 UFSAR 6.3 EMERGENCY CORE COOLING SYSTEMS Four systems are provided to protect the core against various sizes of hypothetical pipe breaks. Three of these inject emergency core cooling water into the reactor and one is a reactor pressure vessel (RPV) automatic depressurization system (ADS). The three injection systems consist of the high-pressure coolant injection (HPCI), low-pressure coolant injection (LPCI), and core spray system. The protection afforded by these systems meets the NRC criteria given in 10CFR 50.46.

6.3.1 Design Bases The objective of the emergency core cooling systems (ECCS), in conjunction with the containment, is to limit the release of radioactive materials should a LOCA occur, so that resulting radiation exposures are kept within the guideline values given in 10 CFR 50.67 or 10 CFR 100 as applicable.

Safety design bases for the subsystems of the ECCS are given in the following subsections.

6.3.1.1 Range of Coolant Ruptures and Leaks The ECCS provides adequate core cooling in the event of any break or leak in the piping of the nuclear system process barrier up to and including the double-ended break of the largest line connected to the RPV. The selection of break sizes and break locations is discussed in Subsection 6.3.3.7.3.

6.3.1.2 Fission Product Decay Heat In the event of a LOCA, the ECCS removes delayed neutron fission heat, residual stored heat, and radioactive decay heat from the reactor core at a rate that limits the maximum fuel cladding temperature to a value less than the 10 CFR 50.46 limit of 2200°F. The amount of heat to be removed is discussed in Subsection 6.2.1.3.8.

6.3.1.3 Reactivity Required for Cold Shutdown The reactor is designed to be in the cold-shutdown condition with the control rod of highest reactivity worth fully withdrawn and all other control rods fully inserted. Refer to Subsection 4.3.2 for a complete discussion.

6.3.1.4 Capability To Meet Functional Requirements The following functional requirements are met:

a. The ECCS is provided with sufficient capacity, diversity, reliability, and redundancy to cool the reactor core under all accident conditions

b. The ECCS is initiated automatically by conditions that indicate the potential inadequacy of the normal core cooling

c. The ECCS is capable of startup and operation regardless of the availability of offsite power supplies and the normal generating system of the plant 6.3-1 REV 24 11/22

FERMI 2 UFSAR

d. Action taken to effect containment integrity does not negate the ability to achieve core cooling. All ECCS pumps are designed to operate without benefit of containment pressure

e. The components of the ECCS within the RPV are designed to withstand the transient mechanical loadings during a LOCA so that the required core cooling flow is not restricted

f. The equipment of the ECCS is designed to withstand the physical effects of a LOCA so that the core can be effectively cooled. Effects considered are missiles, fluid jets, pipe whip, high temperature, pressure, humidity, and seismic acceleration

g. A reliable supply of water for the ECCS is provided. The prime source of liquid for cooling the reactor core after a LOCA is a stored source located within the containment. The source is located so that a closed cooling water path is established during ECCS operation

h. The flow rate and sensing networks of each ECCS are testable during reactor shutdown. All active components are testable during normal operation of the nuclear system.

6.3.2 System Design 6.3.2.1 Emergency Core Cooling System Design The bounds within which system parameters must be maintained and the acceptable inoperable components are discussed in the Technical Specifications.

The ECCS, containing four separate subsystems, is designed to satisfy the following performance objectives:

a. To limit the peak cladding temperature to 2200°F, to prevent a cladding metal/water reaction in excess of 1 percent of the cladding, and to maintain long-term coolability of the core in the event of a mechanical failure of the piping or the nuclear system process barrier, up to and including a break equivalent to the largest nuclear steam supply system (NSSS) pipe

b. To provide this protection by at least two independent, automatically actuated cooling systems

c. To function with or without external (offsite) power sources

d. To permit testing of the ECCS by acceptable methods, including, wherever practical, testing during power plant operations.

The aggregate of the ECCS is designed to protect the reactor core against fuel clad damage in excess of the limits set forth in 10 CFR 50.46 across the entire spectrum of line break accidents.

The operational capabilities of the various subsystems of the ECCS meet the functional requirements and performance objectives described below. Table 6.3-1 lists the types of LOCAs and the ECCS that would operate in response to each.

6.3-2 REV 24 11/22

FERMI 2 UFSAR During the first 10 minutes following the initiation of operation of the ECCS, the functional requirement is satisfied for all combinations of single active component failures and single pipe breaks, including pipe breaks in any ECCS subsystem which might partially or completely disable that subsystem.

After the first 10 minutes following the initiation of operation of the ECCS, and in the event of an active or passive component failure in the ECCS or its essential support system, long-term core and containment cooling is provided by any one LPCI or core spray loop delivering water to the RPV and by one residual heat removal (RHR) pump supported by one RHR heat exchanger with 100 percent service water flow. Containment cooling, using one RHR pump supported by one RHR heat exchanger, can be delayed up to twenty minutes following the DBA LOCA.

The power for operation of the core spray and LPCI is from regular ac power sources. Upon loss of the regular power, operation is from onsite standby ac power sources. Standby sources have sufficient diversity and capacity so that all core spray and LPCI requirements are satisfied. One core spray loop and one LPCI loop are powered from one ac division and the other core spray loop and LPCI loop are powered from a second and separate ac division.

Four diesel generators are the site backup power supplies, with two diesel generators and two buses per division.

With the exception of LPCI while lined up in shutdown cooling and RPV pressure is less than or equal to the cut in pressure, all systems start automatically. The starting signal comes from independent and redundant sensors of drywell pressure and low RPV water level. Refer to Subsection 7.3.1 for a complete discussion of the ECCS instrumentation and starting and control logic.

Piping and instrumentation diagrams for the subsystems and components that constitute the ECCS are provided and referenced under the discussion of the subsystem or component.

6.3.2.2 Equipment and Component Descriptions The four types of core cooling systems (HPCI, ADS, core spray, and LPCI) are described in this section with reference to the appropriate piping and instrumentation diagrams and system process diagrams.

6.3.2.2.1 High Pressure Coolant Injection System The HPCI system is provided to ensure that the reactor core is adequately cooled to meet the design bases in the event of a small break in the nuclear system and loss of coolant that does not result in rapid depressurization of the RPV. Liquid breaks up to approximately 0.1 ft2 break area and steam breaks up to approximately 0.5 ft2 break area are within the capability of the HPCI system alone. This permits the plant to be shut down while maintaining sufficient RPV water inventory until the RPV is depressurized. The HPCI system continues to operate until RPV pressure is below the maximum pressure at which LPCI operation or core spray system operation can maintain core cooling.

The HPCI system consists of a steam turbine assembly driving a constant-flow pump assembly and system piping, valves, controls, and instrumentation. The HPCI piping and instrumentation diagram is shown in Figure 7.3-1. The HPCI system process and valve 6.3-3 REV 24 11/22

FERMI 2 UFSAR lineup diagrams are shown in Figures 6.3-1 through 6.3-5. The schematic drawing is shown in Figure 6.3-1.

The principal HPCI 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 operation of the HPCI system and to be protected from the physical effects of design-basis accidents (DBAs) such as pipe whip, flooding, and high temperature.

The pump assembly is located below the level of the condensate storage tank and below the water level in the suppression pool to ensure positive suction head to the pumps.

Two sources of water are available. The HPCI system initially injects water from the condensate storage tank (see Figure 6.3-2). When the water level in the tank falls below setpoint level or when suppression pool level is high, the pump suction is auto-matically transferred to the suppression pool. This transfer may also be made from the main control room using remote controls. The transfer requires the opening of normally closed valves F041 and F042 in the pump suction line leading from the suppression pool. The opening of these valves automatically closes valve F004 in the pump suction line leading from the condensate storage tank. When the pump suction has been transferred to the suppression pool, a closed loop is established for recirculation of water escaping from a break (see Figure 6.3-3).

Injection water is piped to the reactor feedwater pipe at a T-connection.

The HPCI turbine is driven by steam from the RPV which, after reactor shutdown, is generated by decay and residual heat. The steam is extracted from a main steam line upstream of the main steam isolation valves (MSIVs). The HPCI inboard isolation valve (F002) and the bypass valve around the HPCI outboard isolation valve (F600) in the steam line to the HPCI turbine are normally open to keep the piping to the turbine at elevated temperatures. This permits rapid startup of the HPCI system. Signals from the HPCI control system open (with oil pressure available) or close the turbine control/stop valve.

A condensate drain pot is provided upstream of the turbine steam admission valve to prevent the HPCI steam supply line from filling with water. The drain pot normally routes the condensate to the main condenser, but upon receipt of a HPCI initiation signal or a loss of non-interruptible control air pressure, isolation valves on the condensate line automatically close.

The turbine has two devices for controlling power. One is a speed governor that limits turbine speed to its maximum operating level, and the other is a control governor with automatic speed setpoint control that is positioned by a demand signal from a flow controller to maintain constant flow over the pressure range of HPCI operation.

As reactor steam pressure decreases, the HPCI governor valves open further to pass the steam flow required to provide the necessary pump flow. The capacity of the system is selected to provide sufficient core cooling to prevent excessive clad temperatures while the pressure in the RPV is above the pressure at which core spray and LPCI become effective.

Startup of the HPCI system is completely independent of ac power. Only dc power from the station battery and steam extracted from the nuclear system are necessary. The HPCI controls automatically start the system and bring it to design flow rate within 60 sec from receipt of a primary containment (drywell) high-pressure signal or an RPV low water level 6.3-4 REV 24 11/22

FERMI 2 UFSAR signal. This time interval for HPCI injection is used in the Fermi 2 TRACG-LOCA analyses that demonstrate conformance to 10 CFR 50.46 (Reference 42).

High-pressure coolant injection operation automatically actuates the following valves:

a. HPCI pump discharge shutoff valve

b. HPCI steam supply shutoff valves

c. HPCI turbine stop valve

d. HPCI turbine control valves

e. HPCI steam line drain isolation valves

f. HPCI pump suction valve from condensate storage.

Startup of the hydraulic oil pump and proper functioning of the hydraulic control system is required to open the turbine valves. Operation of the barometric condenser components is functionally illustrated in Figure 7.3-2 and their failure does not prevent the HPCI system from fulfilling its core cooling objective. The same initiating signal automatically starts the turbine oil pump, and when sufficient oil pressure is developed, the stop valve begins to open. Contacts actuated by the HPCI turbine stop and turbine steam supply valve limit switches initiate the speed control ramp generator which slowly increases the control valve position from closed to the value demanded by the flow controller. As a result, the turbine smoothly accelerates from rest to the speed at which rated pump flow is developed. When rated flow is established, the flow controller signal adjusts the setting of the control governor so that rated flow is maintained as nuclear system pressure decreases.

A minimum flow bypass is provided for pump protection (see Figure 6.3-4). The bypass valve (F012) automatically opens when a low flow combined with a high discharge pressure signal is sensed. It automatically closes on a high-flow signal or if the closing of either the turbine stop valve or steam inlet valve is sensed. Pump discharge pressure is sensed by PS N027, and flow is sensed by FS N006. When the bypass is open, flow is directed to the suppression pool.

A full-flow functional test of the HPCI can be performed during plant operation by drawing suction from the condensate storage tank and returning the water to the tank through a full-flow test line (see Figure 6.3-5). During this test, a signal to initiate the HPCI automatically stops the test mode and starts the water injection to the feedwater line. This transfer from the test mode to the accident mode requires the closing of the normally closed (but open for the test mode) valves F008 and F0ll located in the test line connecting the pump discharge and the condensate storage tank.

A cross connection is provided from the HPCI Test Line piping to the GSW piping to be used as part of the Flexible and Diverse Coping Strategy (FLEX) to mitigate Beyond Design Basis External Events (BDBEE) in response to NRC Order EA-12-049.

Exhaust steam from the HPCI turbine is discharged to the suppression pool. A drain pot at the low point in the exhaust line collects moisture present in the steam. Collected moisture is discharged to the suppression pool or bypassed to the barometric condenser.

6.3-5 REV 24 11/22

FERMI 2 UFSAR The HPCI turbine gland seals are vented to the barometric seal condenser. Noncondensable gases from the barometric condenser are pumped to the standby gas treatment system (SGTS).

A redundant system of check valves and isolation valves has been installed as a vacuum breaker line that connects the air space in the suppression pool with the HPCI turbine exhaust line. This eliminates any possibility of water from the suppression pool being drawn into the HPCI turbine exhaust line. The two isolation valves (electrically separated) in series in this vacuum breaker line operate automatically via a combination of low reactor pressure and high drywell pressure. Test connections are provided on either side of the two check valves.

The system component classifications plus additional requirements are described in Chapter

3. The pump is designed and tested in accordance with the standards of the Hydraulic Institute.

The system is designed for a service life of 40 years, accounting for corrosion, erosion, and material fatigue. The various operations of the HPCI components are summarized below.

The HPCI turbine is shut down automatically by any of the following signals:

a. Turbine overspeed--prevents damage to the turbine casing

b. Reactor pressure vessel high water level--indicates that core cooling requirements are satisfied

c. High-pressure coolant injection pump low suction pressure--prevents damage to the pump due to loss of flow

d. High-pressure coolant injection turbine exhaust high pressure--indicates a turbine or turbine control malfunction.

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

Because the steam supply line to the HPCI turbine is part of the nuclear system process barrier, certain signals automatically isolate this line, causing shutdown of the HPCI turbine.

Automatic shutoff of the steam supply is described in Section 7.3. However, automatic depressurization and the low-pressure systems of the ECCS act as backup, and automatic shutoff of the steam supply does not negate the ability of the ECCS to satisfy the safety objective.

In addition to the automatic operational features of the system, provisions are included for remote manual startup, operation, and shutdown (provided automatic initiation or shutdown signals do not exist). 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.

6.3.2.2.2 Automatic Depressurization System In case the capability of the feedwater pumps, control rod drive (CRD) pumps, reactor core isolation cooling (RCIC) system, and HPCI system is not sufficient to maintain the reactor water level, the ADS functions to reduce the reactor pressure to a value low enough (<300 6.3-6 REV 24 11/22

FERMI 2 UFSAR psig) to allow the LPCI and core spray systems to pump water to the RPV in time to cool the core consistent with the design bases.

The ADS uses five of the 15 safety/relief valves of the nuclear system pressure relief system to achieve the automatic blowdown to the suppression pool. The capacity of each relief valve is about 900,000 lb/hr at set pressure. The ADS starts operating soon enough after failure of the HPCI and dumps steam fast enough to ensure that the LPCI and core spray systems begin to operate and cool the fuel adequately.

To activate, the ADS must have drywell high pressure (2 psig) and RPV low water level (level 1) signals. Simultaneous occurrence of these drywell high pressure and RPV low water level conditions initiate a time delay of 120 seconds to allow the HPCI system time to recover level. After that time delay, ADS safety relief valves will operate if at least one RHR pump or both core spray pumps in either division are running (developing pressure). RPV low water level (level 1) signal also activates a bypass timer set for 8 minutes. This bypass time delay is provided to bypass the drywell pressure high logic circuit. If for some reason the drywell high pressure is not detected, the RPV low water level signal alone will activate the ADS safety relief valves after the 8 minute bypass time delay, plus the original 120 second time delay, provided that appropriate discharge pressure signals are present. The values shown above are based on analysis (Reference 34); refer to Technical Requirements Manual Table 3.5.1-1 for operating setpoints.

Opening of the relief valve requires pneumatic pressure to the valve's diaphragm actuator.

This pneumatic supply is controlled by a solenoid-operated pilot valve. For the ADS to function, this valve control system must be operable, and there must be a pneumatic supply.

The accumulator associated with the relief valves used with the ADS has sufficient capacity to allow for five operations of the pilot valves to cover interruptions if the pneumatic supplies are switched from the normal to the emergency backup sources. The relief valve pneumatic supply and backup supply systems are capable of performing their function for the long-term period of 100 days following an accident as required by NUREG-0737, Item II.K.3.28. (See also Section 5.2.2.2.3 for a description of the accumulator system.) The accumulator and pneumatic supply systems are capable of performing their design function during and following exposure to a harsh environment and/or a seismic event. In the automatic depressurization mode, the relief valves do not reset to normal safety/relief valve setpoints on low RPV pressure. To ensure proper cooling under all circumstances, including a postulated failure of ADS, reactor pressure relief can still be provided by operation of the non-ADS safety/relief valves. This ensures that the low pressure systems can be actuated with a HPCI failure and one additional single failure of the ADS, since any single failures affecting ADS will not impair remote operation of eight non-ADS safety relief valves.

The ADS valves stay open once activated until the reactor pressure is 50 psi higher than the containment pressure. These valves close when the reactor pressure decays to less than 50 psi above the containment pressure, and reopen when the reactor pressure is 100 psi above the containment pressure. Thus, the maximum pressure that can exist during the long-term period following a LOCA is 100 psi plus containment pressure.

The design, description, and evaluation of the pressure relief valves are discussed in detail in Subsection 5.2.2. See Section 7.3 for details on instrumentation and control.

6.3-7 REV 24 11/22

FERMI 2 UFSAR The relief valve setpoints cannot be tested while they are in place on the steam lines. The safety/relief valves are designed to allow removal for bench testing of the setpoints during shutdown.

6.3.2.2.3 Core Spray System The core spray system protects the core in the event of a large break in the nuclear system if the feedwater pumps, the CRD pumps, the RCIC, and the HPCI systems are unable to maintain RPV water level.

The protection provided by the core spray system also extends to a small break if the feedwater pumps, CRD pumps, RCIC, and HPCI systems are all unable to maintain the RPV water level and the ADS has operated to lower the RPV pressure so that LPCI and the core spray system provide core cooling.

Two independent loops are provided as a part of the core spray system. Each loop consists of two single-stage, in-line water pumps with suction and discharge connected in parallel and each pump driven by an 800-hp electric motor; a spray sparger in the RPV above the core; piping and valves to convey water from the suppression pool to the pumps and to the sparger; and the associated controls and instrumentation. Figures 6.3-7 through 6.3-11 show the schematic process and valve lineup diagrams of the core spray system. The piping and instrumentation diagram is shown in Figure 7.3-7.

In case of low water level in the RPV or high pressure in the drywell, the core spray system automatically starts and the pumps in the two core spray loops are signaled to start after a 5-sec delay on auxiliary ac power. This signal also starts without delay the diesel generator set and the LPCI system. In case auxiliary ac power is lost, the pumps start in sequence (with time delay) on standby ac power. Pump suction valves F001A, B, C, and D are normally locked open to ensure a positive suction head for the pumps. The test bypass motor-controlled valves F0l5A and B, normally closed, are signaled to close if open. When the reactor pressure is permissive (<500 psig), valves F004A and B (normally open) and F005A and B are signaled to open automatically. The pumps take water from the suppression pool and discharge to the sparger ring and nozzle spray. This condition is shown in Figure 6.3-8.

When the system is actuated, water is taken from the screened suction line in the suppression pool. Flow then passes through a normally open, motor-operated valve. A keylock switch is installed in the control circuit with position indication available in the main control room.

This valve is located in the core spray pump suction line as close to the suppression pool as practical. It can be closed by a remote manual switch from the main control room to isolate the system from the suppression pool in case of a leak from the core spray system.

The four core spray pumps are located in the reactor building below the water level in the suppression pool to ensure positive pump suction. The pumps, piping, controls, and instrumentation of each loop are separated and protected so that any single physical event, or missile generated by rupture of any pipe in any system within the containment drywell, cannot make both core spray loops inoperable. The switchgear for each loop is in a separate emergency bus room for the same reason.

A vent line with two normally closed valves is provided from the pump casing for filling the pump with water. A shaft seal drain is provided, which drains to the radwaste system, along 6.3-8 REV 24 11/22

FERMI 2 UFSAR with the vent line. Leakage from the drain line is measured during primary containment leakage tests.

A low-flow bypass line is provided from the pump discharge to below the surface of the suppression pool. The bypass flow is required to prevent the pump from overheating when pumping against a closed discharge valve. An orifice limits the bypass flow. A manual valve that is normally locked open is used to close the bypass line for maintenance. A motor-operated valve on the bypass line closes upon receipt of a signal from a flow switch in the main discharge line.

Two relief valves, set for 500 psig, protect each low pressure core spray system loop upstream of the outboard shutoff valve from reactor pressure. The relief valves discharge to the suppression pool.

Two motor-operated valves are provided to isolate the core spray system from the nuclear system when the core spray pump is not running. These valves admit core spray water to the inboard check valve when signaled to open at approximately 500-psig RPV pressure. Both valves are installed outside the drywell to facilitate operation and maintenance, but as close as practical to the drywell 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. A test line is normally closed with two normally closed valves and a pipe cap to ensure containment.

A check valve is provided in each core spray line just inside the primary containment to prevent loss of reactor coolant outside containment in case the core spray line breaks. A normally locked-open manual valve is provided downstream of the inside check valve to shut off the core spray system from the reactor during shutdown conditions for maintenance of the upstream valves. The two core spray system pipes enter the RPV through nozzles l20° apart.

Each pipe then divides into a semicircular header with a downcomer at each end which turns through the shroud near the top. A semicircular sparger is attached to each of the four outlets to make two practically complete circles, one above the other inside the shroud head. Short elbow nozzles are spaced around the spargers to spray the water radially into the tops of the fuel assemblies.

Core spray piping upstream of the outboard shutoff valves F004A and B is designed for the lower pressure and temperature of the core spray pump discharge. The outboard shutoff valve and downstream piping are designed for RPV pressure and temperature. The pumps, piping, and valves are designed to meet requirements described in Chapter 3. The pumps are also designed and tested in accordance with the standards of the Hydraulic Institute. Pump operability testing under the plant technical specifications and the in-service testing program ensures pump operation at or above the minimum required performance assumed in the plant safety analyses. Pump test acceptance criteria developed for this purpose are required to include consideration of the lowest allowed emergency diesel generator (EDG) operating frequency based on the maximum allowed frequency control tolerance as well as pressure and flow test instrument accuracies.

The core spray pumps and all automatic valves can be operated individually by manual switches in the main control room. Operating information is provided in the main control room with pressure indicators, flowmeters, and indicator lights. Automatic signals to start 6.3-9 REV 24 11/22

FERMI 2 UFSAR the system preempt all other signals while the system is in auto mode. In the manual condition, the pump or valve will be under total operator control. The manual condition is indicated to the operator in the main control room.

6.3.2.2.3.1 Core Spray Test Mode During Plant Operation A test line for the rated core spray system flow rate is provided to route the suppression pool water from the pump discharge to the suppression chamber without entering the reactor pressure vessel (see Figure 6.3-9). During reactor operation, the core spray injection valves are normally closed. The pumps are started by the operator using the remote manual control in the main control room. Valves F015A and B in the test lines are opened partially to achieve the rated flow through the test lines. This mode of operation permits testing of pump operation and ensures that rated flow is achieved. It also permits testing of control and operation of components of the low pressure section of the core spray system.

6.3.2.2.3.2 Core Spray Test During Plant Shutdown To provide for system testing during a plant shutdown (see Figure 6.3-10), a connection is provided from the condensate storage tank to the pump suction. This condensate is used for flow testing of the spray nozzles inside the pressure vessel. A normally closed manual valve is provided between the condensate storage tank and the pump suction line to minimize the possibility of communication of the condensate to the suppression pool and to avoid extension of the primary containment.

During plant shutdown, the core spray system can be tested by manually opening valves F002A and B. The pumps are started by remote manual control, and valves F004A and B and F005A and B are opened by remote manual switch. System operation including sparger rings can be tested in this manner during shutdown conditions. Any system maintenance or repairs may be made on the core spray system during plant shutdown by manually closing valves F007A and B, which are normally locked open.

System operability is determined by performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position.

Actual injection of coolant into the reactor vessel may be excluded from this test, which is performed every 24 months. Such testing was performed during initial plant startup and periodic performance is not needed as the continued operability of the LPCS header is assured by means of the break detection logic discussed in Subsection 7.3.1.2.3.9.

6.3.2.2.3.3 Core Spray Minimum Flow Bypass Mode The pump discharge line is provided with a low-flow bypass line to protect the core spray pumps from overheating during operation at high vessel pressure (see Figure 6.3-11). Flow-measuring element FE N002 is coupled to flow switch FS N006, which at a nominal flow rate of less than 2100 gpm, signals bypass line motor-operated valve F031 to open automatically. Water from the suppression pool is then routed through the bypass lines back to the suppression pool. As soon as flow is established in the pump discharge lines, the signal from FS N006 signals the minimum bypass motor-operated valves F03lA and B to close automatically.

6.3-10 REV 24 11/22

FERMI 2 UFSAR 6.3.2.2.4 Low Pressure Coolant Injection System In case of low water level in the reactor or high pressure in the containment drywell, the LPCI mode of operation of the RHR system pumps water into the RPV in time to cool the core consistent with the design bases. The core spray system starts from the same signals and operates independently to achieve the same objective. The isolation valves for these two systems are opened when reactor pressure is less than 500 psig, but injection flow does not occur until the differential pressure across the check valves permits. This occurs when the RPV pressure is less than 300 psig.

Low-pressure coolant injection operation provides protection to the core for the case of a large break in the nuclear system when the feedwater pumps, the CRD pumps, and RCIC and HPCI systems are unable to maintain RPV water level. Manual override of LPCI operation is prevented by two keylocked switches. Conditions for manual override of LPCI operation are described in the Fermi 2 Containment Control Emergency Procedures.

Protection provided by LPCI also extends to a small break in which the feedwater pumps, CRD pumps, and RCIC and HPCI systems are all unable to maintain the RPV water level, and the ADS has operated to lower the reactor vessel pressure so that LPCI and core spray systems start to provide core cooling.

In the event of a break in one of the two reactor recirculation system loops, logic is provided to sense the broken loop and to inject the LPCI flow into the unbroken loop. Thus, the flows from the two LPCI system loops are interconnected by valving. Since electrical power to each LPCI loop is isolated (Divisions I and II), it is necessary to have a swing bus arrangement that permits the valves of an LPCI loop that has been disabled by a single failure of a divisional electrical supply to be energized. This feature preserves the ability of the LPCI to cross-connect flow and inject into the unbroken recirculation loop.

The Fermi 2 LPCI valve logic also provides for closing only the valve in the discharge side of the unbroken reactor recirculation loop as opposed to earlier logic that closed both the discharge and suction valves in the unbroken reactor recirculation system loop. The logic change provides for continued depressurization (permitting coolant injection by the core spray system) in the event that the single failure is the LPCI logic that selects the broken reactor recirculation system loop.

6.3.2.2.4.1 Accident Mode Valves F048A and F048B open automatically. Also, valves F015 and F017 in the loop corresponding to the undamaged recirculation loop receive a signal to open automatically upon receipt of reactor vessel low pressure (<500 psig) signal. See Figure 6.3-14.

The system pumps take water from the suppression pool and pump it into the core region of the reactor vessel through the undamaged recirculation loop. The system pumps are rated at 10,000 gpm per pump. The rated flow of 30,000 gpm is delivered with three-pump operation at 20 psid pressure difference between the reactor vessel and the primary containment. A redundancy of pumps is provided so there is one more pump available than the number required for the rated flow in the LPCI. The core is flooded to an adequate height and the level maintained by the LPCI operating alone with three of four pumps operating.

6.3-11 REV 24 11/22

FERMI 2 UFSAR Soon after the LOCA (assuming offsite power is also lost), the high-drywell-pressure or reactor-low-water signal initiates the selected valves in the LPCI and core spray systems to open. These valves receive power as soon as it is restored by the emergency diesel generators. The LPCI system pumps are also signaled to start. The core spray system pumps start with 5-sec delay, i.e., within 18 sec of the accident. The LPCI injection valves are fully open and the recirculation loop discharge valve (in the undamaged loop) closes within 77 seconds. This interval is the maximum allowable time from the high drywell pressure initiating signal to pump at rated speed and ready to inject flow to the vessel with emergency power that is used in Fermi 2 TRACG-LOCA analyses (Reference 42).

6.3.2.2.4.2 Low Pressure Coolant Injection Loop Selection Logic This system is described in Subsection 7.3.1.2.4.

6.3.2.2.4.3 Low Pressure Coolant Injection Test Mode A design flow (10,000 gpm per pump) functional test of the RHR system pumps is performed for each pair of pumps during plant operation by taking suction from the suppression pool and discharging through the test lines back to the suppression pool (see Figure 6.3-15).

Discharge valve F015 to the reactor recirculation line remains closed, and reactor operation is undisturbed. The upstream and downstream valves for the containment spray headers (F016 and F021) are tested or exercised individually by remote manual switches in the main control room.

The control system is designed to provide automatic return from test mode to operating mode if LPCI injection is required during testing.

6.3.2.2.4.4 Low Pressure Coolant Injection Minimum Flow Bypass Mode This mode of operation is provided to protect the system pumps from overheating at low flow rates, by routing the pump flow through the minimum bypass lines to the suppression chamber. A single motor-operated valve F007 in each bypass line automatically opens upon sensing low flow after either RHR pump within the associated division is started. This valve automatically closes whenever the flow from either of the associated main system pumps is above the low-flow setting. One switch (N021) is used for each loop. (See Figure 6.3-16).

Low-pressure coolant injection pump and piping equipment is described in detail in Subsection 5.5.7, which also describes the other functions served by the same pumps if not needed for the LPCI function.

6.3.2.2.5 Emergency Core Cooling System Discharge Line Fill System One design requirement of any core cooling system is that cooling water flow to the RPV be initiated rapidly when the system is called on to function. This quick-start system characteristic is provided by quick-opening valves and quick-start pumps. By always keeping the HPCI, LPCI, and core spray pump discharge lines full, the lag between the signal for pump start and the initiation of flow into the RPV can be minimized. If for some reason these lines were empty when the systems were called for, not only would the lag time be increased, but also the lines would be subjected to unnecessarily large momentum forces 6.3-12 REV 24 11/22

FERMI 2 UFSAR associated with accelerating fluid into an empty pipe. To prevent draining of the ECCS-discharge lines, a fill system is provided to keep the core spray lines charged with demineralized water and the RHR lines charged with condensate water by a pressure regulating valve. A system is provided to maintain the HPCI pump discharge piping between the normally closed injection valve and pump discharge check valve charged with condensate water.

Since the core cooling pumps are located in the subbasement of the reactor building, approximately 75 ft below the point where the discharge piping enters the RPV, check or stop-check valves are provided near the pumps to prevent backflow from emptying the lines into the suppression pool. These valves will leak slightly, producing a small backflow that will eventually empty the discharge piping. The core spray lines are kept charged with demineralized water and the RHR lines are kept charged with condensate water by a pressure regulating valve. The HPCI pump lines are charged by the head (gravity) from the condensate storage tanks. The HPCI pump discharge piping valves up to the normally closed injection valve are also kept charged with condensate water. Alarms are provided for RHR and core spray fill line low pressure.

The demineralized water storage system supplies water to the reactor building, turbine building, radwaste building, auxiliary steam boilers, and core spray fill systems from a common manifold. The demineralized water supply from the manifold to the fill system is controlled by the pressure regulating valve. The water supply to the manifold is pumped from the demineralized storage system by a demineralized water jockey pump (DWJP) and, as required, by one or two demineralized water transfer pumps (DWTP).

The condensate water storage system supplies water to the RHR keep fill system from a reactor building second floor header. The condensate water supply from the header to the fill system is controlled by a pressure regulating valve. The water supply to the header is from the condenser pumps through a 4-inch supply line located downstream of the polishing demineralizers. During a plant shutdown, condensate is supplied by the condensate storage jockey pump and as required by the normal hotwell supply Pump.

When the demand for demineralized water is less than 20 gpm, the DWJP maintains the manifold pressure at 82 psig. If the quantity of water supplied by the DWJP exceeds 20 gpm, the manifold pressure drops. When the pressure reaches a defined setpoint, a pressure switch on the common manifold activates and one of the two DWTPs automatically starts. Should the demineralized water demand exceed the capability of the DWJP and one DWTP, the manifold pressure would continue to drop. At a lower setpoint, a second switch would activate to start the second DWTP and activate an alarm in the main control room.

The RHR fill system consists of two fill lines (branching from a single valve) supplied with condensate water from the header and terminates at the connections to the RHR pump discharge lines.

The core spray fill system consists of two fill lines (involving one pressure control valve in each line) supplied with demineralized water from the common manifold and terminates at the connections to the core spray pump discharge lines.

Vent and drain connections have been incorporated at all high and low points in the RHR and core spray piping systems. Prior to initial start (such as after maintenance to the RHR or core 6.3-13 REV 24 11/22

FERMI 2 UFSAR spray system) the discharge lines are filled by manually venting the high-point vents of the RHR and core spray discharge lines to avoid any trapped air pockets in the discharge lines.

The pressure control valve keeps the lines filled after initial filling.

The suction and discharge piping to the RCIC system is kept full up to the normally closed RCIC injection valve by static head from the condensate storage tanks and by appropriate high-point venting during initial fill and as required periodically by the Technical Specifications. The elevation of the injection valve is lower than the low level of the condensate storage tanks.

The HPCI piping from the discharge of the pump, through the check valves up to the normally closed injection valve is kept full from the static head of the Condensate Storage Tank (CST), and by appropriate high-point venting during initial fill and as required periodically by Technical Specifications. The elevation of the injection valve is below the minimum level of the CST, and any leakage from the system is made up by CST water. The relative height of the feedwater line connection for HPCI is such that the water in the feedwater lines keeps the remaining portion of the HPCI discharge line full of water.

However, the HPCI system discharge piping near the injection valve to the feedwater system absorbs heat from feedwater via conduction and valve leakage, that has the potential to form a localized steam void. When the HPCI turbine-driven pump is started, rapid pressurization of this line causes the void to collapse and produce a momentum transient which stresses the piping and related supports.

The momentum transient that is present during HPCI start has been analyzed and shown not to produce any damage to the HPCI piping, components, and supporting structure. However, the condensate water storage system is utilized to maintain the HPCI discharge piping between the normally closed injection valve and pump discharge check valve charged with condensate water to prevent possible void formation and minimize momentum transient effects. The pressure of the condenser pumps, connected to the HPCI discharge piping by a supply line located downstream of the condensate polishing demineralizers, maintains the piping charged with condensate water to prevent steam void formation.

In addition, the HPCI pump discharge piping just upstream of the injection valve is provided with cooling fins to remove heat and provide additional subcooling margin in the area of void formation.

6.3.2.2.6 Emergency Equipment Cooling Water System The emergency equipment cooling water system (EECWS) consists of two (redundant) systems that supply cooling water to emergency equipment that is automatically operable on high drywell pressure, low reactor building closed cooling water system (RBCCWS) differential pressure, or on a loss of offsite ac power or that may be manually initiated upon failure of the RBCCWS. In addition, the EECWS may be manually initiated with the non-essential loads subsequently restored to facilitate RBCCW heat exchanger cleaning, to enhance drywell cooling during high lake water (GSW) temperature, for testing, or to provide RHR Reservoir freeze protection during extreme cold weather. The system diagram is presented in Figure 9.2-2. The EECWS is designed to provide equipment cooling and ventilation space cooling for HPCI, RCIC, RHR, and core spray systems.

6.3-14 REV 24 11/22

FERMI 2 UFSAR Each of the two supply and return cooling loops (Division I and Division II) consists of one circulating pump of sufficient capacity to circulate water through the system and return the cooling water to a full capacity heat exchanger. The demineralized water in the system is cooled by the emergency equipment service water system (EESWS).

Both the EECWS and the EESWS are discussed in Subsection 9.2.2.

6.3.2.2.7 Emergency Core Cooling System Suction Lines The two core spray, four RHR, and HPCI suction lines have remote manual motor-operated gate valves.

The piping is classified as Class 2 piping in accordance with ASME Boiler and Pressure Vessel (B&PV) Code Section III, 1971, and has been stress analyzed for thermal and deadweight flexibility and seismic dynamic response. This analysis established nozzle loads on the torus connections which in turn are analyzed in accordance with ASME B&PV Code Section III-B. As these connections are situated below the torus, they are protected against possible missiles originating from the slab above the torus or any high-pressure lines situated above the torus.

To prevent the loss of torus water due to an ECCS suction line break, a leak-detection system is provided. Any postulated break in the ECCS pump suction line is detected and the appropriate isolation valve can be activated to isolate the break.

The maximum distance between the containment nozzle and the center line of the isolation valve occurs on the four 24-in. RHR suction lines. This distance is 11 ft 8 in.

Leak detection for the ECCS suction lines is provided by a system that measures the rate of change of the liquid level in the sump of the floor drain. The operator can isolate the leaking line and verify that the leak is stopped by observing the sump level.

6.3.2.3 Applicable Codes and Classification All ECCS piping, components, and system designs comply, as a minimum, with applicable codes, code cases, and addenda in effect at the time the equipment was procured. These systems are designed and constructed in accordance with Category I criteria and Quality Assurance Level 1.

The RHR/LPCI, HPCI, and core spray systems are each divided into two classes.

The Class 1 portion of each system includes all piping and components that are a part of the reactor system pressure boundary out to and including the second isolation valve.

The Class 1 portions of the RHR/LPCI, core spray systems, and HPCI are designed and constructed in accordance with Subsection NB of ASME B&PV Code Section III, 1971 or later issue and addenda of this code in effect at the date of purchase order, and conform with 10 CFR 50.55a, whichever is more restrictive.

The remaining portions of the RHR/LPCI, HPCI, and core spray systems are designated Class 2 and are designed and constructed in accordance with Subsection NC of ASME B&PV Code Section III, 1971 or later addenda in effect at the date of purchase order. The only exceptions to the foregoing are 6.3-15 REV 24 11/22

FERMI 2 UFSAR

a. The RHR/LPCI and core spray pumps were purchased in 1970 and therefore meet the requirements of Section B ASME Code for pumps and valves for nuclear power (1968 draft issue)

b. The shell sides of the RHR heat exchangers are designed and constructed in accordance with ASME B&PV Code Section III (1968), Class C, and Tubular Exchanger Manufacturers Association (TEMA) Class C Standard

c. The tube sides of the RHR heat exchangers are designed and constructed in accordance with ASME Section VIII, Division I, and TEMA Class C Standard

d. Relief valve code and standards are defined in Chapter 5

e. The HPCI turbine is a non-ASME component per ASME B&PV Section III, 1971 Edition, Article NE-1130

f. The HPCI barometric condenser is designed and constructed in accordance with the ASME B&PV Code Section VIII.

6.3.2.4 Materials Specifications and Compatibility Subsection 5.2.3 discusses general material considerations. Refer to Table 5.2-6 for a presentation of the specifications that generally apply to the selection of materials used in the ECCS. Nonmetallic materials such as lubricants, seals, packings, paints, primers, and insulation, as well as metallic materials, are selected as a result of an engineering review and evaluation for compatibility with other materials in the system and the surroundings with concern for chemical, radiolytic, mechanical, nuclear radiation, and temperature effects.

Subsection 6.3.2.19 contains a discussion by commercial name of materials in the primary containment that may conceivably interfere with ECCS performance as a result of their deterioration under LOCA conditions.

Materials for the principal components are listed in Table 6.3-2.

6.3.2.5 Design Pressures and Temperatures The design pressures and temperatures at various points in the system during each of several modes of operation of the ECCS subsystems can be obtained from the information blocks on the following process diagrams: Figures 6.3-1 through 6.3-5 for the HPCI system, Figures 6.3-7 through 6.3-11 for the core spray system, and Figures 6.3-14 through 6.3-16 for the LPCI. The operational characteristics of the ADS valves are presented in Chapter 5.

6.3.2.6 Coolant Quantity The HPCI system normally takes suction from the condensate storage tank. This tank is designed so that the last 150,000 gal is reserved for use by the HPCI or RCIC systems by the tanks standpipe design. Not all of this 150,000 gal is usable since the suction is switched to the suppression pool automatically upon a condensate storage tank low level (equivalent to about 45,000 gal of water in the tank based on a nominal trip setpoint). However, while the plant is operating, the condensate storage tank is maintained at a normal level considerably higher than that required to provide 150,000 usable gallons. The HPCI suction is also switched to the suppression pool upon suppression pool high level signal (approximately 3.5 6.3-16 REV 24 11/22

FERMI 2 UFSAR in. above normal water level) or at any time manually. The suppression pool contains approximately 880,000 gal of water. The core spray and LPCI systems take suction from the suppression pool.

The residual heat removal service water (RHRSW) system serves as the ultimate heat sink.

Its design includes two 3,465,000-gal reservoirs (described in detail in Section 9.2). They are sized in accordance with the recommendations of Regulatory Guide 1.27.

6.3.2.7 Pump Characteristics The HPCI pump is driven by a high-pressure turbine fed by reactor steam. The rated horsepower of the turbine at high speed (4100 rpm) is 4750 hp. The turbine produces 1000 hp at low speed (2100 rpm).

The core spray pump is driven by an open, drip-proof, induction motor rated at 800 hp.

Power required is 102 amp at 4160 V ac.

The RHR pumps are each driven by a type-K, squirrel cage, induction motor rated at 2000 hp. Power required is 255 amp at 4l60 V ac.

6.3.2.8 Heat Exchanger Characteristics There are no heat exchangers in the closed cooling water path associated with the emergency core cooling subsystems. The heat exchangers in the RHR system are discussed in Section 5.5.

6.3.2.9 Emergency Core Cooling System Flow Diagram A schematic diagram, the flow rates, and the pressures of the various ECCS subsystems can be obtained from the information blocks on the following process diagrams: Figures 6.3-1 through 6.3-11, and Figures 6.3-14 through 6.3-16. These parameters are presented for several modes of operation, including LOCA and test conditions.

6.3.2.10 Relief Valves and Vents The RHR/LPCI and the core spray systems are not designed to withstand normal reactor system pressures. Relief valves are provided to protect the low-pressure portions of these subsystems against possible overpressurization due to valve leakage and pump heat input.

Pressurized portions of the HPCI system are designed for service at reactor pressure and therefore do not require overpressure protection.

The design basis for the relief valves to protect the core spray and RHR systems from overpressurization is given in Subsection 5.5.13.

6.3.2.11 System Reliability The ECCS reliability has been achieved through an evolutionary process. Initially a proposed system configuration was submitted for evaluation. A reliability model of the proposed system was constructed and an estimate of the system success probability was made. Reliability models were then constructed for alternative ECCS configurations and a 6.3-17 REV 24 11/22

FERMI 2 UFSAR comparative trade-off study yielded the most reliable system configuration. Upon completion of the final design, a formal reliability analysis was performed to

a. Determine the expected system availability (average reliability)

b. Set safe system test intervals and allowable repair times

c. Qualitatively evaluate the system for conformance to the original design concepts, as well as existing industry standards and criteria for reactor protection and safety systems.

System availability is evaluated and selected test intervals and allowable repair times were determined by well-established reliability/availability methods. The qualitative analysis includes a functional system failure modes and effects analysis (FMEA). The FMEA results are used to verify conformance to industry criteria, develop reliability models, and ensure that the original design redundancy and diversity have been retained.

Availability, as applied to the ECCS, is defined as the probability that the system is operable when required. The ECCS availability is a function of the component system test intervals and the failure rates of the component parts used in the systems. The component parts used in the ECCS have low failure rates, as evidenced by historical field operating experience. The ECCS availability required to ensure adequate plant safety is established as a system design requirement. To ensure adherence to the availability design requirement, the periodic test intervals and allowable repair times for inoperable systems are defined in the Technical Specifications.

The power sources required for successful system operation are arranged in redundant configurations such that the power availability is not a limiting factor in determining the overall system success probability.

6.3.2.12 Protection Provisions The ECCS piping and components are designed to accommodate the effects of movement, missiles, thermal stresses, the effects of the LOCA, and the safe-shutdown earthquake (SSE).

The reactor coolant pressure boundary (RCPB) has been analyzed for four categories of design transients: normal, upset, emergency, and faulted conditions. These categories are generally described in the ASME B&PV Code Section III, 1968 Edition. Subsection 5.2.1 contains details of this analysis.

Protection of the mechanical, instrumentation, and electrical portions of the engineered safety feature (ESF) system and reactor protection systems (RPS) against environmental conditions is discussed in Section 3.11.

Subsection 6.3.2.2.5 describes the features protecting against water-hammer effects in ECCS discharge lines.

The components of the core spray system, the HPCI, the LPCI, and the RHR systems are protected from becoming functionally inoperative as a result of flooding the lower levels of the reactor building due to excessive leakage from the ECCS complex. Section 3.4 describes design protection against flooding.

6.3-18 REV 24 11/22

FERMI 2 UFSAR Response 3.1.2, Amendment 11 of the Fermi 2 PSAR discusses thermal stresses generated by high-temperature and high-pressure jet streams impinging on spherical plate sections. Also presented is an analysis of the uplift force on the RPV associated with a main steam line break. The methods used to provide assurance that thermal stresses do not cause damage to the ECCS are described in Subsection 6.3.3.9.

The ECCS is protected against the effects of the pipe whip, which might result from piping failures up to and including the LOCA, by separation barriers, pipe-whip restraints, or energy-absorbing materials. One or more of these three methods have been applied to provide protection against cascading damage to piping and components of the ECCS that could otherwise result in a reduction of ECCS effectiveness to an unacceptable level.

Section 3.6 describes the design protection and analysis performed for pipe whip.

The ECCS piping and components located outside the containment are protected from internally and externally generated missiles by the reinforced-concrete structure of the ECCS pump rooms. In addition, the watertight construction of the ECCS pump rooms below grade level protects against damage by flooding. Section 3.5 describes design protection against postulated missile damage.

6.3.2.13 Provisions for Performance Testing

a. High pressure coolant injection system

1. A full-flow test line is provided to route water from and to the condensate storage tank without entering the RPV

2. Instrumentation is provided to indicate system performance during normal and test operations

3. All motor-operated and air operated valves are capable of manual operation, either local or remote for test purposes

4. Drains are provided to leak test the major system valves.

b. Core spray system

1. A full-flow test line is provided to route water from and to the suppression pool without entering the RPV

2. In the event the torus is unavailable to provide suction, a test line from the condensate storage tank provides reactor grade water to test pump discharge to simulate injection into the RPV. Direct injection to the vessel is not performed (Subsection 6.3.2.2.3.2)

3. Instrumentation is provided to indicate system performance during normal and test operations

4. All motor-operated valves, air-operated valves, and check valves are capable of manual operation for test purposes

5. Relief valves are removable for bench testing.

6.3-19 REV 24 11/22

FERMI 2 UFSAR

c. Low pressure coolant injection system

1. Discharge test lines are provided for the four pumps to route suppression pool water back to the suppression pool without entering the RPV

2. Instrumentation is provided to indicate system performance during normal and test operations

3. All motor-operated valves, air-operated valves, and check valves are capable of manual operation for test purposes

4. Shutdown cooling lines taking suction from the recirculation system are provided to allow testing of pump discharge into the RPV during normal plant shutdown

5. All relief valves are removable for bench testing.

d. Automatic depressurization system Actual operation of each safety/relief valve pilot valve associated with the ADS was verified during the Preoperational Test Program.

6.3.2.14 Net Positive Suction Head The RHR/LPCI and core spray pump systems are designed to ensure adequate net positive suction head (NPSH) margin availability under all combinations of foreseeable adverse conditions. The point of minimum margin for all pumps occurs at the peak suppression pool temperature, calculated on the basis of conservative assumptions. No dependence is placed upon positive containment pressure. The Regulatory Position stated in Regulatory Guide 1.1, dated November 2, 1970, is met.

The conditions assumed for calculating the peak suppression pool temperature and the available NPSH margin are as follows:

a. Reactor at 3499 MWt (102% of 3430 MWt)

b. Suppression pool volume is 117,161 ft3

c. Initial suppression pool water temperature 95°F

d. Temperature of RHRSW reservoir varies linearly from 80°F to 90°F over 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and stabilizes at 90°F

e. Pump suction strainers plugged to maximum design per UFSAR Section A.1.82

f. All of the energy in the RPV is absorbed by the suppression pool water following a LOCA

g. Pumps operating at rated flows

h. The heat loads considered were pump heating; Zr-H2O reaction; peak sensible heat in RPV, steam, all water in the feedwater system, recirculation loops, fuel; and decay heat 6.3-20 REV 24 11/22

FERMI 2 UFSAR

i. The primary containment long-term response to a recirculation line break LOCA scenario in Subsection 6.2.1.3.3

j. Bounding minimum RHR heat exchanger heat transfer coefficient is 366 BTU/sec-°F

k. RHR system is placed in the suppression pool cooling mode 20 minutes after LOCA The analysis yielded a peak suppression pool temperature of 196.5°F which occurs approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after LOCA. This temperature is less than the suppression pool temperature of 198°F used in the RHR and the core spray NPSH margin calculations described below. The NPSH margins for the RHR and core spray pump systems using a peak suppression pool temperature of 198°F and other conservative calculational methods are positive, even allowing for instrument tolerances to cause flow to be above nominal design values. The 198°F pool temperature for NPSH is the controlling limit for the bulk pool temperature.

A hydraulic analysis has been performed for each RHR operating mode shown in the General Electric process diagram (Figure 6.3-14, Sheet 2). The NPSH required was obtained by using the most conservative RHR pump performance curve and corresponds to the flow rate through the pump. In calculating the NPSH available for each mode, the design conditions on the process diagram were used and the suction strainers were assumed to be plugged to maximum design per UFSAR Section A.1.82. The results of the RHR hydraulic analysis are as follows, assuming pumps with maximum allowed degradation:

GE Nominal Design Flow per NPSH NPSH Pump Required Available Mode Description (gpm) (ft absolute) (ft absolute)

A LPCI accident, three 10,000 15 30 pumps, RPV pressure equals 20 psig B LPCI accident, two 13,000 17 27 pumps, RPV pressure equals 20 psig C2 Containment spray, one 10,000 12.8 13.9*

pump, RPV pressure equals 0 psig D2 Suppression pool 10,000 12.8 31 Cooling, one pump 14*

E Shutdown cooling, two 9,625 13 49 pumps, RPV pressure equals 97 psig 6.3-21 REV 24 11/22

FERMI 2 UFSAR F Shutdown cooling, two 9,750 13 76 pumps, RPV pressure equals 0 psig G LPCI accident, two 13,000 17 19**

pumps, RPV pressure equals 0 psig H LPCI test, one pump 10,300 13 42 J2, J4 Minimum flow bypass, 480 8 44 two pumps

• Suppression pool at 198°F

• • Margin consistent with GE process diagram fluid temperature. Long-term operation at the higher suppression pool design maximum temperature of 198°F requires throttling flow consistent with EOP procedures consistent with UFSAR Section 6.3.2.17.

From the above cases, it is apparent that Modes C2 and G have the lowest NPSH margin.

Since NPSH margin is typically reduced at higher flow rates, Modes C2 and G were also examined using LPCI pumps operating on the vendor supplied pump curve (not degraded) and with 2% over-frequency applied. Under this condition, while NPSH margin is reduced to less than 1 ft for the worst case pump, the margin remains positive without containment overpressure.

The RHR pump suction strainers are 11-gage perforated plate stacked discs with 1/8-in.-

diameter holes. Therefore, the largest particles that could pass through the strainers are 1/8 in. in diameter.

After a postulated LOCA, debris released to the suppression pool would tend to sink to the bottom of the pool. The accumulation of this debris on the RHR pump suction strainers is minimized because the strainer is located at a 45° angle above the bottom of the pool, with a 10° mitre bend between the suction flange and the strainer flange. Any particles that could pass through the strainer perforations are not of sufficient size to affect RHR pump suction flow.

Local heating in the suppression pool is a phenomenon that occurs when high-energy steam is released into the suppression pool for quenching. The most severe local heating occurs during a safety/relief valve discharge. In general, local-to-bulk temperature differences at the time of maximum temperatures are about 15° for cases where two RHR loops are assumed available and about 30° for cases where one RHR loop is assumed available. The pool temperature during normal plant conditions is limited by Technical Specifications so that localized heating from safety/ relief valve discharges will not nullify the NPSH of the ECCS pumps, even for prolonged operation of the valves.

Local heating also occurs during the RPV depressurization stage of a postulated LOCA when steam and noncondensable gases are blown through the downcomers into the suppression pool. Local heating during this event will be significantly less than the temperature achieved 6.3-22 REV 24 11/22

FERMI 2 UFSAR during safety/relief valve blowdown because of lower energy in the steam and high turbulence in the water.

As described in Subsection 6.2.1.3.2, at about 100 sec after the design-basis accident (DBA),

hot water only will be discharged out of the break; at 1200 sec, the suppression pool temperature has reached 168°F. Thus, up to this point, there would be a very large margin on NPSH even if local heating were significant. At the time the suppression pool reaches its peak temperature, approximately 5 hr after LOCA, local heating cannot be significant for the small T in the water being discharged is quickly blended with the pool water.

The preceding conditions describe the containment system after full blowdown following a large break. Consequently, they are not applicable to the HPCI system. The HPCI pump is located below the level of the condensate storage tank (CST), from which suction is normally taken, and below the water level in the suppression pool.

A low-water level in the condensate storage tank (2 ft 8 in. above the bottom of the tank) or a high-water level in the suppression pool (3.5 in. above normal level), would cause the two normally closed, motor-operated gate valves located in the suppression pool suction line to automatically open. The normally open, motor-operated gate valve located in the condensate storage tank suction line would remain open until the two suppression pool suction valves fully open. At that time, the condensate storage tank suction valve would close. In this way, NPSH is maintained.

In the case of an ECCS passive failure such as pump seals or valve seals, the operator has adequate time to take corrective action and isolate the failure before the NPSH would become inadequate for the remaining ECCS pumps due to reduced suppression pool level.

Adequate minimum submergence is available to prevent vortex formation and air ingestion during operation. With the exception of suction from the CST, minimum required submergence is computed in accordance with NUREG/CR-2772 as endorsed in Reg. Guide 1.82 Rev. 2. Under the RHR RUNOUT scenario, available submergence is sufficient to ensure minimal air entrainment and still meet NPSH requirements under Regulatory Guide 1.82, Rev. 2 for the minimum required compliment of pumps. The predicted CST suction minimum submergence is acceptable based on analytical analysis and the use of mechanical vortex suppression assemblies. The analytical method establishes the minimum submergence for straight (non-circular) spill over flow into the suction piping in accordance with Reference 2. For circular flow or vortex flow considerations, mechanical vortex suppression assemblies are installed that eliminate flow vortexes from introducing the potential for air entrainment into the pump suction. The pertinent data are summarized below:

6.3-23 REV 24 11/22

FERMI 2 UFSAR Predicted Submergence Available for Incipient Air System Suction Source Submergence (ft) Ingestion (ft)

RHR Suppression pool 8.7 7.35 (LPCI) 9.0 (LPCI RUNOUT)

Core spray Suppression pool 9.2 3.9 HPCI Suppression pool 8.2 1.2 HPCI Condensate storage 1.45 (including 0.98 tank 0.44 foot silt block)

Under the limiting RUNOUT condition, the minimum submergence of the most limited of four available RHR pumps is not sufficient to ensure zero air ingestion. Here, the LPCI function is not credited to meet 10CFR50.46 ECCS performance requirements. With consideration of the standard applied NPSH penalties one or more RHR pumps have sufficient NPSH. This ensures RHR is available for subsequent use to provide long-term containment cooling in suppression pool cooling mode.

A postulated minimum level of 14 in. below the torus centerline was used to determine the level of suppression pool submergence.

The precaution taken to preclude vortex formation in the HPCI-RCIC condensate storage tank suction is to transfer suction to the suppression pool on low tank level. This is supplemented by the installation of a vortex suppression assembly over the suction intake for the HPCI-RCIC systems to mechanically preclude vortex formation.

6.3.2.15 Residual Heat Removal Pump Runout Evaluation The Fermi 2 design was reexamined also to determine whether a failure in the LPCI logic could disable the RHR pumps. The single failures that potentially could disable the RHR pumps have been identified as the following.

Case A The LPCI logic correctly selects the unbroken loop, but a single failure causes inadvertent opening of LPCI injection valve E11-F015 into the broken loop. This condition results in four RHR pumps injecting into both recirculation loops with one loop broken Case B All four RHR pumps start for LPCI injection, but a single failure causes the LPCI loop selection logic to select the wrong (broken) loop. This condition results in all four RHR pumps injecting into the broken recirculation loop Case C The LPCI logic correctly selects the unbroken loop, but a single failure causes the recirculation pump discharge valve B31-F031 to remain 6.3-24 REV 24 11/22

FERMI 2 UFSAR unclosed. This condition results in four RHR pumps injecting into the vessel through one recirculation loop inlet and discharge lines.

Under the above conditions, the RHR pump operation was examined for cavitation, pump motor overload, and emergency diesel generator overload.

6.3.2.15.1 Analysis Assumptions As shown in Figure 6.2-13, the initial LOCA blowdown causes an almost immediate temperature increase to approximately 135°F in the torus with a continued increase to 168°F after 20 minutes. A water temperature of 168°F was assumed for the entire time period and for each of the cases (A, B, and C) listed above.

As described in Subsection 6.3.2.1, after 10 minutes the operator begins the post-LOCA manual control of the RHR system, which includes throttling the RHR system and initiating containment cooling. However, the operator can delay the containment cooling for up to 20 minutes. Therefore, it is assumed that the RHR pump runout condition occurs during the 0-to 20-minute part of the DBA.

Although the LOCA blowdown will cause a pressure increase in the primary containment, the drywell and torus pressure assumed for the analysis is 0 psig.

Reactor vessel pressure was determined from the LPCI process diagram Figures 6.3-14 through 6.3-16. A vessel pressure of 20 psig given in mode A was assumed, because the runout condition lasts only during the short term portion of the LOCA analysis. The RHR suction strainers were assumed to be plugged.

For Case B, no jet pump resistance is available as the broken injection loop bypasses the normal injection path through the jet pumps. For Cases A and C, an equivalent jet pump resistance value was determined and used in the analysis.

The reactor core level was assumed to flood to two-thirds of the core height.

The Technical Specifications allow only 7 days of continuous plant operation with an inoperable LPCI pump. Therefore, the analysis did not consider any pumps to be out of service for maintenance.

6.3.2.15.2 Calculation Procedure and Results From the description of cases A, B, and C, it is clear that case A is the limiting case. This is because case A allows all four pumps to pump into parallel paths consisting of both the normal injection path and to the broken loop. Case A bounds case B, since case B simply eliminates the parallel path to the desired injection line. Case C is the least limiting. Like case B, case C involves only one flow path, but it would inject against a greater residual pressure in the reactor and intact recirculation loop piping. Therefore, only case A is analyzed in detail. The vendor-certified RHR pump performance curves provided a record of pump performance test data up to a pumping condition of 14,000 gpm. Operating conditions beyond this point were assessed using extrapolated vendor pump performance curves and data from the preoperational testing for RHR pumps. The results for each case are discussed below.

6.3-25 REV 24 11/22

FERMI 2 UFSAR Case A Case A results in four RHR pumps pumping into both LPCI loops, with one loop broken.

Under the most limiting scenario for minimum overall available NPSH, the RHR pumps are required to operate at approximately 15,500 gpm. The analysis of the available NPSH margins for this condition determines that adequate margins are available for torus water temperatures less than 168°F consistent with the time available for operators to take action to establish containment cooling within 20 minutes in accordance with the plant design as described in Section 6.3.2.14. For the Case A pump operating condition, pump motor and emergency diesel generator overloads will not be experienced.

6.3.2.15.3 Conclusion A failure of the LPCI logic will not result in RHR pump operating conditions that would allow pump cavitation, pump motor overload, or emergency diesel generator overload. The limiting case failure does allow the pumps to operate at a point that is not part of the manufacturer's performance test data. Extrapolated performance data were used as a basis for the analysis conclusion. The extrapolated data has been confirmed by expanding the scope of the preoperational testing for the RHR pumps to provide performance data for the 14,000-gpm to 15,300-gpm range. No design changes to the RHR system are required; therefore, the performance of the RHR system, with respect to process diagram requirements, has not changed and there is no impact on the Appendix K analysis discussed in Subsection 6.3.3.

6.3.2.16 Motor-Operated Valves and Controls The LPCI and the core spray systems are not designed to withstand reactor system pressures.

Provisions have therefore been made to ensure that these ESF systems are not subjected to damaging pressures. These provisions include appropriate relief valves, discussed in Subsection 6.3.2.10, and isolation valves with system interlocks and alarms that are discussed below. Refer to Section 7.3 for a further discussion of controls for these valves. The LPCI/RHR system is isolated from the reactor system by the following:

Valves Line Isolation Isolation Signal F008 RHR pump suction Pressure trip unit B31-N611B signals close above permissive pressure F009 RHR pump suction Pressure trip unit B31-N611A signals close above permissive pressure F022 RPV head spray Pressure trip unit B31-N611A signals (RHR pump close above permissive pressure discharge)

F015A, B RHR pump discharge B21-N690A, B and logic signal to RPV prevent opening above interlock pressure F050A, B RHR pump discharge Check valve (air operator on valve for to RPV testing) 6.3-26 REV 24 11/22

FERMI 2 UFSAR If either trip unit B31-N611A or B31-N611B fails in a nonconservative manner, the system is still protected because the other unit sends a "close" signal to the valve in series with the valve controlled by the failed trip unit. In the event of valve leaks, the system is protected by the pressure relief valves as outlined in Subsection 6.3.2.10.

Provisions have been made to allow for thermal expansion of water trapped between valves F008 and F009 (penetration X-12), by way of a line that returns the trapped water to the RPV.

The core spray system is isolated from the reactor system by the following Valves Line Isolation Logic F005A, B Core spray pump discharge Manual control room pushbutton to close F006A, B Core spray pump discharge Check valve Check valves are backed up by normally closed motor-operated valves. In the event of operator failure and check valve leak, the system is protected by relief valves as outlined in Subsection 6.3.2.10.

All motor-operated ECCS valves have position indication in the control room.

6.3.2.17 Manual Actions With the exception of LPCI while RHR is in the shutdown cooling mode, the initiation of the ECCS is completely automatic. No operator action is required for the initiation of postaccident modes of operation. When RHR is lined up in the shutdown cooling mode and RPV pressure is less than or equal to the cut in pressure, manual operation is required to permit LPCI to align and initiate. This includes manually lining up the suction path from the torus for the loop which is in shutdown cooling. No manual valve is required to change position to accomplish a safety-related mode of any ECCS. Manual valves generally do not have position indication in the control room. Administrative procedures require the position of any critical manual valve to be verified and recorded after each time it is operated and the position of critical manual valves to be verified and recorded during a refuel outage prior to plant operation following refueling. Thus, all critical manual valves are under rigid administrative control.

Following is a list of manual valves critical to the operation of ECCS that are controlled by administrative procedures:

Safety System Valve Number(s)

HPCI system P1100-F042 LPCI mode of RHR E1100-F034 A (B, C, D)

Core Spray E2100-F001 A (B, C, D)

E2100-F037 A (B, C, D) 6.3-27 REV 24 11/22

FERMI 2 UFSAR Operators are instructed and trained to observe the values and rates of change of the plant parameters that have the greatest significance for plant safety (e.g., RPV water level, containment pressure, torus temperature, radiation monitors, operation of ECCS, standby gas treatment system, emergency diesel generator loads, etc.). From these parameters, together with his training and use of the symptom-oriented emergency operating procedures, the operator is able to logically evaluate the condition of the plant and is prepared to take appropriate action at the end of the initial interval.

A timer is used in each ADS logic. The time-delay setting before actuation of the ADS is long enough that the HPCI system has time to operate, yet not so long that the LPCI and core spray systems are unable to adequately cool the fuel if the HPCI system fails to start. Manual reset circuits are provided for the ADS initiation signal. By resetting this signal manually, the delay timers are recycled. The operator can use the reset pushbuttons to delay or prevent automatic opening of the relief valves if such delay or prevention is necessary.

A manual inhibit switch is also provided for each ADS trip system. These switches allow the operator to inhibit ADS operation without repeatedly pressing the reset pushbuttons.

Operation of the manual inhibit switch will activate a white indicating light and an annunciator to alert the operator of the inhibit action. Enabling the inhibit function will not terminate an ADS logic actuation after the 120 second time delay has elapsed. At this point, only the reset pushbutton can be used to affect the ADS operation. Guidance is contained in the Emergency Operating Procedures.

6.3.2.18 Process Instrumentation Sufficient instrumentation is available to the operator in the main control room to assist him in accurately assessing the post-LOCA conditions if LOCA should occur. Basically, these indications are of two varieties: those that indicate the pressures, temperatures, and levels in the RPV and containment, and those that provide indication of operations of the ECCS position of valves and circuit breakers, flows, temperatures, and pressures of ECCS.

The most significant instruments in the first category are

a. Reactor pressure vessel level

b. Reactor pressure vessel pressure

c. Containment pressure

d. Containment temperature

e. Suppression pool level

f. Suppression pool temperature.

The most significant instruments in the second category are as follows.

a. LPCI flow and pressure

b. Core spray flow and pressure

c. HPCI flow and pressure.

Other available instrumentation is listed on the piping and instrumentation diagram included with the description of the above system in Chapter 5. Discussion of instrumentation also 6.3-28 REV 24 11/22

FERMI 2 UFSAR appears in Chapter 7. See Subsection 7.5.1.4.2 for a detailed listing of the process information available in the main control room that permits accurate assessment of postaccident conditions.

6.3.2.19 Materials Materials used in or on the ECCS are reviewed and evaluated with regard to radiolytic and pyrolytic decomposition and attendant effects on safe operation of the ECCS. For example, fluorocarbon plastic (Teflon) is not permitted in environments that attain temperatures greater than 300°F or radiation exposures above 104 rads.

Organic materials used in the Fermi 2 primary and secondary containments have been selected for extended life during normal operations for their resistance to expected accident environmental conditions. Thermal insulation used is inorganic and is not sensitive to high radiation fields, steam, or high temperature.

Evaluations of the protective coatings used within the containment (Subsection 6.2.1.6) have been made. It has been determined that they will satisfactorily endure accident environmental conditions and their expected products of decomposition, if any, will not adversely affect the operability of any ESF system.

6.3.2.20 Maintenance and Operability The capability of the ECCS to provide core cooling is verified by regularly scheduled functional tests on each component and system. Subsection 6.3.4 discusses these tests and the testing program.

The configuration of the ECCS systems has placed most of the components in concrete cubicles so that maintenance on any component has a minimum of complications due to radiation from the primary system or from other components (see Figures 1.2-6 and 1.2-8).

Drains for all pumps, heat exchangers, and low points in piping runs are piped directly to radwaste collection points. Flushing and makeup are provided from the demineralized water or CSTs.

Because of these features, maintenance of ECCS components during a long-term LOCA mode of operation may be possible depending upon which component has failed. However, special facilities for this situation have not been provided, since the system designs inherently account for component failures without overall loss of intended function (usually by redundancy of systems, see Subsection 3.12.2.2). In addition, the following design provisions have been included to increase system operational reliability during a LOCA:

a. All components essential to ECCS operation are capable of continued operation under LOCA conditions of pressure, temperature, and radiation

b. Suction strainers have been provided on all ECCS pumps to prevent pump seizure due to entrained foreign particulates

c. Adequate fouling factors have been included in the determination of the design heat transfer capacities of the RHR heat exchangers.

6.3-29 REV 24 11/22

FERMI 2 UFSAR The core spray and RHR pumps and motors are designed for the operating life of the plant (40 years) and for a postulated single continuous operation of 100 days for an accident during that 40-year operating life.

The following table shows the maximum expected accumulated operating time of these pumps for the life of the plant (40 years):

Mode of Operation RHR (hr) Core Spray (hr)

In-shop testing 4 4 Preoperational testing 168 168 Monthly testing 480 480 Yearly testing 40 40 Post LOCA 2,400 2,400 Shutdown 28,800 N/A Total 31,892 3,092 The severe operating conditions to which the HPCI pumps are exposed are temperatures to 212°F, radiation, and dynamic loads from seismic and hydrodynamic effects. The pumps are mainly fabricated of metallic materials that will not be degraded by the temperature and radiation environment. The nonmetallic gaskets and seals are made of materials with a demonstrated resistance to the environment. The dynamic load inputs are addressed analytically and evaluated against appropriate criteria to ensure operation of the pump while undergoing dynamic loading. The above ensures that the expected service life will exceed the expected operating time of 500 hr. (Surveillance tests are performed once a month for 40 years equaling 480 tests plus a possible 20 real starts equaling 500 operating hours.)

CS pumps are analyzed for the effects of dynamic loads resulting from seismic and hydrodynamic effects. Operability under the worst loadings is ensured by the operability assurance program described in Section 3.9.4.3.

6.3.3 Emergency Core Cooling System Performance Evaluation The performance of the ECCS was determined originally by applying the 10 CFR 50, Appendix K, evaluation models and then showing conformance to the acceptance criteria of 10 CFR 50, Section 50.46. Reference 3 provided a complete description of the LOCA events and the methods used to perform the original calculations.

The original methodology was updated (Reference 4) for the power uprate program (Reference 5) for GE11 (Reference 19), and for the GE14 fuel introduction (Reference 16).

The LOCA analysis was then revised using the SAFER/PRIME-LOCA analytical model and methodology (Reference 39). Then the TRACG-LOCA evaluation model replaced the SAFER/PRIME-LOCA for the ECCS-LOCA analysis for the GNF3 fuel introduction (Reference 42). The updated methodology and a description of the LOCAs are summarized here.

6.3-30 REV 24 11/22

FERMI 2 UFSAR The ECCS performance is evaluated for the entire spectrum of break sizes for postulated LOCAs. The discussion includes information on the radiological consequences of the following events:

a. Feedwater piping break, Subsection 15.6.6

b. Spectrum of BWR steam system piping failures outside containment, Subsection 15.6.4

c. Loss-of-coolant accidents, Subsection 15.6.5.

Cycle-specific reload information is in Reference 15.

6.3.3.1 Emergency Core Cooling System Bases for Technical Specifications The maximum average planar linear heat generation rates (MAPLHGR) calculated in this performance analysis provide the basis for Technical Specifications designed to ensure conformance with the acceptance criteria of 10 CFR 50, Section 50.46. Minimum ECCS functional requirements are specified in Subsections 6.3.3.4 and 6.3.3.5; testing requirements are discussed in Subsection 6.3.4. Limits on minimum suppression pool water level are discussed in Section 6.2.

The plant is licensed for average power range monitor (APRM) rod block monitor (RBM)

Technical Specification (ARTS) improvement program (Reference 6, 7, 8, and 20) and has both power and flow dependent limits imposed on the operating limit MAPLHGR (Reference 8 and 20). The flow dependent MAPLHGR, MAPLHGRf, is determined from the product of the standard MAPLHGR and a flow dependent term, MAPFACf, which is defined as a function of the core flow rate and positioning of the scoop tube on the recirculation pump motor. The plant specific MAPFACf versus flow curve is shown in the Core Operating Limits Report (COLR).

The power dependent operating limit MAPLHGR, MAPLHGRp, is determined from the product of the standard MAPLHGR and the power dependent term, MAPFACp. For powers between 25 percent rated and the bypass point for the turbine stop valve/turbine control valve fast closure scram signal (29.5 percent rated), there are two values for MAPFACp, one for core flows >50 percent rated and one for core flows 50 percent rated, as shown in the COLR. Once the power exceeds this bypass point, the MAPFACp is determined from a single curve which must be multiplied by the standard MAPLHGR to produce the reduced power operating limit MAPLHGR, MAPLHGRp.

The operating limit MAPLHGR to be used becomes the most limiting value of either MAPLHGRf or MAPLHGRp.

6.3.3.2 Acceptance Criteria for Emergency Core Cooling System Performance The applicable acceptance criteria, quoted from 10 CFR 50, Section 50.46, "Acceptance Criteria for Emergency Core Cooling Systems for Light-Water-Cooled Nuclear Power Reactors," are listed here. A detailed description of the methods used to show compliance are in Subsection 6.3.3.7 and Reference 1.

6.3-31 REV 24 11/22

FERMI 2 UFSAR

a. Criterion 1, peak cladding temperature - "The calculated maximum fuel element cladding temperature shall not exceed 2200°F." Conformance to Criterion 1 is shown in Table 6.3-4

b. Criterion 2, maximum cladding oxidation - "The calculated total local oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation." Conformance to Criterion 2 is shown in Table 6.3-4

c. Criterion 3, maximum hydrogen generation - "The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all the metal in the cladding cylinder surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react."

Conformance to Criterion 3 is shown in Table 6.3-4

d. Criterion 4, coolable geometry - "Calculated changes in core geometry shall be such that the core remains amenable to cooling." As described in Reference 1, conformance to Criterion 4 is demonstrated by conformance to Criteria 1 and 2

e. Criterion 5, long-term cooling - "After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core."

Conformance to Criterion 5 is demonstrated in Reference 9. Briefly summarized, the core remains covered to at least the jet pump suction elevation, and the uncovered region is cooled by spray cooling and/or by steam generated in the covered part of the core.

6.3.3.3 Single-Failure Considerations The functional consequences of potential operator errors, single failures, and the potential for submerging valve motors in the ECCS are discussed in Subsection 6.3.2. This Subsection includes information on errors that could cause any manually controlled, electrically operated valve in the ECCS to move to a position that could adversely affect the ECCS. There it was shown that all potential single failures are no more severe than one of the single failures identified in Table 6.3-5.

It is therefore only necessary to consider each of these single failures in the emergency-core-cooling-system performance analyses.

The specific analysis (Reference 42) included break sizes ranging from the minimum size that meets the definition of a LOCA to 200% of the largest applicable pipe cross-sectional area. Different single failure assumptions were investigated in order to identify the limiting case. Non-recirculation line breaks were found to be non-limiting. The feedwater line break accident analysis assumes operator actions are required to depressurize the reactor during a Division I battery failure. This assumption was reviewed and accepted by the NRC per the Ref. 24 SER.

The TRACG LOCA analysis (Reference 42) indicates that the small recirculation line breaks with Division II DC Power Source (Div II Battery) failure are limiting. This analysis was 6.3-32 REV 24 11/22

FERMI 2 UFSAR performed at maximum core thermal power, including uncertainty allowance (see Table 6.3-6, Section A Plant Parameters).

6.3.3.4 System Performance During the Accident In general, the system response to an accident can be described as

a. Receiving an initiation signal

b. A small lag time (to open all valves and have the pumps up to rated speed)

c. Finally the ECCS flow entering the vessel.

Key ECCS actuation setpoints and time delays for all the ECCSs are provided in Table 6.3-6.

The minimization of the delay from the receipt of signal until the ECCS pumps have reached rated speed is limited by the physical constraints on accelerating the diesel generators and pumps. The delay time resulting from valve motion in the case of a high-pressure system provides a suitably conservative allowance for valves available for this application. In the case of the low-pressure system, the time delay for valve motion is such that the pumps are at rated speed before the vessel pressure reaches the pump shutoff pressure.

Simplified piping and instrumentation and functional control diagrams for the ECCS are provided in Subsection 6.3.2. The operational sequence of ECCS for the DBA is shown in Table 6.3-7.

Operator action is not required, except as a monitoring function and as noted in Section 6.3.3.3, during the short-term cooling period following a LOCA. During the long-term cooling period, the operator will take action as specified in Subsection 6.2.2.3 to place the containment cooling system into operation.

6.3.3.5 Use of Dual Function Components for Emergency Core Cooling System With the exception of the LPCI system, the systems of the ECCS are designed to accomplish only one function: to cool the reactor core following a loss of reactor coolant. To this extent, components or portions of these systems (except for pressure relief) are not required for operation of other systems that have emergency core-cooling functions, or vice versa.

Because either the ADS initiating signal or the overpressure signal opens the safety/relief valve, no conflict exists.

The LPCI subsystem, however, uses the RHR pumps and some of the RHR valves and piping. When the reactor water level is low, the LPCI subsystem has priority through the valve control logic over the other RHR subsystems for containment cooling. When RHR is lined up in the shutdown cooling mode and RPV pressure is less than or equal to the cut in pressure, manual operator action is required for LPCI injection. Immediately following a LOCA, the RHR system is directed to the LPCI mode.

6.3.3.6 Limits on Emergency Core Cooling System Parameters The limits on the ECCS parameters are discussed in Subsection 6.3.3.1 and Subsection 6.3.3.7.1.

6.3-33 REV 24 11/22

FERMI 2 UFSAR Any number of components in any given system may be out of service, up to and including the entire system. The maximum allowable out-of-service time is a function of the level of redundancy and the specified test intervals. The limiting conditions for operation and surveillance requirements are given in the Technical Specifications.

6.3.3.7 Emergency Core Cooling System Analyses for Loss-of- Coolant Accident 6.3.3.7.1 Loss-of-Coolant Accident Analysis Procedures and Input Variables The procedures approved for LOCA analysis conformance calculations were originally performed and approved in accordance with the methodology described in Reference 3. This methodology has been updated in accordance with the procedures in detail in Reference 40, commonly referred to as SAFER/PRIME methodology. The SAFER/PRIME methodology has been replaced with the procedures in Reference 41, commonly referred to as TRACG-LOCA, for GNF3 and GE14 fuel types. The new methodology, which is an ECCS evaluation model developed to analyze BWR LOCA in accordance with 10 CFR 50.46, is a best estimate plus uncertainty type of evaluation model. Potentially limiting break locations, initial conditions, and ECCS performance are determined using inputs that correspond to the nominal trial associated with the statistical analysis in the break spectrum calculations.

Statistical analyses are performed for at least the most limiting small break, intermediate break, and double-ended guillotine break (DEGB).

Two primary computer models were used to determine the LOCA response for plant Fermi 2 using the TRACG-LOCA method. These models are PRIME and TRACG, which are described below.

a. DELETED

b. DELETED

c. PRIME The PRIME model provides the parameters to initialize the fuel rod fission gas inventory and rod internal pressure at the onset of a postulated LOCA for input to TRACG. PRIME also provides the initial pellet-cladding gap conductance and other parameters used by TRACG to calculate the transient gap conductance.

d. TRACG TRACG calculates the system response of the reactor and the detailed fuel rod heat transfer over a complete spectrum of hypothetical break sizes and locations. TRACG is compatible with the PRIME fuel rod model for gap conductance and fission gas release. A simplified form of the PRIME fuel thermal conductivity model is built into TRACG. TRACG calculates the core and vessel water levels, system pressure response, ECCS performance, and other thermal-hydraulic phenomena occurring in the reactor as a function of time. TRACG conservatively models the sources of heat in the core such as fission power, decay heat, and metal-water reaction. TRACG realistically models all regimes of heat transfer to calculate the transient cladding temperatures and oxidation.

6.3-34 REV 24 11/22

FERMI 2 UFSAR The significant input variables used by the LOCA codes are listed in Table 6.3-6.

6.3.3.7.2 Accident Description A detailed description of the LOCA calculation is provided in Reference 40 and is supplemented by Reference 42. With the TRACG-LOCA methodology, the limiting break is the limiting small recirculation suction line break. The limiting single failure is the one which results in the highest PCT. This is the failure of the Division II DC power (battery).

Table 6.3-8 provides a listing of figures which summarizes LOCA results.

6.3.3.7.3 TRACG-LOCA Break Spectrum Calculations The break spectrum calculations were performed in Reference 42 to determine all potentially limiting initial conditions, single failures, break locations, and break size combinations. All calculations were performed for both GNF3 and GE14 fuel, and all calculations were performed with a loss of offsite power coincident with the break. All break spectra were calculated assuming a maximum core thermal power corresponding to the current licensed thermal power, plus power uncertainty, of 3,499 MW with an initial dome pressure of 1045 psia.

Only three limiting single failures are evaluated for the standard LOCA analysis, which are Division I Battery, Division II Battery and LPCI Injection Valve. The other three single failures, which are Diesel Generator (DG), HPCI and One ADS Valve, result in more ECCS systems available than at least one of the three limiting single failures and, therefore, are not considered in the break spectrum calculations.

For Division I Battery Failure, the core spray line (CSL), feedwater line (FWL), recirculation suction line (RSL), recirculation discharge line (RDL), Main Steam Line (MSL) and Reactor Water Cleanup (RWCU) breaks are considered. The limiting break sizes are 0.3185, 0.3154, and 0.3743 ft2 for RDL, RSL and FWL, respectively. The CSL, MSL and RWCU are clearly non-limiting compared to the recirculation line breaks.

For Division II Battery Failure, the CSL, FWL, RSL, RDL, MSL and RWCU breaks are considered. The limiting break sizes are 0.1280, 0.1056, and 0.4491 ft2 for RDL, RSL and FWL, respectively. The CSL, MSL and RWCU are clearly non-limiting compared to the recirculation line breaks.

For LPCI Injection Valve Failure, the RSL, RDL and CSL breaks are considered. The limiting break sizes are 0.7924 and 0.7848 ft2 for RDL and RSL, respectively. Other breaks are not included for this failure because they are not limiting.

The Double Ended Guillotine Break (DEGB) peak cladding temperature (PCT), vessel pressure, and water level for GNF3 are provided in Figures 6.3-79, 6.3-80, and 6.3-81. The PCT, vessel pressure, and water level at the most limiting break for GNF3 are provided in Figures 6.3-82, 6.3-83, and 6.3-84.

6.3.3.7.4 TRACG-LOCA Statistical Analyses Based on the break spectra calculations, potentially limiting breaks were chosen for statistical analysis in Reference 42. The results of the statistical analyses are shown in Table 6-3.4, with 6.3-35 REV 24 11/22

FERMI 2 UFSAR the overall maximum peak cladding temperature, maximum local oxidation (MLO), and core wide oxidation (CWO) for GE14 and GNF3 fuel types.

6.3.3.7.5 Compliance Evaluations The licensing basis PCT, maximum local fuel cladding oxidation (MLO), and total fraction of fuel cladding oxidized in the core (CWO) for GE14 and GNF3 are determined based on the results from the statistical analyses. The licensing basis PCT, MLO and CWO values are identified in Table 6.3-4.

6.3.3.7.6 Operating Mode Considerations The ECCS performance (Reference 42) was also evaluated for the following operating mode considerations:

a. Maximum Extended Operating Domain (MEOD) - The MEOD and Maximum Extended Load Line Limit Analysis (MELLLA) provide an expanded operating rod line and an increased core flow range operating domain as shown in Figure 4.4-3.

b. Partial Feedwater Heating (PFH) - The Feedwater Heaters Out-of-Service (FWHOOS) and Final Feedwater Temperature Reduction (FFWTR) mode of the PFH mode of operation (References 6 and 7).

c. Single Loop Operation (SLO) - SLO is permitted when operation is below 66.1% of rated power with recirculation pump speed limited to 75%

(References 12 and 14).

d. Out-of-Service Equipment - The Fermi-2 Technical Specifications allows the turbine bypass, moisture separator reheater and several SRVs to be inoperable without requiring a plant shutdown. The unavailability of the turbine bypass and moisture separator has no impact on the results of the ECCS analysis because no credit for these systems has been taken in the ECCS evaluation.

The availability of SRVs does not impact the calculated licensing basis PCT results since the limiting break events produce only a mild pressurization during the early time period of the event.

6.3.3.8 Loss-of-Coolant Accident Analysis Conclusions Having shown compliance with the applicable acceptance criteria of Subsection 6.3.3.2, it is concluded that the ECCS will perform its function in an acceptable manner and meet all of the 10 CFR 50, Section 50.46 acceptance criteria.

6.3.3.9 Thermal Shock Considerations The ECCS pumps starting at some time after the accident are at ambient (greater than 40°F) and could be heated rapidly as they draw their suctions from the suppression pool.

The HPCI pump and piping system considers a rapid rise in suction temperature from ambient (greater than 40°F) to the maximum operating temperature. The suction is normally 6.3-36 REV 24 11/22

FERMI 2 UFSAR from the condensate storage tank (less than 100°F), but can be switched to the suppression pool. If the reactor is not depressurized, the suppression pool temperature rises slowly, providing ample time for the operator to either depressurize and use the LPCI and/or core spray, or to cool the suppression pool with the containment cooling subsystem of the RHR system.

The design of the ECCS pumps (except HPCI), therefore, considers the differences in the rate of expansion between stationary and rotating parts in order to ensure operability during the transients (sudden change in water temperature from 40° to 170°F).

The piping design similarly considers this thermal shock. The steam line in the HPCI turbine is kept warm since it is normally open from the reactor with a drain pot at the turbine end of the line. A design requirement for the turbine itself is for rapid start, i.e., admission of hot steam to a cold turbine. The turbine vendor has considered the possible thermal shock effects in his design. The turbine exhaust increases rapidly from ambient (greater than 40°F) to operating (300°F) temperature, which is considered in both turbine and piping design.

The output of these ECCS subsystems into the reactor introduces relatively cold water into a hot RPV, and thermal shock is considered in the design of the reactor vessel, its nozzles, and the feedwater lines. The LPCI discharges via the hot recirculation line, so this thermal shock is also considered in the recirculation system piping design.

Section 5.2 contains a summary of results of the cold water injection thermal stress analyses.

6.3.4 Inspection and Testing Each active component of the ECCS required to operate in a DBA is designed to be operable for test purposes during normal operation of the nuclear steam supply system (NSSS).

Regular tests are performed on the system to verify operability. If a test shows some element of the system to be inoperative, repairs are made to return the system to fully operative status.

A failure of the system occurring between tests may have serious consequences, depending on whether or not a need to function occurs before the next test is performed. There is, therefore, a direct relationship between the system unreliability, the rate of occurrence of system failures from all causes, and the testing interval for the system.

It has been shown that the test frequency as well as the failure rate affect system reliability.

There are practical limits on test frequency, such as the possibility of wearing out system components with too much testing. The test frequency outlined in the Technical Specifications is based upon these considerations.

The HPCI system, ADS, and core spray system have no normal process uses, and therefore are tested periodically to provide assurance that the ECCS will operate to effectively cool the reactor core in an accident. The four LPCI pumps may be placed in use as part of the RHR system and, if so, their status is known from normal process uses. However, the LPCI pumps should be tested no less frequently than the rest of the ECCS. Other parts of the LPCI, such as the two testable check valves inside the primary containment drywell and the four shutoff valves outside the drywell, are intended for use only in an accident, so they are also tested periodically.

6.3-37 REV 24 11/22

FERMI 2 UFSAR Preoperational tests of the ECCS were conducted during the final stages of plant construction prior to initial startup. These tests ensured the proper functioning of all controls and instrumentation, pumps, piping, and valves. System reference characteristics such as pressure differentials and flow rates were documented during the preoperational tests and will be used as base points for measurements obtained in the subsequent operational tests.

During plant operations, the pumps, valves, piping, instrumentation, wiring, and other components outside the primary containment can be visually inspected at any time.

Components inside the primary containment can be inspected when the drywell is open for access. When the RPV is open, for refueling or other purposes, the spargers and other internals can be inspected. The testing frequencies of most components of the ECCS are correlated with the testing frequencies of the associated controls and instrumentation. When a pump or valve control is tested, the operability of the pump or valve and the associated instrumentation is also tested by the same action.

When the system is tested, the operation of most of the components is indicated in the main control room. There are exceptions that require local observation at the component and may require special tests for which there are special provisions and methods.

Pressure-operated relief valves may leak after operation and it is not advisable to overpressurize the system for test, so relief valves are removed as scheduled at refueling outages for bench tests and setting adjustments. Bench tests of automatic depressurization valves are discussed in Subsection 5.2.2.

A pressure-operated control valve such as the one upstream of the HPCI system barometric condenser is functionally tested and adjusted in place, in accordance with the valve manufacturer's manual and the system specification for pressure setting. A test pressure connection is provided to check and adjust the setting.

Reverse flow and excess flow check valves in the ECCS are tested periodically in accordance with the Technical Specifications and the Inservice Testing Program.

Test lines are provided between pairs of containment isolation valves in the ECCS to measure leakage when the containment is pressurized for tests. The test line is also used to pressurize between the closed valves to identify which one is leaking. Allowable valve leakage is in accordance with Section 6.2 and the Technical Specifications.

Allowable valve seat leakage during shop hydrostatic tests for nuclear Class 1, 2, and 3 gate, globe, and ball valves associated with these systems is 2 cm3/hr/in. of seat diameter during hydrostatic test at design pressure. Leakage for check and stop- check valves is 10 cm3/hr/in.

diameter of valve seat at the design differential pressure across the valve. Valve packing leakage during the hydrostatic test is specified as "no visible leakage."

Pumps for the ECCS are equipped with face-type mechanical shaft seals.

A design flow functional test of the HPCI system up to the normally closed pump discharge valve is performed during normal plant operation by pumping water from the condensate storage tank and back through the full-flow test return line. The HPCI system turbine pump is driven at its rated output by steam from the reactor. The suction valves from the suppression pool and discharge valves to the reactor feedwater line remain closed.

6.3-38 REV 24 11/22

FERMI 2 UFSAR The HPCI system test conditions are tabulated on the HPCI system process diagram, Figures 6.3-1 through 6.3-5. If an initiation signal occurs while the HPCI system is being tested, the system returns to the automatic startup mode and supplies water to the reactor.

The HPCI may be tested at full flow with condensate at any time except when the reactor vessel water level is low, the condensate level in the condensate storage tank is below the reserve level, or the valves from the suppression pool to the pump are open.

During the HPCI flow test, the minimum-flow bypass valve opens/closes as required per the logic. The turbine steam valves and the flow test valves to the condensate storage tank are opened to support the HPCI flow test.

To ensure proper operation of the valves when pumping from the suppression pool, the HPCI suction valve auto transfer test is performed to meet Technical Specification requirements.

Credit is taken for the RHR and CS testing from the suppression pool as an indication of strainer performance/degradation.

The RHR, CS and HPCI suppression pool suction strainers are inspected periodically in accordance with the plant preventive maintenance program.

Each loop of the core spray systems may be tested during reactor operation. The test conditions are tabulated on the core spray system process diagram, Figures 6.3-7 through 6.3-

11. The normal system test does not inject cold water into the reactor because the testable check valve is held closed by the reactor pressure which is higher than core spray pump pressure. To test the injection portion of the system, using demineralized water, the reactor must be shut down and depressurized. This prevents unnecessary thermal stresses.

To test the core spray pumps at rated flow, the pump suction valve from the suppression pool is open, the pump is started using the remote manual switches in the main control room and the test bypass valve is opened to the suppression pool. Proper operation is determined by observing the instruments in the main control room. The core spray system outside the drywell is checked for leaks.

The two motor-operated injection valves outside the drywell and the air-operated testable check valve inside the drywell are tested as described in the Fermi 2 Inservice Testing Program.

If an initiation signal occurs during the test, the core spray system is signaled to start and the system returns to the automatic startup mode and is ready to deliver water to the reactor.

Similarly, LPCI pumps and valves are tested periodically during reactor operations. With the injection valves closed and the return line open to the suppression pool, full-flow pumping capability is demonstrated. The injection valves are tested, and the testable check valves are operated, as described previously for the core spray valves. The system test conditions during reactor shutdown are shown on the RHR/LPCI system process diagram, Figures 6.3-14 through 6.3-16. The portion of the LPCI outside the drywell is inspected for leaks during tests. Controls and instrumentation are tested as described in Section 7.3.

On receipt of an LPCI initiation signal during tests, the valves in the test bypass lines and in the shutdown cooling system are closed automatically to ensure that the LPCI pump discharge is routed properly to the reactor vessel.

6.3-39 REV 24 11/22

FERMI 2 UFSAR Detailed specifications for ECCS component testing are contained in Chapter 14 and the Technical Specifications.

The valves performing an isolation function between high-pressure and low-pressure portions of systems connected to the RCS are tested in accordance with the Technical Specifications.

Table 6.3-9 lists the valves that perform an isolation function between high-pressure and low-pressure portions of systems connected to the RCS. These pressure isolation valves meet the requirements of the ASME Code Section XI, Pump and Valve Testing Program, and are categorized as A or AC. The testing program for the valves, which is referenced in the Technical Specifications, consists of the following methods:

a. Exercise the valve and verify the valve position during refueling and after maintenance before the return to service in accordance with IWV-3300 or IWV-3522(b)

b. Exercise the valve (full stroke) for operability during the cold-shutdown mode as time permits, but not more frequently than once every 3 months

c. Measure the full-stroke time (not for check valves)

d. Leak test the valve seat before reaching power operation following refueling and after valve maintenance before the return to service.

These valves will not be routinely exercised every 3 months during plant operation as required by IWV-3410 because of the following.

a. Such tests remove one of the two barriers protecting the low-pressure portion of the ECCSs

b. The operators on testable check valves cannot overcome the force on the valve with reactor pressure on one side.

Instead, the valves will be exercised during cold-shutdown periods as time permits (but not more frequently than once every 3 months). If there is excessive leakage through the normally closed gate and check valves, the operator will be alerted by the high pressure alarm indicated in Table 6.3-10. The operator will then be procedurally required to close the normally open gate valve from the control room to effect isolation.

6.3.5 Instrumentation Requirements Design details and logic of the instrumentation for the ECCS are discussed in Section 7.3.

6.3.5.1 High Pressure Coolant Injection Actuation Instrumentation The HPCI is automatically actuated by the following sensed variables: (1) RPV low water level; or, (2) drywell high pressure.

In addition, the HPCI can be manually actuated from the main control room.

6.3.5.2 Automatic Depressurization System Actuation Instrumentation The ADS is automatically actuated when the RPV low water level is coincident with drywell high pressure. A time delay is incorporated as discussed in Chapter 7. In addition, two core 6.3-40 REV 24 11/22

FERMI 2 UFSAR spray pumps or an RHR pump must be running. Each ADS valve can be manually actuated from the main control room.

6.3.5.3 Core Spray Actuation Instrumentation The core spray is automatically actuated by the RPV low water level or drywell high pressure. In addition, the core spray can be manually actuated from the main control room.

6.3.5.4 Low Pressure Coolant Injection Actuation Instrumentation The LPCI is automatically actuated by the RPV low water level or drywell high pressure. In addition, the LPCI can be manually actuated from the main control room.

Emergency Procedures contain adequate caution to deter the operator from premature LPCI flow diversion. The Emergency Procedures caution the operator against diversion unless adequate core cooling is assured. The containment cooling modes of the RHR are secondary to core cooling requirements except in those instances outside the design envelope involving multiple failures, for which maintenance of containment integrity is required to minimize risk to the environment.

6.3-41 REV 24 11/22

FERMI 2 UFSAR 6.3 EMERGENCY CORE COOLING SYSTEMS REFERENCES

1. GE Nuclear Energy, Fermi-2 SAFER/GESTR-LOCA, Loss-of-Coolant Accident Analysis, NEDC-31982P, July 1991, including Errata and Addenda No. 1, April 1992.

2. R. T. Lubin and G. S. Springer, "Surface Deformations in a Draining Liquid,"

Journal of Spacecraft and Rockets, Vol. 6, No. 2, February 1969.

3. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, Appendix K, NEDE-20566-P, December 1975.

4. General Electric Company, The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident - SAFER/GESTR Application Methodology, NEDE 23785-1-PA, Revision 1, October 1984.

5. Letter from NRC to Detroit Edison, "Amendment No. 87 to Facility Operating License No. NPF-43 (TAC No. M82102)," September 9, 1992.

6. GE Nuclear Energy, Maximum Extended Operating Domain Analysis for Detroit Edison Company Enrico Fermi Energy Center Unit 2, NEDC-31843P, July 1990.

7. Letter from NRC to Detroit Edison, "Amendment No. 69 to Facility Operating License No. NPF-43: TAC No. 77676," May 15, 1991.

8. GE Nuclear Energy, Maximum Extended Load Line Limit and Feedwater Heater Out-of-Service Analysis for Enrico Fermi Energy Center Unit 2, NEDC-31515, Revision 1, August 1989.

9. General Electric Company, General Electric Company Analytical Model for Loss-of-Coolant Analysis In Accordance with 10 CFR 50, Appendix K, NEDO-20566A, September 1986.

10. Letter, C. O. Thomas (NRC) to J. F. Quirk (GE), "Acceptance for Referencing of Licensing Topical Report NEDE-23785, Revision 1, Volume III (P), "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident,"

June 1, 1984.

11. Deleted

12. General Electric Company, Fermi 2 Single-Loop Operation Analysis, MDE 0368, Revision 1, April 1987.

13. Deleted

14. General Electric Company, Enrico Fermi Energy Center Unit 2 Single-Loop Operation, NEDE-32313P, September 1994.

15. GNF Supplemental Reload Licensing Report for Fermi Power Plant Unit 2 (Latest approved edition as identified in the COLR).

16. Enrico Fermi 2 SAFER/GESTR Loss of Coolant Accident Analysis for GE14 Fuel, GE-NE-0000-0030-6565-R1, June 2008.

17. Fermi 2 Energy Center Extended Power Uprate Task T0407: ECCS LOCA SAFER/GESTR, GE-NE-0000-0015-4730-01, Revision 2, August 2004.

6.3-42 REV 24 11/22

FERMI 2 UFSAR 6.3 EMERGENCY CORE COOLING SYSTEMS REFERENCES

18. NEDC-32868P, Revision 1, "GE14 Compliance With Amendment 22 of NEDE-24011-P-A (GESTAR-II)", September 2000.

19. Enrico Fermi 2 SAFER/GESTR Loss of Coolant Accident Analysis for GE11 Fuel, GE-NE-0000-0047-1716-R1, June 2008.

20. GE14 Fuel Design Cycle Independent Analyses For Fermi Unit 2, GE-NE-0000-0025-3282-00, November 2004.

21. 10 CFR 50.46 Notification Letter 2006-01, July 28, 2006

22. 10 CFR 50.46 Notification Letter 2007-01, December 18, 2007

23. 10 CFR 50.46 Notification Letter 2008-01, Rev. 1, November 25, 2008, Edison File R1-8114

24. NRC Letter to Mr. Jack M. Davis from Mahesh L. Chawla Fermi 2 - Approval of Plant Specific ECCS Evaluation Model Reanalysis (TAC No. MD9169), June 30, 2009

25. GE Analysis, Reduced LPCI Flow GE11 and GE14 ECCS LOCA-Evaluation, GE-NE-0000-0121-0144-R1, July 2010

26. Fermi 2 Calculation, DC-0367 Vol I, Hydraulic Calculations of the RHR System

27. 10 CFR 50.46 Notification Letter 2011-02, July 20, 2011, Edison File R1-8112

28. 10 CFR 50.46 Notification Letter 2011-03, July 20, 2011, Edison File R1-8113

29. TRVEND 1-2OX0YP-3 Supplement to Error Notification Letters 2008-01, 2011-02, and 2011 Verified Final GEH Letter Report, Edison File R1-8111

30. GE Confirmation of Inputs, TRVEND 0000 0147 2229 R0, Edison File R1-8139

31. GEH 10 CFR 50.46 Notification Letter 2013-01, January 15, 2013, Edison File R1-8173

32. TRVEND 0000 0154 0175 R0, Fermi Recirculation Line Break - LPCS Curve, October 15, 2012, Edison File R1-8172

33. Deleted

34. TRVEND 00N1275R0, Revision 0, DTE Energy Enrico Fermi 2 Automatic Depressurization System High Drywell Pressure Bypass Timer GE14 Evaluation; dated February 2014

35. 10 CFR 50.46 Notification Letter 2014-01, May 21, 2014, Edison File R1-8292

36. 10 CFR 50.46 Notification Letter 2014-02, May 21, 2014, Edison File R1-8293

37. 10 CFR 50.46 Notification Letter 2014-03, May 21, 2014, Edison File R1-8294

38. 10 CFR 50.46 Notification Letter 2014-04, May 21, 2014, Edison File R1-8295

39. GE Hitachi Nuclear Energy, NEDC-33865P, Revision 0, DTE Energy Enrico Fermi 2 SAFER/PRIME-LOCA Loss-of-Coolant Accident Analysis, March 2015 6.3-43 REV 24 11/22

FERMI 2 UFSAR 6.3 EMERGENCY CORE COOLING SYSTEMS REFERENCES

40. GNF Licensing TR, The PRIME Model for Analysis of Fuel Rod Thermal-Mechanical Performance, Technical Bases - NEDC-33256P-A Revision 1, Qualification - NEDC-33257P-A Revision 1, and Application Methodology -

NEDC-33258P-A Revision 1, September 2010

41. Licensing Topical Report, TRACG Application for Emergency Core Cooling Systems / Loss-of-Coolant-Accident Analyses for BWR/2-6, NEDE-33005P-A, Revision 2, May 2018.

42. TRVEND 24MCGNF3FTRT0417, Rev 1, DTE Energy Fermi Unit 2 TRACG ECCS Loss-of-Coolant Accident (LOCA) Analysis, Revision 1, November 2019.

GEH Doc Number: 005N1475, Edison File #: T19-137 6.3-44 REV 24 11/22

FERMI 2 UFSAR TABLE 6.3-1 SHUTDOWN COOLING AND EMERGENCY CORE COOLING SYSTEM OPERATION Accident or RHR or ECCS Subsystems Redundancy Provided condition Required Operation and Components Used Within System Backup System(s)

Shutdown For a normal shutdown and cooldown, the main Main condenser Two RHR heat RHR cooling Cooling condenser is used to condense decay-heat-generated RHR heat exchangers, exchangers (one heat subsystem backs up steam until the condenser vacuum is lost. Makeup RHR main pumps exchanger sufficient) the main condenser water is provided as for condenser isolation. When the used for shutdown condenser is no longer effective, primary system Four RHR pumps (two cooling cooling is continued by taking water from one of the pumps sufficient) recirculation loops, through the RHR heat exchangers, and back to the recirculation loop using the RHR pumps. Should the reactor be isolated from the condenser by operation of the isolation valve (not a normal operation) steam is first dumped to the suppression pool rather than to the condenser (below).

Isolation of Upon the closing of the main steam line valve Relief valves Total of 15 safety/relief 1. RCICa condenser following a scram, automatic operation of relief valves valves available (nine (occurs when causes steam to be dumped to the suppression pool, the RHR heat exchangers sufficient) 2. HPCIa a reactor RHR removes heat from the pool. 3. Control rod scram is Two RHR heat The single RCIC steam-driven pump takes water from exchangers (one drive water accompanied systema by condensate storage and discharges to the feedwater sufficient) containment line. Signal: low reactor vessel water level. RCIC pump 4. Core spray and isolation) Condensate (reserve LPCIa storage)

Small leaks First Level Feedwater system and control rod drive Second level HPCI (accident system can provide some makeup water. and/or RCIC condition)

Second Level The single HPCI steam-driven pump takes water from condensate storage and discharges to HPCI steam-driven pump, RCIC pump (600gpm) Third level a feedwater line. Signal: low reactor vessel water level station battery (no ac or high drywell pressure. The decay-heat-generated required, 5000gpm) Water can also come steam flows to the HPCI turbine and is exhausted to the from suppression pool Five safety/relief valves At low pressure suppression pool.

Manual actuation of any (RV approximately Third Level Automatic depressurization system vents Three of four pumps of of 15 safety/relief 300 psi) both LPCI steam to the suppression pool. With decreased pressure LPCI valves and core spray can LPCI and core spray systems can provide water operate.

Two loops of core spray signals: low reactor vessel level and high drywell system (alternate) SRVs pressure and core spray or RHR pump running.

Standby ac power supply Large leaks Core spray system pumps water from the suppression Pumps with electric Two independent core LPCI (accident pool to core. Signal: low reactor vessel water level or motors, spray sparger, spray systems standby condition) high drywell pressure. standby ac bus; different ac bus available for each spray loop (6350 gpm per core spray system and 10,000 gpm per LPCI/RHR pump)

LPCI operates. Three of the four RHR main pumps Pumps and motors. Power Three of the four RHR Core spray take water from the suppression pool and delivers it to from standby ac bus pumps required. All a recirculation loop. Signal: low reactor vessel level or (30,000 gpm for 3 LPCI have ac standby as high drywell pressure. pumps plus 12,700 gpm backup power source for two core spray (four pumps are systems) signaled to start) a Systems used for reactor water inventory control.

Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.3-2 MATERIALS FOR THE PRINCIPAL EMERGENCY CORE COOLING SYSTEM COMPONENTS Item Supplier Impeller Casing Shaft LPCI pump Byron Jackson Martensite SS Carbon steel Austenite SS Core spray pump Byron Jackson Martensite SS Carbon steel Austenite SS HPCI pump Byron Jackson Martensite SS Carbon steel Martensite SS HPCI turbine Terry Low-alloy steel Carbon steel Low-alloy steel ADS safety/relief valves Target Rock N/A N/A N/A two-stage walves Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.3-3 HAS BEEN INTENTIONALLY DELETED Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.3-4

SUMMARY

OF RESULTS OF LOSS-OF-COOLANT ACCIDENT ANALYSIS Parameters Results Results Acceptance Criteria

1. Fuel Type GE14 Fuel GNF3 Fuel

2. Limiting Break Recirculation Recirculation Suction Small Break Suction Small Break

3. Limiting Failure Division II DC Division II DC Power (Battery) Power (Battery)

4. Peak Cladding < 1980 °F < 2150 °F 2200 °F Temperature (Licensing Basis)

5. Maximum Local < 6.0 % < 9.5 % 13 %(a)

Oxidation

6. Core-Wide Metal- < 0.02 % < 0.02 % 1.0 %

Water Reaction

7. Coolable Geometry Items 4 and 5 Items 4 and 5 PCT 2200 °F and Maximum Local Oxidation 13 %(a)

8. Long Term Cooling Core flooded above Core flooded above Core temperature top of active fuel top of active fuel acceptably low and long-term decay heat removed a

The MLO calculated by TRACG-LOCA is limited to 13% to ensure the 10CFR50.46 limit of 17% is satisfied.

Page 1 of 1 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-5 EMERGENCY CORE COOLING SYSTEM SINGLE - FAILURE EVALUATIONSa Assumed Failureb Suction Break Systems Remainingc,d LPCI valve All ADS, 2 core spray, HPCI Divisional diesel generators (EDG) All ADS, 1 core spray, HPCI, 2 LPCI Battery (Division I) HPCI, 2 LPCI, 1 core spray Battery (Division II) All ADS, 1 core spray, 2 LPCI HPCI All ADS, 4 LPCI, 2 core spray One ADS valve All ADS minus one, 2 core spray, HPCI, 4 LPCI a

This table shows the single active failures considered in the ECCS performance evaluation.

b Other postulated failures are not specifically considered because they all result in at least as much ECCS capacity as one of the above assumed failures.

c Systems remaining, as indentified in this table, are with concurrent loss-of-offsite power and are applicable to all non-ECCS line breaks. For a LOCA from an ECCS line break, the systems remaining are those listed, less the ECCS in which the break is assumed.

d Analyses performed with one ADS valve assumed unavailable in addition to the single failure (Table 6.3-6).

Page 1 of 1 REV 16 10/09

FERMI 2 UFSAR TABLE 6.3-6 ECCS ANALYSIS SIGNIFICANT INPUT VARIABLES AND INITIAL CONDITION Variable Units Value A. Plant parameters Core Thermal Power, plus uncertainty MWth 3499 Nominal Vessel Dome Pressure psia 1045 Maximum Core Recirculation Flow mlb/hr 105 Rated normal feedwater temperature °F 426.5 Reduced feedwater temperature °F 376.5 Nominal downcomer water level (above vessel inches 563.5 zero)

B. Emergency Core Cooling System Parameters Low-Pressure Coolant Injection (LPCI) System Vessel Pressure at Which Flow psid 264 Credited to Commence Minimum Flow at psid 20 Vessel Pressure of:

Two pumps gpm 21,850 Three pumps gpm 26,260 Four pumps gpm 27,625 Initiating Signals and Setpoints:

Low Water Level ft above TAF* 1.02 or High Drywell Pressure psig 2.0 Assumed Injection Valve Stroke Time sec 30 Maximum Vessel Pressure At Which LPCI psig 350 Injection Valve Can Open Maximum Allowable Time from Drywell Pressure sec 77 Initiating Signal to Pump at Rated Speed and Ready to Inject Flow to Vessel with Emergency Power Minimum Break Size for Which Loop Selection ft2 0.15 Logic Assumed to Select Unbroken Loop Page 1 of 3 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-6 ECCS ANALYSIS SIGNIFICANT INPUT VARIABLES AND INITIAL CONDITION Variable Units Value Low Pressure Core Spray (CS) System Vessel Pressure at Which Flow May Commence psid 280 Minimum Rated Flow at Vessel Pressure of: psid 100 One Loop gpm 5,625 Initiating Signals and Setpoints:

Low Water Level ft above TAF* 1.02 or High Drywell Pressure psig 2.0 Runout Flow at Vessel Pressure of: psid 0 One Loop gpm 7,013 Assumed Injection Valve Stroke Time sec 15 Maximum Vessel Pressure at Which LPCS psig 350 Injection Valve Can Open Maximum Allowable Time from Drywell Pressure sec 47 Initiating Signal to Pump at Rated Speed and Ready to Inject flow to Vessel with Emergency Power High Pressure Coolant Injection (HPCI) System Vessel Pressure at Which Flow May Commence psia 1135 Minimum Rated Flow at Vessel Pressure of: psia 1135 to 165**

gpm 5000 Initiating Signals and Setpoints:

Low Water Level ft above TAF* 7.6 or High Drywell Pressure psig 2.0 Maximum Allowable Time from Drywell Pressure sec 60 Initiating Signal to Rated Flow Available and Injection Valve Wide Open Automatic Depressurization System (ADS)

Total Number of Valves Installed -- 5 Number of Valves Assumed in Analysis -- 4 Page 2 of 3 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-6 ECCS ANALYSIS SIGNIFICANT INPUT VARIABLES AND INITIAL CONDITION Variable Units Value Minimum Flow Capacity of any 4 Valves at mlb/hr 3.48 Vessel Pressure psig 1090 Initiating Signals and Setpoints:

Low Water Level ft above TAF* 1.02 and High Drywell Pressure psig 2.0 Time Delay After Initiating Signal sec 120

• TAF (Top of Active Fuel) = 366.3 inches from vessel zero

• • HPCI pump is designed to produce a flow of 5000 gpm at an RPVpressure of 1184 psia, which exceeds LOCA input.

Page 3 of 3 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-7 OPERATIONAL SEQUENCE OF EMERGENCY CORE COOLING SYSTEMS FOR DESIGN-BASIS ACCIDENTa Time (sec) Events 0 Design-basis LOCA assumed to start; normal auxiliary power assumed to be lost.

0 Drywell high pressure and reactor low water level reached; scram; HPCI, LPCS, LPCI signaled to start on high drywell pressure.

3 Reactor low-low water level reached. Main steam isolation valves close; HPCI receives second signal to start, all diesel generators signaled to start.

7 Reactor low-low-low water level reached. Second signal to start LPCI and LPCS; autodepressurization sequence begins.

<13 All diesel generators ready to load; open HPCI injection valve; begin energizing LPCI pump motors.

18 Begin energizing LPCS pump motors.

47 LPCS pumps at rated flow; LPCS injection valves open, completing the LPCS startup.

77 LPCI pumps at rated flow; LPCI injection valves open, completing the LPCI startup.

See Figure Core effectively reflooded assuming worst single failure; heatup terminated 6.3-20 10 minutes Operator shifts to containment cooling.

a For the purpose of all but the next-to-last entry on this table, all ECCS equipment is assumed to function as designed. Performance analysis calculations consider the effects of single equipment failures. (See Subsections 6.3.2.5 and 6.3.3.3.)

Page 1 of 1 REV 21 10/17

FERMI 2 UFSAR TABLE 6.3-8 KEY TO FIGURES IN SECTION 6.3.3.7 Break Size Large Recirculation Small Recirculation Variable Line Break, DEGB Line Break Peak Clad Temperature Vs. Time Figure 6.3-79 (GNF3) Figure 6.3-82 (GNF3)

RPV Pressure Vs. Time Figure 6.3-80 (GNF3) Figure 6.3-83 (GNF3)

Water Level Vs. Time Figure 6.3-81 (GNF3) Figure 6.3-84 (GNF3)

These curves indicate the trends of the variables post-LOCA.

Page 1 of 1 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-9 PRESSURE ISOLATION VALVES Valve Size System P&ID Numbers Type (in.) Function RHR 6M721-2083 E11-F015A, B Gate 24 Discharge to recirculation system 6M721-2084 E11-F050A, B Check 24 Discharge to recirculation system E11-F008 Gate 20 Suction from recirculation system E11-F009 Gate 20 Suction from recirculation system E11-F608 Gate 20 Suction from recirculation system Core spray 6M721-2034 E21-F005A, B Gate 12 Discharge to core spray sparger E21-F006A, B Check 12 Discharge to core spray sparger HPCI 6M721-2035 E41-F006 Gate 14 Discharge to feedwater line E41-F005 Check 14 Discharge to feedwater line RCIC 6M721-2044 E51-F013 Gate 6 Discharge to feedwater line E51-F014 Check 6 Discharge to feedwater line Page 1 of 1 REV 23 02/21

FERMI 2 UFSAR TABLE 6.3-10 PRESSURE ISOLATION PROTECTION AND MONITORING System/Line Relief Valve Overpressure Control Room Control Room Needing Protection Protection Alarm Indicator Local Indicator RHR discharge F025A, B, E11-N022A, B E11-R003A, B, C, D, --

1-1/2 in. at 400 psig 0-600 psig RHR suction F030A, B, C, D, F029, 1 in. -- E11-R002A, B, C, D, --

30 in. Hg, 150 psig Core spray discharge E2100F012A (V22-2016), E21-N007A, B -- E21-R600A, B, E2100F012B (V22-2017), at 440 psig 0-600 psig E2100F011B (V22-2119),

E2100F011A (V22-2120)

HPCI E41-F020 (V22-2044), E41-N031 -- E41-R004, 30 in.

1-1/2 in. at 70 psig Hg, 100 psig RCIC suction E51-F017 (V22-2002), E51-N030 -- E51-R002, 30 in.

1 in. at 70 psig Hg, 85 psig Page 1 of 1 REV 16 10/09

Figure Intentionally Removed Refer to Plant Drawing M-5860 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-1 HIGH PRESSURE COOLANT INJECTION SYSTEM PROCESS DIAGRAM REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5872 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-2 HIGH PRESSURE COOLANT INJECTION SYSTEM HIGH PRESSURE INJECTION ACCIDENT CONDITION REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5873 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-3 HIGH PRESSURE COOLANT INJECTION SYSTEM HIGH PRESSURE INJECTION MODE USING SUPRESSION POOL AS BACKUP SOURCE REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5874 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGUE 6.3-4 HIGH PRESSURE COOLANT INJECTION SYSTEM MINIMUM FLOW MODE REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5875 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-5 HIGH PRESSURE COOLANT INJECTION SYSTEM TEST MODE DURING PLANT OPERATION REV 22 04/19

FIGURE 6.3-6 HAS BEEN DELETED REV 21 10/17

Figure Intentionally Removed Refer to Plant Drawing M-5861 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-7 CORE SPRAY SYSTEM PROCESS DIAGRAM REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5868 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-8 CORE SPRAY -ACCIDENT CONDITION REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5869 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-9 CORE SPRAY SYSTEM TEST MODE DURING PLANT OPERATION USING SUPPRESSION POOL REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5870 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-10 CORE SPRAY SYSTEM TEST MODE DURING PLANT SHUTDOWN USING CONDENSATE STORAGE TANK REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5871 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-11 CORE SPRAY SYSTEM MINIMUM FLOW BYPASS MODE - SUCTION FROM SUPPRESSION POOL REV 22 04/19

FIGURE 6.3-12 HAS BEEN DELETED REV 21 10/17

FIGURE 6.3-13 HAS BEEN DELETED REV 21 10/17

Figure Intentionally Removed Refer to Plant Drawing M-5857 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-14, SHEET 1 LOW PRESSURE COOLANT INJECTION SYSTEM PROCESS DIAGRAM REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5690 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-14, SHEET 2 LOW PRESSURE COOLANT INJECTION SYSTEM PROCESS DIAGRAM REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5866 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-15 LOW PRESSURE COOLANT INJECTION SYSTEM TEST MODE DURING PLANT OPERATION REV 22 04/19

Figure Intentionally Removed Refer to Plant Drawing M-5867 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-16 LOW PRESSURE COOLANT INJECTION SYSTEM MINIMUM FLOW BYPASS MODE REV 22 04/19

FIGURE 6.3-17 HAS BEEN DELETED REV 17 05/11

FIGURES 6.3-18 THROUGH 6.3-23 HAVE BEEN DELETED REV 18 10/12

FIGURE 6.3-24 THROUGH FIGURE 6.3-78 HAVE BEEN DELETED REV 17 05/11

1400 U- 1200

• d 1000 _ ___ _-_ -___

0.

E 00 800 -

8600 - -

C 400 0200 CL 0~

0 0 50 100 150 200 250 300 Time (s)

Fermi2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-79 FERMI 2 GNF3 NOMINAL DEGB RDL BREAK FOR CLTP INITIAL CONDITIONS FOR DIV II NEDC-33919P, Revision 0, Figure 9-33 BATTERY FAILURE - OVERALL CORE PCT REV 23 02/21

1200 1000 -- -- --

Q \

00 E 400 200 0

0 50 100 150 200 250 300 Time (s)

Fermi2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-80 FERMI 2 GNF3 NOMINAL DEGB RDL BREAK FOR CLTP INITIAL CONDITIONS FOR DIV II BATTERY FAILURE - REACTOR PRESSURE NEDC-33919P, Revision 0, Figure 9-29 REV 23 02/21

500 450 400 __ ----__ _-_

__ _ _ _ T AFj 350 _ --

300 250 L BAF t200 150 0 50 100 150 200 250 300 Time (s)

Fermi2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-81 FERMI 2 GNF3 NOMINAL DEGB RDL BREAK FOR CLTP INITIAL CONDITIONS FOR DIV II NEDC-33919P, Revision 0,Figure9-31 BATTERY FAILURE - CENTRL CORE (BYPASS AND UPPER PLENUM) WATER LEVEL REV 23 02/21

2000 .

S1500 E

0 1000-c-

500 0

0 100 200 300 400 500 600 Time (s)

Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-82 FERMI 2 GNF3 NOMINAL SMALL RSL BREAK FOR MELLLA INITIAL CONDITIONS FOR DIV II BATTERY FAILURE - OVERALL CORE PCT NEDC-33919P, Revision 0, Figure 9-6 REV 23 02/21

1400 12 0 0 - - - -- -- - ---

1000 -- - ---

800 -

a 600 E

0 400 200 0

0 100 200 300 400 500 600 Time (s)

Fermi2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-83 FERMI 2 GNF3 NOMINAL SMALL RSL BREAK FOR MELLLA INITIAL CONDITIONS FOR DIV II BATTERY FAILURE - REACTOR PRESSURE NEDC-33919P, Revision 0, Figure 9-2 REV 23 02/21

500 N 450 -_____

400 TAF

>350 5 300 -

0i 250 0 200 150 0 100 200 300 400 500 600 Time (s)

Fermi2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-84 FERMI 2 GNF3 NOMINAL SMALL RSL BREAK FOR MELLLA INITIAL CONDITIONS FOR DIV II BATTERY FAILURE - CENTRAL CORE (BYPASS AND UPPER PLENUM) WATER LEVEL NEDC-33919P, Revision 0, Figure 9-4 REV 23 02/21

FERMI 2 UFSAR 6.4 HABITABILITY SYSTEMS Control center habitability systems ensure that the main control room can be occupied under normal, accident, and postaccident conditions. Habitability systems include the systems, components, facilities, supplies, and equipment required for safe habitation of the main control room.

6.4.1 Habitability Systems Design Bases The bases for the functional design of the habitability systems are given below. The bases result in systems that ensure compliance with General Design Criterion 19, 10 CFR 50, Appendix A. Under any design-basis conditions, the environment within the main control room is safe, with personnel protected from radiation, fire, toxic gases, and noxious substances.

6.4.1.1 Radiation Shielding and Air Filtration The total radiation dose to main control room personnel is the dose received while occupying the control center. Doses received while in the main control room are due to the radiation that penetrates the biological shielding and to the isotopes that enter the control center through the ventilation system or through inleakage. Source terms and individual contributions to total doses are given in Chapter 15, along with a further discussion of the assumptions, the physical models, and the methods of analysis.

Sufficient radiation shielding and air filtration are provided to ensure that radiation exposures of main control room personnel do not exceed 5 rem whole-body, or its equivalent to any part of the body, for the duration of a design-basis accident (DBA). For the DBA-LOCA and the Fuel Handling Accident, the dose to main control room personnel does not exceed 5 rem TEDE.

Following is a list of principal assumptions used in determining the control center personnel doses:

a. The plant personnel occupying the control center at the time the LOCA occurs remain in the control center for a period of 24 hr after that occurrence

b. Control center personnel shift changes occur twice per day, starting 24 hr after the occurrence

c. The occupancy factor is 1 for 0-1 day, 0.6 for 1-4 days, and 0.4 for 4-30 days

d. The breathing rates of the main control room personnel are 3.47 x 10-4 m3/sec as specified by the International Committee on Radiation Protection (ICRP)

(Reference 1)

e. In the event of a LOCA, the control center mode in operation is automatically shut down and the emergency makeup air filtration system is placed in operation.

f. When emergency makeup air is supplied to the main control room, the rate of introduction of outside air is 1800 cfm maximum 6.4-1 REV 24 11/22

FERMI 2 UFSAR

g. Radiation monitors in the reactor/auxiliary (i.e., fuel pool ventilation exhaust ducting) building detect airborne radiation concentrations above those specified in the Technical Specifications and cause the control center air conditioning system to automatically switch to its emergency mode of operation

h. Filter trains are provided for emergency makeup air as well as recirculated air.

The filter trains are located outside the main control room

i. Charcoal filters (described in Table 9.4-1) have a assigned decontamination efficiency of 95 percent for removal of all forms of iodine; 99 percent efficiency could be claimed for the recirculation charcoal adsorber according to Regulatory Guide 1.52, but only 95 percent efficiency is claimed to avoid the more frequent testing and replacement of charcoal

j. Control center filter banks are in service throughout the course of the LOCA, filtering outside air makeup l800 cfm maximum and recirculated air 1200 cfm for a total filtered airflow of 3000 cfm

k. The mechanisms for introduction of radioisotopes into the main control room are

1. Intake through filter trains during periods of air makeup

2. Infiltration of outside air or exchange of inside-outside air due to opening and closing of main control room doors at shift-change times. The total quantity of unfiltered inleakage is not more than 173 cfm.

l. A radiation monitor in the control center air intake ducting, before filtration by the emergency makeup air intake and recirculation filter trains, provides radiation level information to the operators.

The assumed atmospheric dispersion factors and radioactive source terms used for each accident analysis are listed in Chapter 15.

Table 15.6.5-4 presents the doses to the control room operator from occupancy of the control room for the 30-day course of a LOCA. Table 12.1-14 presents the direct doses through the concrete walls and ceilings for the 30-day course of a LOCA as experienced by main control room personnel.

6.4.1.2 Physical Environment Systems and controls are provided to ensure that the environment in the control center is safe and comfortable. The thermal environmental conditions are within the comfort range specified in American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) Comfort Standard 55-66 (Reference 2), with a nominal dry bulb temperature of 75°F and a relative humidity not exceeding 60 percent, except for the mechanical equipment room (MER) and SGTS room which are discussed in Subsection 9.4.1.1. The emergency operating modes of the air conditioning system are designed to meet single-failure criteria and ensure l00 percent backup for the entire system, with the exception of the common ductwork and filters. The smoke/Halon dampers to the relay room, cable spreading room or computer room will close due to a single active failure in the Halon fire protection system.

6.4-2 REV 24 11/22

FERMI 2 UFSAR Sufficient time is available to take manual action to reestablish airflow. Ventilation capability is provided by the air conditioning system in both the normal mode and the emergency air makeup mode of operation. Main control room environmental conditions, including radiation levels, are monitored. The air volume of the control center envelope is approximately 252,731 ft3, which is sufficient to allow closing of the makeup air intake for a period of more than 28 days without exceeding permissible carbon dioxide concentrations when three workers occupy the main control room.

6.4.1.3 Fire Protection Noncombustible and flame-retardant materials are used where practical, and equipment, electrical components, and control instrumentation are designed to minimize fire hazards.

Fire and smoke detection and alarm systems are provided as required. Applicable NFPA codes and standards used for guidance are listed in Subsection 9.5.1.

Portable fire extinguishers are located in the main control room. The equipment is adequate to control fires that could originate inside the main control room. The air conditioning system has a purging capability to expedite the discharge of smoke from the main control room.

The control center can be isolated to prevent admission of smoke or noxious fumes resulting from a postulated fire outside the main control room. The control center is designed to be protected against exterior fire exposure by the 3-hr-rated walls. Personnel are not harmed and safety-related equipment is not damaged by the proper use of the portable fire extinguishers in the main control room.

Personnel training ensures that plant operators are cognizant of the proper use of fire extinguishers and know the emergency procedures to be taken in the event of fire.

6.4.1.4 Personnel Protection and First Aid The control center contains emergency safety breathing apparatus for personnel use, as well as first aid supplies for immediate emergency use.

6.4.1.5 Utilities and Sanitation Normal communications, lighting, kitchen, and sanitary facilities are provided in the control center to ensure habitability. The onsite power system supplies power for the main control room habitability systems when offsite power is not available.

6.4.2 System Design 6.4.2.1 Radiation Shielding Accessibility to the main control room during normal operation is unlimited, with sufficient shielding provided to ensure that normal radiation levels are below 0.3 mrem/hr. In addition to its function during normal operation, the main control room shielding reduces direct radiation doses from the LOCA to levels that permit controlled occupancy by operating personnel following that accident.

6.4-3 REV 24 11/22

FERMI 2 UFSAR Control center shielding is ordinary concrete. The actual floor of the main control room is 1 ft thick but, as a result of other structures, it has an effective thickness of 8 ft 4 in.; the outside (north) wall is 2 ft thick; the roof of the main control room is 5 ft thick over one portion and 1 ft thick over the remaining portion, with the total effective concrete thickness over the main control room varying, however, between 6 ft 6 in. and 10 ft 6 in.; the wall facing the reactor is 4 ft 4 in. thick, with an additional 7 ft of concrete biological shielding surrounding the reactor.

Section 12.1 includes a layout drawing of the control center, as well as a scaled isometric view of the main control room and its associated shielding. Section 12.1 also presents detailed descriptions of shield thicknesses, justifications for the thicknesses of shielding provided, descriptions of the geometric and physical models used, and information relative to the assumptions and data used in the design.

6.4.2.2 Radiation Monitoring System The functional design of the radiation monitoring system (RMS) provides adequate and reliable radiological data for the evaluation of habitability of the main control room.

The outputs from area and process radiation monitors associated with main control room habitability are displayed, alarmed, and recorded, if necessary, in the main control room.

The area radiation monitor provides measurements of dose rates in the main control room.

Location and the design criteria used in their selection are described in Subsection 12.1.4 along with operational characteristics, including type of detector, sensitivity, range, method of calibration, and setpoints.

Process monitors continuously monitor the levels of radioactivity in main control room ventilation systems. Inlet makeup air is monitored upstream of the filters in the emergency air makeup and recirculation systems. Airborne radioactivity monitoring is described in Subsection 12.2.4, which gives the locations and design criteria of the fixed instruments, as well as the criteria used to determine the necessity for and the location of the equipment.

That section also provides information on the operational characteristics of the monitors, the detector type, the sensitivities, the ranges, and setpoints and their bases.

Personnel dosimetry under normal and under accident conditions is described in detail in Subsection 12.3.4.

6.4.2.3 Air Conditioning System 6.4.2.3.1 System Description The control center air conditioning system (CCACS) is described in Section 9.4, which includes system, water control, and airflow diagrams.

The air conditioning system provides year-round comfort and safety from airborne radioactivity for control center personnel. The individual components of the Category I system are designed for an operational life of 40 years, accounting for corrosion and material fatigue. Electrical power for motor operation is supplied from the reactor building 6.4-4 REV 24 11/22

FERMI 2 UFSAR engineered safety feature (ESF) buses, maintaining separation and redundancy, and common-mode failure is prevented by physical separation.

The system is capable of maintaining the control center at a nominal temperature of 75°F and at a maximum relative humidity of 60 percent during normal operation, except for the mechanical equipment room (MER) and SGTS room which are discussed in Subsection 9.4.1.1. Noise level in the main control room, when measured in accordance with Appendix E1 of NUREG-0700, Guidelines for Control Room Design Reviews, does not exceed 65 dB(A). The noise level in the washroom and kitchen, on the same measurement basis, also does not exceed 65 dB(A). Conditioned air is supplied directly to the main control room, while the kitchen and washroom are conditioned by exhausting air that is drawn from the main control room.

There are four operating modes for the CCACS as follows:

a. Normal mode: A minimum of 2769 cfm outside air mixes with recirculated ventilating air, bypassing the emergency makeup and recirculation filters

b. Purge mode: 100 percent outside air is circulated through the control center and exhausted to the atmosphere to purge any smoke or fumes within the control center

c. Recirculation mode: A maximum of 1800 cfm outside air is filtered and mixes with 1200 cfm recirculated air; it is filtered again and mixed with recirculating ventilation air to prevent intrusion and to provide continuous removal of contaminants during a radiation-release emergency

d. Chlorine mode: All outside intakes are closed to prevent ingress during a chlorine-release emergency. Ventilating air is recirculated with 1200 cfm passing through the emergency recirculation filter.

Normal Operation Mode During normal operation, the control center air conditioning system serves the main control room and several other areas. The supply airflow to the control center is 31,510 cfm and the return airflow is 30,440 cfm. Normal makeup air is passed through an electronic air cleaner and a roll-type filter.

The master selector switches in the main control room activate all components in the Division I or Division II system. The mixture of return and outside air is filtered, then cooled, heated, and dehumidified, as required, by a multizone air conditioning supply unit.

Each zone thermostat modulates zone mixing dampers to obtain the supply-air temperature necessary to satisfy the zone cooling or heating requirements. Positive pressure is maintained in the control center by throttling the exhaust air-modulating damper. Exhaust fans are provided in the kitchen and washrooms.

Manual override is provided such that an operator in the main control room is able to select the purge mode, which opens the outside air dampers and closes the return air dampers.

Recirculation Mode Upon an automatic isolation signal from the reactor protection system or the RMS, the CCACS is automatically transferred to the recirculation mode. Under emergency conditions, 6.4-5 REV 24 11/22

FERMI 2 UFSAR airflow rate into the control center is 31,510 cfm including 1800 cfm maximum makeup air to offset supply air lost through room leakage (maintaining the control center positive pressure of 1/4 +/- 1/8-in. water gage). The kitchen and washroom individual exhaust ducts each contain dual isolation valves that are closed under emergency conditions.

During an emergency, the control center is isolated from all other areas of the plant. All air supplies to the standby gas treatment rooms and the normal operation of air intake and exhaust ducts are dampered closed.

The multizone air-handling unit, the chiller, chilled water pump and the return air fan continue to operate as during normal operation. The return air damper assumes a full-open position. Cooling water is supplied from the emergency equipment cooling water (EECW) system. The fan in the mechanical equipment room fan-coil cooling unit is also energized under room thermostat control. Chilled- water flow through the cooling coil of the unit continues unimpeded as during normal operation.

The emergency recirculation air fan is energized and the dampers on the emergency intake air duct are opened and the kitchen and washrooms exhaust fans are deactivated.

The emergency recirculation air filter train consists of a prefilter, a high-efficiency particulate air (HEPA) filter, a charcoal filter, another HEPA filter, and redundant fans. The emergency makeup air filter train consists of a filtering-type demister, two electric heaters, a HEPA filter, a charcoal filter, and another HEPA filter. Detailed descriptions of the filter trains are presented in Subsection 9.4.1, with summary descriptions of the train components given below:

a. The demister removes entrained water droplets and serves as a prefilter for the downstream HEPA filter. The demister meets design requirements specified in Savannah River Laboratory Report DP-812

b. The electric heater reduces the relative humidity of influent air under worst conditions to 70 percent or less

c. The HEPA filters have a design DOP filtration efficiency of 99.97 percent for particles 0.3 µm in diameter or larger. The elements meet the requirements of ANSI N509-1980. They are UL-approved fire resistant and suitable for service under the temperatures and mass peak loadings expected. The filters are installed and field tested such that a 95 percent decontamination efficiency can be assumed for removal of particulate iodine.

d. The charcoal adsorber in the emergency makeup air filter train is a deep-bed unit, as is that in the recirculation air filter train. These units contain impregnated activated carbon. Representative samples of the carbon are lab tested prior to installation and periodically while in service to demonstrate that the carbon is 99 percent efficient in removing methyl iodide. The carbon is installed and field tested for by-pass leakage such that a 95 percent decontamination efficiency can be assumed for removal of all forms of gaseous iodine.

e. Downstream HEPA filters are identical to the upstream HEPA units and serve to trap charcoal fines and decay daughters entrained in the air stream.

6.4-6 REV 24 11/22

FERMI 2 UFSAR The CCACS design provides redundant alarms for main control room high/low pressure to ensure that a positive pressure in the main control room is maintained at all times.

Additionally, alarms are provided in the control room to alert operators for large pressure drops across the CCHVAC emergency make-up and recirculation filters indicating the filter airflow is degrading.

Chlorine Mode In the event that chlorine gas is detected, control room personnel will place CCHVAC in the chlorine mode, whereupon the normal intake and discharge isolation dampers would close and the emergency intake isolation dampers would remain closed; all other dampers and equipment would function as described in the recirculation mode. In this mode, airflow is circulated throughout the control center at the emergency flow rate, but the outside air intake and exhaust ducts are closed by dampers.

For all operating modes, damper position indications in the main control room allow continuous monitoring of the system performance and confirm all remote manual control actions taken.

Purge Mode The air conditioning system has a smoke purge mode. In this mode, fresh air is brought into the main control room and no air is recirculated. This mode is initiated automatically when the gaseous fire suppression system actuates, or it can be initiated manually by the operator.

Ionization-type smoke detectors provide an alarm indicating conditions that require isolation of the control center.

For heat and smoke removal from the control center complex in the event of a fire in any of the air-conditioning zones, the fire- detection system will activate alarms in the control center. The control room operator can remote manually initiate the purge mode.

6.4.2.3.2 Control Center Air Intakes The control center air conditioning system consists of two 100 percent-capacity air-conditioning supply units, an air- distribution system, and an emergency filtration system.

The control center is heated, cooled, and pressurized by a recirculating air system. Figures 9.4-1 and 9.4-2 show the ventilating air circulating flow path, rates, and dampers and their positions for the different operating modes. The emergency filtration system processes control center recirculated air and makeup air through charcoal filters if the control center is subjected to airborne radioactive contamination. This system consists of two separate emergency air intakes. The intake that draws from the area having the lowest level of contamination is manually selected for operation.

The physical orientation between the normal and emergency intake openings and the potential source points of radiation are described in Section 2.3.4.2.4.

Each emergency intake has two parallel paths containing redundant dampers. One path in each intake contains two Division I isolation dampers and one Division I modulating damper, which maintains the control center at approximately 1/4 +/- 1/8-in. water gage positive pressure in the recirculation mode. The other path contains identical dampers powered by Division II.

6.4-7 REV 24 11/22

FERMI 2 UFSAR For normal operation, a separate normal intake supply is used, allowing the makeup and emergency filters to remain on standby with full filtering capacity available for emergencies.

Two air- operated isolation dampers are provided on the normal air intake duct and on the system exhaust vent. One damper in each duct is designated as a Division I damper; the other damper in each duct is designated as a Division II damper. Each damper will close within 5 sec after an isolation signal is initiated and is designed to achieve "bubble-tight" full shutoff.

Two return air fans are provided and each fan is sized to return 95 percent of the total air supplied to the control center. One fan is for Division I and the other for Division II. In the normal mode, the exhaust air damper is modulated to maintain approximately 1/4 +/- 1/8 in. of water difference between the lower of the outside ambient pressure or the turbine building pressure and the control center pressure when the system is in the normal operating mode.

6.4.2.4 Fire Protection System The fire protection system is described in detail in Subsection 9.5.l. Portable fire extinguishers are provided at strategic locations in the main control room. High-sensitivity, ionization-type detectors for combustion products are located in the ceiling space. The fire protection system and specific construction materials are identified in the fire hazards analysis referenced in Subsection 9.5.1.

6.4.2.5 Personnel Protective Equipment and First Aid and Emergency Supplies Operator respiratory protection in the main control room consists of a mask-hose apparatus connected to a bottled air supply. The supply is 3600 ft3, which is adequate for 30 manhours of heavy work, with a 20 percent contingency. The size of the supply is based on the data supplied in Reference 3. This handbook indicates that an adult man performing heavy work requires 39.3 to 45.2 liters of air per minute. The size of the supply is based on the larger of these figures.

The supply consists of a rack outside the main control room containing 12 air cylinders (300-ft3) connected to a manifold. This supply is piped to a five connection manifold in the main control room. Located at the manifold are five individual dual purpose airline/self-contained breathing apparatus (SCBA) respirator units with a length of hose adequate to permit operator movement throughout the main control room area.

The dual purpose airline/SCBA respirator may be attached to either the emergency air system via the manifold, or function independently via the on-board air supply. This provides the operators the capability to move about, and exit the main control room. Two spare bottles per SCBA are also maintained adjacent to the main control room. These units are of the type tested and approved by the Bureau of Mines and by the National Institute for Occupational Safety and Health (NIOSH), and supply fresh air for a period of approximately 20 minutes.

Possible first aid needs are met by a kit in the main control room.

A five-man-day supply of food is stored in the main control center complex and can be used for an emergency. In addition, sufficient potable water is reserved to provide a five-man-day supply during an emergency. Under the conditions that would exist in the event of long-6.4-8 REV 24 11/22

FERMI 2 UFSAR duration accidents, the main control room is accessible for shift changes so that additional food and water can be brought to the main control room.

6.4.2.6 Utilities and Sanitation The plant communications system is described in Subsection 9.5.2. This diverse system, which includes telephones, portable two-way radios, an intercom system, and a public address system, provides assurance that there is a means of communication between the main control room and plant or offsite areas.

Subsection 9.5.3 contains a description of the normal lighting system and the emergency lighting system. The design criteria and failure analysis ensure that these systems, in conjunction with the power supply system (Section 8.3), will provide adequate lighting for the main control room.

The kitchen area of the main control room contains an electric range, a refrigerator, a water heater, and cooking and eating utensils. The main control room washroom contains toilets, washing facilities, housekeeping supplies, and waste containers.

6.4.3 Design Evaluation Operating systems that serve to ensure main control room habitability are discussed in detail in the following sections and subsections.

a. Control center air conditioning system - 9.4.l

b. Fire protection system - 9.5.l

c. Communications system - 9.5.2

d. Lighting system - 9.5.3

e. Onsite power systems - 8.3

f. Radiation monitoring systems - 12.1.4 and 12.2.4.

As the referenced sections and subsections state, the systems or portions of systems essential for main control room habitability meet the seismic, the component redundancy, and the power-supply redundancy requirements that ensure satisfactory performance under normal and accident conditions.

Summary evaluations of the designs of the systems that contribute to main control room habitability are provided in the following subsections.

6.4.3.1 Radiation Monitoring System The design of the radiation monitoring equipment essential for main control room habitability meets all of the functional requirements given in Subsection 6.4.2.2. The monitor locations, types, sensitivities, ranges, and setpoints ensure that necessary information is available to main control room personnel and that those main control room habitability systems, which are actuated automatically, will receive initiation signals.

6.4-9 REV 24 11/22

FERMI 2 UFSAR The portable radiation monitoring equipment applicable to main control room habitability is readily available as required. The equipment is described in Subsection 12.3.2, and personnel dosimetry is discussed in Subsection 12.3.4.

6.4.3.2 Air Conditioning System - Control of Main Control Center Thermal Environment The CCACS is operated on a continuous basis to maintain a safe and comfortable thermal environment in the main control room. The state of readiness of this system is indicated by the system performance, as reflected in the main control room temperature and relative humidity. With the exception of the common ductwork and filters, the system has 100 percent backup and meets single- failure criteria. The smoke/Halon dampers to the relay room, cable spreading room or computer room will close due to a single active failure in the Halon fire protection system. Sufficient time is available to take manual action to reestablish airflow. The air conditioning system emergency mode and all essential components are designed to Category I requirements.

The air-conditioning functions provided include cooling, heating, humidification, air filtration, forced air circulation, exhaust, and positive pressure control. In normal operation, air filtration is provided by an electronic air cleaner and a fiberglass media roll filter. After the mixture of return and outside air is filtered, it is cooled and heated by the multizone air-handling unit.

The air conditioning system, sized in accordance with ASHRAE recommendations, is designed for an ambient temperature of 95°F dry bulb and 75°F wet bulb during summer operation and -10°F dry bulb for winter operation. The ambient temperature range specified prevails 99 percent, or more, of the total time at the plant location.

The total system flow is 31,510 cfm, of which 11,350 cfm is supplied directly to the main control room. The supply of conditioned air ensures that the thermal environment within the main control room permits habitation under any weather or plant conditions.

6.4.3.3 Air Conditioning System - Control of Main Control Room Airborne Radioactivity During an emergency, the control center is isolated from all other areas of the plant. All air supply to the standby gas treatment rooms and the normal-operation air intake and exhaust ducts are dampered or valved closed. The multizone air-handling unit and the return air fan continue to operate as during normal operation, with the emergency air-handling system placed in operation by automatic or manual opening of the emergency air intake dampers and energizing the emergency recirculation air fan.

The 1800 cfm maximum emergency outside air required for pressurization and personnel physiology is drawn through the emergency outside air intake filter train. A mixture of filtered outside air and the emergency recirculation air is passed through the emergency recirculation filter train. The kitchen and washroom exhaust air ducts will be closed during emergency operation.

Airborne and fuel pool radioactivity levels in the reactor/ auxiliary building ventilation and exhaust air ducts are monitored. If the activity exceeds acceptable levels, isolation dampers or valves in the control center normal intake and exhaust air ducts and in the air conditioning equipment and standby gas treatment system (SGTS) room air ducts are actuated, placing the 6.4-10 REV 24 11/22

FERMI 2 UFSAR control center air conditioning system in an emergency recirculation mode. In this mode, air is brought in through the emergency makeup air filter train (1800 cfm maximum), mixed with 1200 cfm minimum recirculated air, and put through a 3000 cfm recirculation filter train.

Redundant and separate isolation dampers or valves are installed in all ducts of the air conditioning system that affect the isolation of the main control room from other building areas; the emergency intake air duct and the kitchen and washroom exhaust air ducts are also equipped with redundant isolation dampers.

The system design, the isolation capabilities, and the efficiencies of the components used in the emergency filter trains ensure that airborne radioactivity in the main control room does not rise to levels that prohibit habitability.

6.4.3.4 Air Conditioning System - Control of Main Control Room Chemical Environment Adverse chemical effects on the main control room environment could result from the following three events:

a. A chlorine accident off the plant site

b. A fire outside the main control room

c. A fire inside the main control room There are shipments of hazardous chemicals by rail and road routes within a 5-mile radius of the plant. The closest transportation line lies about 3.5 miles from the plant. At this distance, a release of a hazardous chemical is not a threat to Fermi 2 control room habitability. In accordance with the provisions of Regulatory Guide 1.78, Revision 1, control center habitability was analyzed for the rupture of a 90-ton chlorine railroad tankcar.

It was determined that the probability of a chlorine railcar accident and a spill resulting in a control room toxic concentration meets the Regulatory Guide criterion for not considering such scenario to be a credible event (Reference 6).

The CCACS ensures that the toxic or noxious substances that might result from one of the above events do not prevent occupancy of the main control room.

Upon manual initiation of chlorine mode, the (100 percent recirculation) chlorine mode of operation of the air conditioning system commences; in this configuration, there is no makeup airflow and approximately 1200 cfm of the main control room airflow is passed through the recirculation air filter train for cleanup.

The safety of main control room operators is further ensured by the provision of self-contained breathing apparatus units in the main control room, as described in Subsection 6.4.2.5. Storage provisions for the breathing apparatus and procedures for use permit operators to don appropriate respirators upon detection of toxic gases or chlorine odors. The emergency plan includes instructions for immediate donning of breathing apparatus on detection of chlorine release, and the training of main control room personnel includes rehearsal and the procedures necessary for rapid utilization of the equipment.

6.4-11 REV 24 11/22

FERMI 2 UFSAR A fire-detection system is provided throughout the control center. The system consists of ionization or photoelectric detectors for alarming the presence of smoke or for actuating the automatic gaseous fire-suppression systems where provided.

In the chlorine mode, introduction of smoke and/or noxious fumes from outside fires into the main control room is prevented; in the unlikely event of a UL Class A fire inside the main control room, the smoke purge system is used to remove the products of the fire from the main control room.

For smoke purging, the normal air conditioning system can be operated on a zero-recirculation basis, with a greatly increased outside air intake. As the zero-recirculation terminology implies, airflow in the control center areas is on a once-through basis.

In summary, the CCACS is highly flexible, providing modes of operation that ensure acceptable air quality.

6.4.3.5 Fire Protection A description of the fire protection system for the main control room is identified in Subsection 9.5.1.

6.4.3.6 Personnel Protection Self-contained breathing apparatus is provided for emergency use in the main control room.

The apparatus is selected according to the guidelines of ANSI Z88.2 (Reference 4). A respiratory protective program meeting the requirements of Occupational Safety and Health Administration (OSHA) 1910.134 (Reference 5) has been established and will be maintained, thereby ensuring the effectiveness of the provisions for personnel protection.

6.4.3.7 Utilities and Sanitation Several communications channels are maintained open under all conditions. Most of the communications systems are in routine use. Those systems not frequently used are subjected to periodic maintenance and testing to ensure their state of readiness. The provision of diverse and redundant systems ensures a reliable communications capability.

Lighting is provided in the main control room at all times. The installation of normal and emergency systems, with power-source redundancy, ensures that the main control room is adequately illuminated. The normal lighting system is proven operable during regular operating periods and will continue to operate under most accident conditions; in the event that the normal system is inoperative, the emergency system provides illumination.

Kitchen and sanitary facilities are proven operable under normal conditions and will continue to function under accident conditions.

6.4.4 Testing and Inspection 6.4-12 REV 24 11/22

FERMI 2 UFSAR 6.4.4.1 Radiation Monitoring System Testing and inspection of the RMS ensure that each functional requirement of the system is met. The RMS is tested in conjunction with the CCACS to ensure that the monitors perform the desired functions.

The area and process radiation monitors are readily accessible for testing, inspection, and calibration. The testing of the monitors does not interfere with normal operation of the habitability systems for the main control room. Portable equipment such as air samplers, personnel dosimeters, and other radiation analysis equipment applicable to main control room habitability is tested and inspected periodically as required.

Specific details of the measures taken to ensure the operability of radiation monitoring equipment are given in Subsections 12.1.4, 12.2.4, and 12.3.4.

6.4.4.2 Control Center Air Conditioning System The CCACS is subjected to those tests and inspections required to ensure its capability to perform its designed functions throughout the lifetime of the plant. As indicated in the preceding subsection, those portions of the system that interact directly with other systems are subjected to testing concurrent with the other systems.

The system and its components are tested in accordance with the codes and standards to which they are designed, and with the tests and inspections specified in Section 9.4, the Technical Specifications, and the Technical Requirements Manual. The compliance of the emergency makeup air and emergency recirculation filter trains and their components with Regulatory Guide 1.52 is described in Subsection A.1.52. Testing of the filter trains and their components involves

a. Predelivery and component qualification tests

b. Onsite preoperational acceptance tests

c. Operational surveillance tests The quantity of air supplied for pressurization of the control center is determined by performing a duct traverse measurement at the installed test ports in the ductwork. The static pressure differential in the control center complex is measured to verify that a pressure of 1/4 +/- 1/8-in. water gage is maintained by the CCACS operating in the emergency mode.

Should a component or material in the CCACS fail to meet the required level of performance, the component or material is replaced. Should the system fail to meet performance standards in any mode of operation, the component(s) adversely affecting the system performance is replaced. The modes of operation considered for the main control room are normal mode, recirculation mode (radiation emergency), chlorine mode (complete isolation), and purge mode (smoke removal with zero recirculation).

6.4.4.3 Main Control Room Fire Protection System Fire protection for the main control room is ensured by fire extinguishers inside the main control room, fire-detection equipment, the smoke purge capability of the CCACS, and the 6.4-13 REV 24 11/22

FERMI 2 UFSAR isolation provisions of that system. Inspection and testing requirements are provided in Subsection 9.5.1.

6.4.4.4 Other Control Center Habitability Systems Self-contained breathing apparatus is inspected to ensure that pressures are at least equal to those required to supply air for the minimum acceptable breathing period. If cylinder pressure is insufficient, the cylinder is recharged or replaced. Regulators in the air packs are periodically inspected to verify operability; units that do not function properly are repaired or replaced.

The communications and lighting systems are proven operable, in part, by normal use, with backup or emergency facilities tested periodically by individual tests or intentional disabling of the primary system.

Kitchen and sanitation facilities are known to be operable through normal use.

6.4.5 Instrumentation The individual system design sections of the UFSAR contain descriptions of the instrumentation used for monitoring and actuating those portions of the systems vital to main control room habitability. Design details and logic of the instrumentation are discussed in Chapter 7.

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FERMI 2 UFSAR 6.4 HABITABILITY SYSTEMS REFERENCES

1. Report of ICRP Committee II on Permissible Dose for Internal Radiation (1959),

Health Physics Journal, Vol. 3 (June 1960).

2. American Society of Heating, Refrigerating and Air- Conditioning Engineers (ASHRAE), 55-66, Standard on Thermal Comfort Conditions.

3. P. L. Altman, J. F. Gibson, and C. C. Wang, Handbook of Respiration, W. B.

Saunders Company, 1958.

4. American National Standards Institute, ANSI F88.2-1969, Respiratory Protection.

5. Occupational Safety and Health Administration, Title 29, Part 1910.134, Respiratory Protection.

6. License Amendment No. 147, Elimination of the Chlorine Detection Function from the Control Center Heating, Ventilation and Air Conditioning System, dated June 26, 2002.

6.4-15 REV 24 11/22

Figure Intentionally Removed Refer to Plant Drawing A-2100 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 6.4-1 PLOT PLAN - GRADE ELEVATION 583 FT REV 22 04/19